USD Partners LP - Quarter Report: 2019 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended September 30, 2019



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

For the transition period from to

Commission file number 001-36674

USD PARTNERS LP

(Exact Name of Registrant as Specified in Its Charter)



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

811 Main Street, Suite 2800

Houston, Texas 77002

(Address of Principal Executive Offices) (Zip Code)

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

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



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

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

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

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



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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES ¨ NO x

As of November 1, 2019 there were 24,411,514 common units, 2,092,709 subordinated units and 461,136 general partner units outstanding.

TABLE OF CONTENTS



PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Statements of Income	1
	Consolidated Statements of Comprehensive Income	2
	Consolidated Statements of Cash Flows	3
	Consolidated Balance Sheets	4
	Consolidated Statements of Partners’ Capital	5
	Notes to the Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	59
Item 4.	Controls and Procedures	59
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	61
Item 1A.	Risk Factors	61
Item 6.	Exhibits	61
SIGNATURES		63

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

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

Cautionary Note Regarding Forward-Looking Statements

This Report includes forward-looking statements, which are statements that frequently use words such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,” “position,” “projection,” “should,” “strategy,” “target,” “will” and similar words. Although we believe that such forward-looking statements are reasonable based on currently available information, such statements involve risks, uncertainties and assumptions and are not guarantees of performance. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Any forward-looking statement made by us in this Report speaks only as of the date on which it is made, and we undertake no obligation to publicly update any forward-looking statement. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include: (1) changes in general economic conditions; (2) the effects of competition, in particular, by pipelines and other terminalling facilities; (3) shut-downs or cutbacks at upstream production facilities, refineries or other related businesses; (4) the supply of, and demand for, terminalling services for crude oil and biofuels; (5) the price and availability of debt and equity financing; (6) actions by third parties, including customers, lenders and our sponsors; (7) hazards and operating risks that may not be covered fully by insurance; (8) disruptions due to equipment interruption or failure at our facilities or third-party facilities on which our business is dependent; (9) natural disasters, weather-related delays, casualty losses and other matters beyond our control; (10) changes in laws or regulations to which we are subject, including compliance with environmental and operational safety regulations, that may increase our costs; and (11) our ability to successfully identify and finance acquisitions and other growth opportunities. For additional factors that may affect our results, see “Risk Factors” and the other information included elsewhere in this Report and our Annual Report on Form 10-K for the fiscal year ended December 31, 2018, which is available to the public over the Internet at the website of the U.S. Securities and Exchange Commission, or SEC, (www.sec.gov) and at our website (www.usdpartners.com).

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

USD PARTNERS LP

CONSOLIDATED STATEMENTS OF INCOME



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(unaudited; in thousands of US dollars, except per unit amounts)
Revenues
Terminalling services	$	23,709		$	22,070		$	63,437		$	66,586
Terminalling services — related party	4,459			5,715			15,622			15,414
Fleet leases — related party	984			984			2,951			2,951
Fleet services	50			80			158			505
Fleet services — related party	227			227			682			682
Freight and other reimbursables	272			510			973			2,754
Freight and other reimbursables — related party	193			—			254			4
Total revenues	29,894			29,586			84,077			88,896
Operating costs
Subcontracted rail services	3,689			3,674			10,953			10,047
Pipeline fees	5,411			5,267			15,374			16,109
Freight and other reimbursables	465			510			1,227			2,758
Operating and maintenance	2,481			2,686			8,202			7,540
Operating and maintenance — related party	2,471			—			2,471			—
Selling, general and administrative	2,940			2,463			8,139			7,912
Selling, general and administrative — related party	1,406			1,893			6,081			5,640
Depreciation and amortization	5,300			5,271			15,317			15,807
Total operating costs	24,163			21,764			67,764			65,813
Operating income	5,731			7,822			16,313			23,083
Interest expense	3,005			2,827			9,174			8,025
Loss (gain) associated with derivative instruments	220			(413		)	1,966			(1,823		)
Foreign currency transaction loss (gain)	35			(89		)	237			(183		)
Other expense (income), net	(49		)	(1		)	(52		)	71
Income before income taxes	2,520			5,498			4,988			16,993
Provision for (benefit from) income taxes	414			(430		)	612			(2,247		)
Net income	$	2,106		$	5,928		$	4,376		$	19,240
Net income attributable to limited partner interests	$	1,888		$	5,719		$	3,817		$	18,616
Net income per common unit (basic and diluted)	$	0.08		$	0.21		$	0.15		$	0.72
Weighted average common units outstanding	24,411			21,915			23,965			21,480
Net income per subordinated unit (basic and diluted)	$	0.08		$	0.21		$	0.13		$	0.71
Weighted average subordinated units outstanding	2,093			4,185			2,476			4,569

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,
	2019			2018		2019		2018
	(unaudited; in thousands of US dollars)
Net income	$	2,106		$	5,928	$	4,376	$	19,240
Other comprehensive income (loss) — foreign currency translation	(652		)	997		1,903		(1,791		)
Comprehensive income	$	1,454		$	6,925	$	6,279	$	17,449

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,
	2019			2018
	(unaudited; in thousands of US dollars)
Cash flows from operating activities:
Net income	$	4,376		$	19,240
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	15,317			15,807
Loss (gain) associated with derivative instruments	1,966			(1,823		)
Settlement of derivative contracts	1			(38		)
Unit based compensation expense	4,533			4,333
Deferred income taxes	(299		)	(3,269		)
Other	915			719
Changes in operating assets and liabilities:
Accounts receivable	1,511			(3,459		)
Accounts receivable — related party	(1,054		)	2,450
Prepaid expenses and other assets	72			372
Other assets — related party	(329		)	59
Accounts payable and accrued expenses	(411		)	272
Accounts payable and accrued expenses — related party	2,429			(2,061		)
Deferred revenue and other liabilities	5,590			(403		)
Deferred revenue — related party	(462		)	17
Net cash provided by operating activities	34,155			32,216
Cash flows from investing activities:
Additions of property and equipment	(7,072		)	(443		)
Proceeds from the sale of assets	—			236
Net cash used in investing activities	(7,072		)	(207		)
Cash flows from financing activities:
Distributions	(30,994		)	(29,573		)
Payments for deferred financing costs	(7		)	—
Vested phantom units used for payment of participant taxes	(1,826		)	(1,350		)
Proceeds from long-term debt	28,000			20,000
Repayments of long-term debt	(21,000		)	(21,000		)
Other financing activities	(13		)	—
Net cash used in financing activities	(25,840		)	(31,923		)
Effect of exchange rates on cash	497			(679		)
Net change in cash, cash equivalents and restricted cash	1,740			(593		)
Cash, cash equivalents and restricted cash — beginning of period	12,383			13,788
Cash, cash equivalents and restricted cash — end of period	$	14,123		$	13,195

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

USD PARTNERS LP

CONSOLIDATED BALANCE SHEETS



	September 30, 2019			December 31, 2018
	(unaudited; in thousands of US dollars, except unit amounts)
ASSETS
Current assets
Cash and cash equivalents	$	6,479		$	6,439
Restricted cash	7,644			5,944
Accounts receivable, net	3,653			5,132
Accounts receivable — related party	1,689			624
Prepaid expenses	1,435			2,115
Other current assets	404			634
Other current assets — related party	468			79
Total current assets	21,772			20,967
Property and equipment, net	148,544			145,308
Intangible assets, net	77,250			86,705
Goodwill	33,589			33,589
Operating lease right-of-use assets	13,083			—
Other non-current assets	764			631
Other non-current assets — related party	35			95
Total assets	$	295,037		$	287,295

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable and accrued expenses	$	4,120		$	3,464
Accounts payable and accrued expenses — related party	2,899			460
Deferred revenue	6,016			2,921
Deferred revenue — related party	1,464			1,885
Operating lease liabilities, current	5,075			—
Other current liabilities	3,765			2,804
Total current liabilities	23,339			11,534
Long-term debt, net	213,444			205,581
Deferred income tax liabilities, net	70			360
Operating lease liabilities, non-current	8,275			—
Other non-current liabilities	2,828			356
Total liabilities	247,956			217,831
Commitments and contingencies
Partners’ capital
Common units (24,411,280 and 21,916,024 outstanding at September 30, 2019 and December 31, 2018, respectively)	67,240			107,903
Class A units (38,750 outstanding at December 31, 2018)	—			1,018
Subordinated units (2,092,709 and 4,185,418 outstanding at September 30, 2019 and December 31, 2018, respectively)	(21,941		)	(39,723		)
General partner units (461,136 outstanding at September 30, 2019 and December 31, 2018)	2,888			3,275
Accumulated other comprehensive loss	(1,106		)	(3,009		)
Total partners’ capital	47,081			69,464
Total liabilities and partners’ capital	$	295,037		$	287,295

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

USD PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL



	Three Months Ended September 30,
	2019				2018
	Units	Amount			Units	Amount
	(unaudited; in thousands of US dollars, except unit amounts)
Common units
Beginning balance at July 1,	24,410,226	$	73,424		21,914,224	$	114,822
Conversion of units	—	—			—	—
Common units issued for vested phantom units	1,054	(5		)	1,135	(4		)
Net income	—	1,739			—	4,794
Unit based compensation expense	—	1,421			—	1,313
Distributions	—	(9,339		)	—	(8,143		)
Ending balance at September 30,	24,411,280	67,240			21,915,359	112,782
Class A units
Beginning balance at July 1,	—	—			38,750	950
Conversion of units	—	—			—	—
Net income	—	—			—	9
Unit based compensation expense	—	—			—	43
Forfeited units	—	—			—	—
Distributions	—	—			—	(15		)
Ending balance at September 30,	—	—			38,750	987
Subordinated units
Beginning balance at July 1,	2,092,709	(21,290		)	4,185,418	(37,797		)
Conversion of units	—	—			—	—
Net income	—	149			—	916
Unit based compensation expense	—	—			—	—
Distributions	—	(800		)	—	(1,555		)
Ending balance at September 30,	2,092,709	(21,941		)	4,185,418	(38,436		)
General Partner units
Beginning balance at July 1,	461,136	3,008			461,136	95
Capital contribution	—	—			—	3,366
Net income	—	218			—	209
Unit based compensation expense	—	—			—	—
Distributions	—	(338		)	—	(267		)
Ending balance at September 30,	461,136	2,888			461,136	3,403
Accumulated other comprehensive income (loss)
Beginning balance at July 1,		(454		)		(954		)
Cumulative translation adjustment		(652		)		997
Ending balance at September 30,		(1,106		)		43
Total partners’ capital at September 30,		$	47,081			$	78,779

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,
	2019					2018
	Units		Amount			Units		Amount
	(unaudited; in thousands of US dollars, except unit amounts)
Common units
Beginning balance at January 1,	21,916,024		$	107,903		19,537,971		$	136,645
Conversion of units	2,131,459		(19,631		)	2,131,459		(18,245		)
Common units issued for vested phantom units	363,797		(1,826		)	245,929		(1,350		)
Net income	—		3,506			—		15,337
Unit based compensation expense	—		4,154			—		3,753
Distributions	—		(26,866		)	—		(23,358		)
Ending balance at September 30,	24,411,280		67,240			21,915,359		112,782
Class A units
Beginning balance at January 1,	38,750		1,018			82,500		1,468
Conversion of units	(38,750	)	(1,018		)	(38,750	)	(674		)
Net income	—		—			—		33
Unit based compensation expense	—		14			—		144
Forfeited units	—		—			(5,000	)	73
Distributions	—		(14		)	—		(57		)
Ending balance at September 30,	—		—			38,750		987
Subordinated units
Beginning balance at January 1,	4,185,418		(39,723		)	6,278,127		(55,237		)
Conversion of units	(2,092,709	)	20,637			(2,092,709	)	18,919
Net income	—		311			—		3,246
Unit based compensation expense	—		2			—		26
Distributions	—		(3,168		)	—		(5,390		)
Ending balance at September 30,	2,092,709		(21,941		)	4,185,418		(38,436		)
General Partner units
Beginning balance at January 1,	461,136		3,275			461,136		180
Capital contribution	—		—			—		3,366
Net income	—		559			—		624
Unit based compensation expense	—		—			—		1
Distributions	—		(946		)	—		(768		)
Ending balance at September 30,	461,136		2,888			461,136		3,403
Accumulated other comprehensive income (loss)
Beginning balance at January 1,			(3,009		)			1,834
Cumulative translation adjustment			1,903					(1,791		)
Ending balance at September 30,			(1,106		)			43
Total partners’ capital at September 30,			$	47,081				$	78,779

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

USD PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. ORGANIZATION AND BASIS OF PRESENTATION

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

Basis of Presentation

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

Foreign Currency Translation

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

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

US Development Group, LLC

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

Comparative Amounts

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

We adopted the provisions of ASC 842 Leases on January 1, 2019. We elected to implement the provisions of the new standard to our existing leases by recognizing and measuring lease assets and liabilities on our balance sheet as of January 1, 2019, as well as any cumulative-effect adjustment to the opening balance of Partners’ Capital. Refer to Note 2. Recent Accounting Pronouncements and Note 7. Leases for further discussion.

2. RECENT ACCOUNTING PROUNOUNCEMENTS

Recently Adopted Accounting Pronouncements

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

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

Leases (ASC 842)

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

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

We determine the classification of our leases as operating, financing or sales-type leases based on the criteria set forth in ASC 842 that considers whether a lease is economically similar to the purchase of a nonfinancial asset. We have adopted as our accounting policy the definition of “substantially all” of the fair value of the underlying asset to

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

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

Lessee Accounting

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

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

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

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

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

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

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

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

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

Lessor Accounting

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

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

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

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

Refer to Note 7. Leases for further discussion.

Recent Accounting Pronouncements Not Yet Adopted

Intangibles - Goodwill and Other

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

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

3. NET INCOME PER LIMITED PARTNER INTEREST

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



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


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

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



	For the Three Months Ended September 30, 2019
	Common Units			Subordinated Units			Class A Units ⁽⁷⁾		General Partner Units			Total
	(in thousands, except per unit amounts)
Net income attributable to general and limited partner interests in USD Partners LP ⁽¹⁾	$	1,739		$	149		$	—	$	218		$	2,106
Less: Distributable earnings ⁽²⁾	9,400			806			—		359			10,565
Distributions in excess of earnings	$	(7,661	)	$	(657	)	$	—	$	(141	)	$	(8,459	)
Weighted average units outstanding ⁽³⁾	24,411			2,093			—		461			26,965
Distributable earnings per unit ⁽⁴⁾	$	0.39		$	0.39		$	—
Overdistributed earnings per unit ⁽⁵⁾	(0.31		)	(0.31		)	—
Net income per limited partner unit (basic and diluted)⁽⁶⁾	$	0.08		$	0.08		$	—


⁽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 $181 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 $0.3675 per unit, or $1.47 per unit on an annualized basis. Amounts presented for each class of units include a proportionate amount of the $474 thousand distributable to holders of the Equity classified Phantom Units pursuant to the distribution equivalent rights granted under the USD Partners LP 2014 Amended and Restated Long-Term Incentive Plan.


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


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


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


⁽⁶⁾	Our computation of net income per limited partner unit excludes the effects of 1,290,558 equity-classified phantom unit awards outstanding as they were anti-dilutive for the period presented.


⁽⁷⁾	In February 2019, pursuant to the terms set forth in our partnership agreement, the fourth and final vesting tranche of 38,750 Class A units vested and were converted into Common units. Refer to Note 17. Partners Capital for more information.



	For the Three Months Ended September 30, 2018
	Common Units			Subordinated Units			Class A Units			General Partner Units			Total
	(in thousands, except per unit amounts)
Net income attributable to general and limited partner interests in USD Partners LP ⁽¹⁾	$	4,794		$	916		$	9		$	209		$	5,928
Less: Distributable earnings ⁽²⁾	8,200			1,566			14			280			10,060
Distributions in excess of earnings	$	(3,406	)	$	(650	)	$	(5	)	$	(71	)	$	(4,132	)
Weighted average units outstanding ⁽³⁾	21,915			4,185			39			461			26,600
Distributable earnings per unit ⁽⁴⁾	$	0.37		$	0.37		$	0.36
Overdistributed earnings per unit ⁽⁵⁾	(0.16		)	(0.16		)	(0.13		)
Net income per limited partner unit (basic and diluted)⁽⁶⁾	$	0.21		$	0.21		$	0.23


⁽¹⁾	Represents net income allocated to each class of units based on the actual ownership of the Partnership during the period. The net income for each class of limited partner interest has been reduced by its proportionate amount of the approximate $107 thousand attributed to the general partner for its incentive distribution rights.

⁽²⁾

Represents the distributions paid for the period based upon the quarterly distribution amount of 0.3575 per unit, or $1.43 per unit on an annualized basis. Amounts presented for each class of units include a proportionate amount of the $443 thousand distributed to holders of the Equity-classified Phantom Units pursuant to the distribution equivalent rights granted under the USD Partners Amended and Restated LP 2014 Long-Term Incentive Plan.


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


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


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


⁽⁶⁾	Our computation of net income per limited partner unit excludes the effects of 1,239,488 equity-classified phantom unit awards outstanding as they were anti-dilutive for the period presented.



	For the Nine Months Ended September 30, 2019
	Common Units			Subordinated Units			Class A Units ⁽⁷⁾		General Partner Units			Total
	(in thousands, except per unit amounts)
Net income attributable to general and limited partner interests in USD Partners LP ⁽¹⁾	$	3,506		$	311		$	—	$	559		$	4,376
Less: Distributable earnings ⁽²⁾	28,010			2,402			—		1,012			31,424
Distributions in excess of earnings	$	(24,504	)	$	(2,091	)	$	—	$	(453	)	$	(27,048	)
Weighted average units outstanding ⁽³⁾	23,965			2,476			7		461			26,909
Distributable earnings per unit ⁽⁴⁾	$	1.17		$	0.97		$	—
Overdistributed earnings per unit ⁽⁵⁾	(1.02		)	(0.84		)	—
Net income per limited partner unit (basic and diluted)⁽⁶⁾	$	0.15		$	0.13		$	—


⁽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 $483 thousand attributed to the general partner for its incentive distribution rights.

⁽²⁾

Represents the per unit distributions paid of $0.3625 per unit for the three months ended March 31, 2019, the per unit distribution of $0.365 per unit for the three months ended June 30, 2019, and the per unit distributable of $0.3675 for the three months ended September 30, 2019, representing a year-to-date distribution amount of $1.095 per unit. Amounts presented for each class of units include a proportionate amount of the $940 thousand distributed and $474 thousand distributable to holders of the Equity classified Phantom Units pursuant to the distribution equivalent rights granted under the USD Partners LP 2014 Amended and Restated Long-Term Incentive Plan.


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


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


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


⁽⁶⁾	Our computation of net income per limited partner unit excludes the effects of 1,290,558 equity-classified phantom unit awards outstanding as they were anti-dilutive for the period presented.


⁽⁷⁾	In February 2019, pursuant to the terms set forth in our partnership agreement, the fourth and final vesting tranche of 38,750 Class A units vested and were converted into Common units. Refer to Note 17. Partners Capital for more information.



	For the Nine Months Ended September 30, 2018
	Common Units			Subordinated Units			Class A Units			General Partner Units			Total
	(in thousands, except per unit amounts)
Net income attributable to general and limited partner interests in USD Partners LP ⁽¹⁾	$	15,337		$	3,246		$	33		$	624		$	19,240
Less: Distributable earnings ⁽²⁾	24,432			4,665			42			805			29,944
Distributions in excess of earnings	$	(9,095	)	$	(1,419	)	$	(9	)	$	(181	)	$	(10,704	)
Weighted average units outstanding ⁽³⁾	21,480			4,569			46			461			26,556
Distributable earnings per unit ⁽⁴⁾	$	1.14		$	1.02		$	0.91
Overdistributed earnings per unit ⁽⁵⁾	(0.42		)	(0.31		)	(0.20		)
Net income per limited partner unit (basic and diluted)⁽⁶⁾	$	0.72		$	0.71		$	0.71


⁽¹⁾	Represents net income allocated to each class of units based on the actual ownership of the Partnership during the period. The net income for each class of limited partner interest has been reduced by its proportionate amount of the approximate $291 thousand attributed to the general partner for its incentive distribution rights.

⁽²⁾

Represents the distributions paid for the period based upon the quarterly distribution amount of $0.3525 per unit for the three months ended March 31, 2018 and $0.355 per unit for the three months ended June 30, 2018, and $0.3575 per unit for the three months ended September 30, 2018, representing a year-to-date distribution amount of $1.065 per unit. Amounts presented for each class of units include a proportionate amount of the $1.3 million distributed to holders of the Equity-classified Phantom Units pursuant to the distribution equivalent rights granted under the USD Partners Amended and Restated LP 2014 Long-Term Incentive Plan.


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


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


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


⁽⁶⁾	Our computation of net income per limited partner unit excludes the effects of 1,239,488 equity-classified phantom unit awards outstanding as they were anti-dilutive for the period presented.

4. REVENUES

Disaggregated Revenues

We manage our business in two reportable segments: Terminalling services and Fleet services. Our segments offer different services and are managed accordingly. Our chief operating decision maker, or CODM, regularly reviews financial information about both segments in order to allocate resources and evaluate performance. As such, we have concluded that disaggregating revenue by reporting segments appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. Refer to Note 14. Segment Reporting for our disaggregated revenues by segment. Additionally, the below tables summarize the geographic data for our revenues:



	Three Months Ended September 30, 2019
	U.S.		Canada		Total
	(in thousands)
Third party	$	7,963	$	16,068	$	24,031
Related party	$	2,320	$	3,543	$	5,863



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



	Nine Months Ended September 30, 2019
	U.S.		Canada		Total
	(in thousands)
Third party	$	25,405	$	39,163	$	64,568
Related party	$	6,902	$	12,607	$	19,509



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

Remaining Performance Obligations

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



	For the three months ending December 31, 2019		2020		2021		2022		Thereafter		Total
	(in thousands)
Terminalling Services ^{(1) (2)}	$	24,846	$	80,211	$	65,523	$	57,431	$	39,078	$	267,089
Fleet Services	712		1,030		1,016		1,267		41		4,066
Total	$	25,558	$	81,241	$	66,539	$	58,698	$	39,119	$	271,155

⁽¹⁾The majority of our terminalling services agreements are denominated in Canadian dollars. We have converted the remaining performance obligations provided herein using the year-to-date average exchange rate of 0.7524 U.S. dollars per one Canadian dollar at September 30, 2019.

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

We have applied the practical expedient that allows us to exclude disclosure of performance obligations that are part of a contract that has an expected duration of one year or less. In addition, we have also applied the practical

expedient that allows us not to disclose the amount of transaction price allocated to the remaining performance obligations for all reporting periods presented prior to our adoption of ASC 606.

Contract Assets

Our contract assets represent cumulative revenue that has been recognized in advance of billing the customer due to tiered billing provisions. In such arrangements, revenue is recognized using a blended rate based on the billing tiers of the agreement, as the services are consistently provided throughout the duration of the contractual arrangement. We have included contract assets of $257 thousand and $68 thousand as of September 30, 2019 and December 31, 2018, respectively, in “Other current assets” and $171 thousand as of December 31, 2018, in “Other non-current assets” on our consolidated balance sheets. In addition we have included contract assets of $389 thousand as of September 30, 2019 in “Other current assets— related party” on our consolidated balance sheets.

Contract Liabilities

Our contract liabilities consist of amounts collected in advance from customers associated with their terminalling and fleet services agreements and deferred revenues associated with make-up rights, which will be recognized as revenue when earned pursuant to the terms of our contractual arrangements. We currently recognize substantially all of the amounts we receive for minimum volume commitments as revenue when collected, since breakage associated with these make-up rights options is approximately between 97% and 99% based on our experience and expectations around usage of these options. We deferred $1.1 million in revenues at September 30, 2019 for estimated breakage associated with the make-up rights options we granted to our customers, which we included in “Deferred revenue” on our consolidated balance sheets. We also have other contract liabilities that represent cumulative revenue that has been deferred due to tiered billing provisions. In such arrangements, revenue is recognized using a blended rate based on the billing tiers of the agreement, as the services are consistently provided throughout the duration of the contractual arrangement, which we included in “Other non-current liabilities” on our consolidated balance sheets.

We have included contract liabilities with third-party customers of $6.0 million and $2.9 million as of September 30, 2019 and December 31, 2018, respectively, in “Deferred revenue.” We have included contract liabilities with related party customers of $1.1 million and $1.5 million as of September 30, 2019 and December 31, 2018, respectively, in “Deferred revenue — related party” on our consolidated balance sheets. We have also included contract liabilities of $1.7 million as of September 30, 2019 and none at December 31, 2018 with third-party customers in “Other non-current liabilities” on our consolidated balance sheets.

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



	December 31, 2018		Cash Additions for Customer Prepayments		Revenue Recognized			September 30, 2019
	(in thousands)
Customer prepayments	$	2,921	$	6,016	$	(2,921	)	$	6,016
Customer prepayments — related party ⁽¹⁾	$	1,475	$	1,054	$	(1,475	)	$	1,054
Other contract liabilities	$	—	$	1,667	$	—		$	1,667


⁽¹⁾	Includes contract liabilities associated with customer prepayments from related parties. Refer to Note 12. Transactions with Related Parties for additional discussion of deferred revenues associated with related parties.

Deferred Revenue — Fleet Leases

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

5. RESTRICTED CASH

We include in restricted cash amounts representing a cash account for which the use of funds is restricted by a facilities connection agreement among us and Gibson Energy Inc., or Gibson, that we entered into during 2014 in connection with the development of our Hardisty terminal. The collaborative arrangement is further discussed in Note 10. Collaborative Arrangement.

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



	September 30,
	2019		2018
	(in thousands)
Cash and cash equivalents	$	6,479	$	7,361
Restricted Cash	7,644		5,834
Total cash, cash equivalents and restricted cash	$	14,123	$	13,195

6. PROPERTY AND EQUIPMENT

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



	September 30, 2019			December 31, 2018			Estimated Depreciable Lives (Years)
	(in thousands)						Estimated Depreciable Lives (Years)
Land	$	10,087		$	10,004		N/A
Trackage and facilities	124,907			123,080			10-30
Pipeline	16,366			16,336			20-25
Equipment	16,709			16,455			3-20
Furniture	65			64			5-10
Total property and equipment	168,134			165,939
Accumulated depreciation	(36,384		)	(29,479		)
Construction in progress ⁽¹⁾	16,794			8,848
Property and equipment, net	$	148,544		$	145,308

⁽¹⁾

The amounts classified as “Construction in progress” are excluded from amounts being depreciated. These amounts represent property that is not yet ready to be placed into productive service as of the respective consolidated balance sheet date. We had $170 thousand and $439 thousand of capitalized interest costs for the three and nine months ended September 30, 2019, respectively, and none for the same periods in 2018.

Depreciation expense associated with Property and equipment totaled $2.1 million for the three months ended September 30, 2019 and 2018, and $5.9 million and $6.4 million for the nine months ended September 30, 2019 and 2018, respectively.

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

7. LEASES

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



	Nine Months Ended September 30, 2019
Weighted-average discount rate	6.4	%
Weighted average remaining lease term in years	2.96

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



		Three Months Ended September 30, 2019			Nine Months Ended September 30, 2019
	(in thousands)
Operating lease cost		$	1,483		$	4,451
Short term lease cost		48			147
Sublease income		(1,332		)	(4,002		)
Total		$	199		$	596

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



2019	$	1,520
2020	5,269
2021	4,074
2022	3,787
2023	20
Thereafter	—
Total lease payments	$	14,670
Less: imputed interest	(1,320		)
Present value of lease liabilities	$	13,350

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



	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
	(in thousands, except weighted average term)
Lease income	$	2,363	$	7,512
Weighted average remaining lease term in years			3.03

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



2019	$	1,988
2020	6,895
2021	5,752
2022	4,639
Total	$	19,274

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

8. 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, 2019, 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 2019, 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, 2019. 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 11%;


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


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


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

(5) A range of incremental volumes expected at our Casper terminal of approximately 20,000 to 40,000 bpd for terminalling and storage services resulting from the anticipated successful completion of the Enbridge DRA project in the first quarter of 2020.

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, 2019.

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, 2019			December 31, 2018
	(in thousands)
Carrying amount:
Customer service agreements	$	125,960		$	125,960
Other	106			106
Total carrying amount	126,066			126,066
Accumulated amortization:
Customer service agreements	(48,775		)	(39,328		)
Other	(41		)	(33		)
Total accumulated amortization	(48,816		)	(39,361		)
Total intangible assets, net	$	77,250		$	86,705

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, 2019, the date of our evaluation, indicating cash flows were expected to be sufficient to recover the carrying value of the Casper terminal asset group. No further triggering events were identified through September 30, 2019.

Amortization expense associated with intangible assets totaled $3.2 million for each of the three months ended September 30, 2019 and 2018 and $9.5 million for each of the nine months ended September 30, 2019 and 2018.

9. DEBT

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

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

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

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



	September 30, 2019			December 31, 2018
	(in thousands)
Revolving Credit Facility	$	216,000		$	209,000
Less: Deferred financing costs, net	(2,556		)	(3,419		)
Total long-term debt, net	$	213,444		$	205,581

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



	September 30, 2019		December 31, 2018
	(in millions)
Aggregate borrowing capacity under Credit Agreement	$	385.0	$	385.0
Less: Revolving Credit Facility amounts outstanding	216.0		209.0
Letters of credit outstanding	—		0.6
Available under Credit Agreement ⁽¹⁾	$	169.0	$	175.4


⁽¹⁾	Pursuant to the terms of our Credit Agreement, our borrowing capacity, currently, is limited to 4.5 times our trailing 12-month consolidated EBITDA, which equates to approximately $37 million of availability at September 30, 2019.

The average interest rate on our outstanding indebtedness was 4.80% and 4.86% at September 30, 2019 and December 31, 2018, respectively, without consideration to the effect of our derivative contracts. In addition to the interest we incur on our outstanding indebtedness, we pay commitment fees of 0.50% on unused commitments, which rate will vary based on our consolidated net leverage ratio, as defined in our Credit Agreement. At September 30, 2019, we were in compliance with the covenants set forth in our Credit Agreement.

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



	Three Months Ended September 30,					Nine Months Ended September 30,
	2019			2018		2019			2018
	(in thousands)
Interest expense on the Credit Agreement	$	2,967		$	2,611	$	8,748		$	7,379
Capitalized interest on construction in progress	(170		)	—		(439		)	—
Amortization of deferred financing costs	208			216		865			646
Total interest expense	$	3,005		$	2,827	$	9,174		$	8,025

10. COLLABORATIVE ARRANGEMENT

We entered into a facilities connection agreement in 2014 with Gibson under which Gibson developed, constructed and operates a pipeline and related facilities connected to our Hardisty terminal. Gibson’s storage terminal is the exclusive means by which our Hardisty terminal receives crude oil. Subject to certain limited exceptions regarding manifest train facilities, our Hardisty terminal is the exclusive means by which crude oil from Gibson’s Hardisty storage terminal may be transported by rail. We remit pipeline fees to Gibson for the transportation of crude oil to our Hardisty terminal based on a predetermined formula. Pursuant to our arrangement with Gibson, we incurred pipeline fees of $5.4 million and $5.3 million for the three months ended September 30, 2019 and 2018, respectively, and $15.4 million and $16.1 million for the nine months ended September 30, 2019 and 2018, respectively, which are presented as “Pipeline fees” in our consolidated statements of income.

11. NONCONSOLIDATED VARIABLE INTEREST ENTITIES

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

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



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



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

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

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

12. TRANSACTIONS WITH RELATED PARTIES

Nature of Relationship with Related Parties

USD is engaged in designing, developing, owning and managing large-scale multi-modal logistics centers and other energy-related infrastructure across North America. USD is also the sole owner of USDG and the ultimate parent of our general partner. USD is owned by Energy Capital Partners, Goldman Sachs and certain members of its management.

USDG is the sole owner of our general partner and at September 30, 2019, owns 9,464,381 of our common units and all 2,092,709 of our subordinated units representing a combined 42.9% limited partner interest in us. As of September 30, 2019, a value of up to $10.0 million of these common units were pledged as collateral under USDG’s letter of credit facility. USDG also provides us with general and administrative support services necessary for the operation and management of our business.

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

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

USD Terminals Canada II ULC, or USDTC II, is an indirect, wholly-owned Canadian subsidiary of USDG, organized for the purposes of pursuing expansion and other development opportunities associated with our Hardisty Terminal, pursuant to the Development Rights and Cooperation agreement between our wholly-owned subsidiary USD Terminals Canada ULC, or USDTC, and USDG. USDTC owns the legacy crude oil loading facility we refer to as the Hardisty terminal. USDTC II completed construction of the Hardisty South expansion (“Hardisty South”) which commenced operations in January 2019. Hardisty South, which is owned and operated by USDTC II, added one120-railcar unit train of transloading capacity per day, or approximately 75,000 barrels per day, of takeaway capacity to the terminal by modifying the existing loading rack and building additional infrastructure and trackage.

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, 2019 and 2018 were $1.4 million and $1.9 million, respectively, and for the nine months ended September 30, 2019 and 2018 were $6.1 million and $5.6 million, respectively, which amounts are included in “Selling, general and administrative — related party” in our consolidated statements of income. At September 30, 2019 and December 31, 2018, we had balances payable related to these costs of $0.4 million recorded as “Accounts payable and accrued expenses — related party” in our consolidated balance sheets.

Marketing Services Agreement

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

Hardisty Terminal Services Agreement

We entered into a terminal services agreement with USDTC II during the third quarter of 2019, whereby Hardisty South will provide terminalling services for a third-party customer of our Hardisty terminal for contracted capacity that exceeds the transloading capacity currently available, if needed. We incurred expenses pursuant to this arrangement of $2.5 million for the three and nine months ended September 30, 2019, which amounts are included in “Operating and maintenance expense — related party” in our consolidated statements of income. These costs represent the same rate, on a per barrel basis, that we received as revenue from our third-party customer, which is included in “Terminalling Services” revenue in our consolidated statements of income.

Hardisty Shared Facilities Agreement

USDTC facilitates the provision of services on behalf of USDTC II pursuant to the terms of a shared facilities agreement, which includes all subcontracted railcar loading, operating, maintenance, pipeline and management services for the entire Hardisty terminal, including Hardisty South owned by USDTC II, and passes through a proportionate amount of the cost of such services to USDTC II. Our financial statements only reflect the cost incurred by USDTC.

Related Party Revenue and Deferred Revenue

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

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

In connection with our purchase of the Stroud terminal, we also entered into a Marketing Services Agreement with USDM, as discussed above. Pursuant to the terms of the agreement, we receive a fixed amount per barrel from

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

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
	(in thousands)
Terminalling services — related party	$	4,459	$	5,715	$	15,622	$	15,414
Fleet leases — related party	984		984		2,951		2,951
Fleet services — related party	227		227		682		682
Freight and other reimbursables — related party	193		—		254		4
	$	5,863	$	6,926	$	19,509	$	19,051

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



	September 30, 2019		December 31, 2018
	(in thousands)
Accounts receivable — related party	$	1,689	$	624
Accounts payable — related party ⁽¹⁾	$	2,547	$	67
Other current and non-current assets — related party⁽²⁾	$	503	$	174
Deferred revenue — related party ⁽³⁾	$	1,464	$	1,885


⁽¹⁾	Includes amounts payable to a related party pursuant to the Hardisty Terminal Services Agreement, discussed above, as well as other accounts payable related party amounts associated with our terminalling services business. Does not include amounts payable to related parties associated with the Omnibus Agreement, as discussed above.


⁽²⁾	Represents a contract asset associated with a lease agreement with USDM and cumulative revenue that has been recognized in advance of billing the customer due to tiered billing provisions. Refer to Note 4. Revenue for further discussion.


⁽³⁾	Represents deferred revenues associated with our terminalling and fleet services agreements with USD and affiliates for amounts we have collected from them for their prepaid leases and prepaid minimum volume commitment fees.

Cash Distributions

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



Distribution Declaration Date	Record Date	Distribution Payment Date	Amount Paid to USDG		Amount Paid to USD Partners GP LLC
			(in thousands)
January 31, 2019	February 11, 2019	February 19, 2019	$	4,161	$	285
April 26, 2019	May 7, 2019	May 15, 2019	$	4,189	$	308
July 24, 2019	August 6, 2019	August 14, 2019	$	4,218	$	329

13. 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.

14. SEGMENT REPORTING

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

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



	Three Months Ended September 30, 2019
	Terminalling services			Fleet services			Corporate			Total
	(in thousands)
Revenues
Terminalling services	$	23,709		$	—		$	—		$	23,709
Terminalling services — related party	4,459			—			—			4,459
Fleet leases — related party	—			984			—			984
Fleet services	—			50			—			50
Fleet services — related party	—			227			—			227
Freight and other reimbursables	220			52			—			272
Freight and other reimbursables — related party	—			193			—			193
Total revenues	28,388			1,506			—			29,894
Operating costs
Subcontracted rail services	3,689			—			—			3,689
Pipeline fees	5,411			—			—			5,411
Freight and other reimbursables	220			245			—			465
Operating and maintenance	3,934			1,018			—			4,952
Selling, general and administrative	1,368			218			2,760			4,346
Depreciation and amortization	5,300			—			—			5,300
Total operating costs	19,922			1,481			2,760			24,163
Operating income (loss)	8,466			25			(2,760		)	5,731
Interest expense	—			—			3,005			3,005
Loss associated with derivative instruments	—			—			220			220
Foreign currency transaction loss (gain)	33			(2		)	4			35
Other income, net	(45		)	—			(4		)	(49		)
Provision for income taxes	406			8			—			414
Net income (loss)	$	8,072		$	19		$	(5,985	)	$	2,106



	Three Months Ended September 30, 2018
	Terminalling services			Fleet services			Corporate			Total
	(in thousands)
Revenues
Terminalling services	$	22,070		$	—		$	—		$	22,070
Terminalling services — related party	5,715			—			—			5,715
Fleet leases — related party	—			984			—			984
Fleet services	—			80			—			80
Fleet services — related party	—			227			—			227
Freight and other reimbursables	302			208			—			510
Freight and other reimbursables — related party	—			—			—			—
Total revenues	28,087			1,499			—			29,586
Operating costs
Subcontracted rail services	3,674			—			—			3,674
Pipeline fees	5,267			—			—			5,267
Freight and other reimbursables	302			208			—			510
Operating maintenance	1,634			1,052			—			2,686
Selling, general and administrative	1,346			401			2,609			4,356
Depreciation and amortization	5,271			—			—			5,271
Total operating costs	17,494			1,661			2,609			21,764
Operating income (loss)	10,593			(162		)	(2,609		)	7,822
Interest expense	—			—			2,827			2,827
Gain associated with derivative instruments	—			—			(413		)	(413		)
Foreign currency transaction loss (gain)	(30		)	3			(62		)	(89		)
Other income, net	(1		)	—			—			(1		)
Provision for (benefit from) income taxes	(431		)	5			(4		)	(430		)
Net income (loss)	$	11,055		$	(170	)	$	(4,957	)	$	5,928



	Nine Months Ended September 30, 2019
	Terminalling services			Fleet services		Corporate			Total
	(in thousands)
Revenues
Terminalling services	$	63,437		$	—	$	—		$	63,437
Terminalling services — related party	15,622			—		—			15,622
Fleet leases — related party	—			2,951		—			2,951
Fleet services	—			158		—			158
Fleet services — related party	—			682		—			682
Freight and other reimbursables	741			232		—			973
Freight and other reimbursables — related party	7			247		—			254
Total revenues	79,807			4,270		—			84,077
Operating costs
Subcontracted rail services	10,953			—		—			10,953
Pipeline fees	15,374			—		—			15,374
Freight and other reimbursables	748			479		—			1,227
Operating and maintenance	7,622			3,051		—			10,673
Selling, general and administrative	4,628			710		8,882			14,220
Depreciation and amortization	15,317			—		—			15,317
Total operating costs	54,642			4,240		8,882			67,764
Operating income (loss)	25,165			30		(8,882		)	16,313
Interest expense	—			—		9,174			9,174
Loss associated with derivative instruments	—			—		1,966			1,966
Foreign currency transaction loss (gain)	(62		)	6		293			237
Other income, net	(44		)	—		(8		)	(52		)
Provision for income taxes	596			16		—			612
Net income (loss)	$	24,675		$	8	$	(20,307	)	$	4,376



	Nine Months Ended September 30, 2018
	Terminalling services			Fleet services			Corporate			Total
	(in thousands)
Revenues
Terminalling services	$	66,586		$	—		$	—		$	66,586
Terminalling services — related party	15,414			—			—			15,414
Fleet leases — related party	—			2,951			—			2,951
Fleet services	—			505			—			505
Fleet services — related party	—			682			—			682
Freight and other reimbursables	1,062			1,692			—			2,754
Freight and other reimbursables — related party	3			1			—			4
Total revenues	83,065			5,831			—			88,896
Operating costs
Subcontracted rail services	10,047			—			—			10,047
Pipeline fees	16,109			—			—			16,109
Freight and other reimbursables	1,065			1,693			—			2,758
Operating and maintenance	4,362			3,178			—			7,540
Selling, general and administrative	4,133			961			8,458			13,552
Depreciation and amortization	15,807			—			—			15,807
Total operating costs	51,523			5,832			8,458			65,813
Operating income (loss)	31,542			(1		)	(8,458		)	23,083
Interest expense	—			—			8,025			8,025
Gain associated with derivative instruments	—			—			(1,823		)	(1,823		)
Foreign currency transaction loss (gain)	32			(4		)	(211		)	(183		)
Other expense, net	71			—			—			71
Provision for (benefit from) income taxes	(2,265		)	21			(3		)	(2,247		)
Net income (loss)	$	33,704		$	(18	)	$	(14,446	)	$	19,240

Segment Adjusted EBITDA

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



	Three Months Ended September 30,						Nine Months Ended September 30,
Terminalling Services Segment	2019			2018			2019			2018
	(in thousands)
Net income	$	8,072		$	11,055		$	24,675		$	33,704
Interest income	(18		)	—			(33		)	—
Depreciation and amortization	5,300			5,271			15,317			15,807
Provision for (benefit from) income taxes	406			(431		)	596			(2,265		)
Foreign currency transaction loss (gain) ⁽¹⁾	33			(30		)	(62		)	32
Loss associated with disposal of assets	—			—			50			73
Other income	(27		)	—			(69		)	—
Non-cash deferred amounts ⁽²⁾	1,435			(51		)	1,545			(154		)
Segment Adjusted EBITDA	$	15,201		$	15,814		$	42,019		$	47,197


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

⁽²⁾

Represents the change in non-cash contract assets and liabilities associated with revenue recognized at blended rates based on tiered rate structures in certain of the Partnership’s customer contracts and deferred revenue associated with deficiency credits that are expected to be used in the future prior to their expiration. Amounts presented are net of the corresponding prepaid Gibson pipeline fee that will be recognized as expense concurrently with the recognition of revenue.



	Three Months Ended September 30,						Nine Months Ended September 30,
Fleet Services Segment	2019			2018			2019		2018
	(in thousands)
Net income (loss)	$	19		$	(170	)	$	8	$	(18	)
Provision for income taxes	8			5			16		21
Foreign currency transaction loss (gain) ⁽¹⁾	(2		)	3			6		(4		)
Segment Adjusted EBITDA	$	25		$	(162	)	$	30	$	(1	)


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

15. INCOME TAXES

U.S. Federal and State Income Taxes

We are treated as a partnership for U.S. federal and most state income tax purposes, with each partner being separately taxed on their share of our taxable income. We have elected to classify one of our subsidiaries, USD Rail LP, as an entity taxable as a corporation for U.S. federal income tax purposes due to treasury regulations that do not permit the income of this subsidiary to meet the definition of “qualifying income” as set forth in Internal Revenue Code §7704(d). We are also subject to state franchise tax in the state of Texas, which is treated as an income tax under the applicable accounting guidance. Our U.S. federal income tax expense is based on the statutory federal income tax rate of 21%, as applied to USD Rail LP’s taxable losses of $0.2 million and $0.3 million for the three months ended September 30, 2019 and 2018, respectively, and losses of $0.4 million and $0.7 million for the nine months ended September 30, 2019 and 2018, respectively.

Foreign Income Taxes

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

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

Estimated Annual Effective Income Tax Rate

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



	Three Months Ended September 30,										Nine Months Ended September 30,
	2019					2018					2019					2018
	(in thousands)
Income tax expense at the U.S. federal statutory rate	$	529		21	%	$	1,154		21	%	$	1,047		21	%	$	3,568		21	%
Amount attributable to partnership not subject to income tax	(277		)	(11	)%	(1,582		)	(29	)%	(649		)	(13	)%	(5,483		)	(32	)%
Foreign income tax rate differential	105			4	%	(108		)	(2	)%	168			3	%	(494		)	(3	)%
Other	—			—	%	56			1	%	(53		)	(1	)%	12			—	%
State income tax expense (benefit) ⁽¹⁾	8			—	%	2			—	%	16			—	%	(4		)	—	%
Change in valuation allowance	49			2	%	48			1	%	83			2	%	154			1	%
Provision for (benefit from) income taxes	$	414		16	%	$	(430	)	(8	)%	$	612		12	%	$	(2,247	)	(13	)%


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

We determined our year-to-date 2019 provision for income taxes using an estimated annual effective income tax rate of 12% on a consolidated basis for fiscal year 2019. This rate incorporates the applicable income tax rates of the various domestic and foreign tax jurisdictions to which we are subject.



	Three Months Ended September 30,					Nine Months Ended September 30,
	2019		2018			2019			2018
	(in thousands)
Current income tax expense (benefit):
U.S. federal income tax	$	—	$	—		$	—		$	4
State income tax expense (benefit)	8		2			16			(4		)
Canadian federal and provincial income taxes expense	302		299			895			1,022
Total current income tax expense	310		301			911			1,022
Deferred income tax expense (benefit):
U.S. federal income tax expense	—		—			—			16
Canadian federal and provincial income taxes expense (benefit)	104		(731		)	(299		)	(3,285		)
Total deferred income tax benefit	104		(731		)	(299		)	(3,269		)
Provision for (benefit from) income taxes	$	414	$	(430	)	$	612		$	(2,247	)

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, 2019
	U.S.			Foreign			Total
	(in thousands)
Deferred income tax assets
Property and equipment	$	—		$	162		$	162
Capital loss carryforwards	—			368			368
Operating loss carryforwards	359			—			359
Deferred income tax liabilities
Unbilled revenue	—			(232		)	(232		)
Prepaid expenses	(8		)	—			(8		)
Property and equipment	—			—			—
Valuation allowance	(351		)	(368		)	(719		)
Deferred income tax liability, net	$	—		$	(70	)	$	(70	)



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

We had a $1.7 million and $1.3 million U.S. federal loss carryforward remaining as of September 30, 2019 and December 31, 2018, respectively. Our U.S. federal loss carryforward was generated in 2018 and 2019 and does not expire under currently enacted tax law. Our Canadian loss carryforward was $4.4 million and $4.2 million as of September 30, 2019 and December 31, 2018, respectively. A portion of our Canadian loss carryforward is for capital

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

We are subject to examination by the taxing authorities for the years ended December 31, 2018, 2017 and 2016. We did not have any unrecognized income tax benefits or any income tax reserves for uncertain tax positions as of September 30, 2019 and December 31, 2018.

Refer to Note 19. Supplemental Cash Flow Information for information regarding amounts paid for income taxes.

16. DERIVATIVE FINANCIAL INSTRUMENTS

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

Interest Rate Derivatives

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

Derivative Positions

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



	September 30, 2019			December 31, 2018
	(in thousands)
Other current assets	$	—		$	260
Other non-current assets	—			335
Other current liabilities	(212		)	—
Other non-current liabilities	(1,161		)	—
	$	(1,373	)	$	595

We have not designated our derivative financial instruments as hedges of our interest rate exposure. 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,
	2019		2018			2019		2018
	(in thousands)
Loss (gain) associated with derivative instruments	$	220	$	(413	)	$	1,966	$	(1,823	)

We determine the fair value of our derivative financial instruments using third party pricing information that is derived from observable market inputs, which we classify as level 2 with respect to the fair value hierarchy.

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



					At September 30, 2019			At December 31, 2018
	Notional		Interest Rate Parameters		Fair Value			Fair Value
					(in thousands)
Collar Agreements Maturing in 2022
Ceiling	$	100,000,000	2.5	%	$	102		$	1,238
Floor	$	100,000,000	1.7	%	(1,475		)	(643		)
Total					$	(1,373	)	$	595

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



	September 30, 2019
	Current assets			Non-current assets			Current liabilities			Non-current liabilities			Total
	(in thousands)
Fair value of derivatives — gross presentation	$	2		$	100		$	(214	)	$	(1,261	)	$	(1,373	)
Effects of netting arrangements	(2		)	(100		)	2			100			—
Fair value of derivatives — net presentation	$	—		$	—		$	(212	)	$	(1,161	)	$	(1,373	)



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

17. PARTNERS’ CAPITAL

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

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

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

Subordinated units convert into common units on a one-for-one basis in separate sequential tranches. Each tranche is comprised of 20.0% of the subordinated units issued in conjunction with our IPO. Each separate tranche is eligible to convert on or after December 31, 2015 (but no more frequently than once in any twelve-month period), provided on such date: (i) distributions of available cash from operating surplus on each of the outstanding common units, Class A units, subordinated units and general partner units equaled or exceeded $1.15 per unit (the annualized minimum quarterly distribution) for the four quarter period immediately preceding that date; (ii) the adjusted operating surplus generated during the four quarter period immediately preceding that date equaled or exceeded the sum of $1.15 per unit (the annualized minimum quarterly distribution) on all of the common units, Class A units, subordinated units and general partner units outstanding during that period on a fully diluted basis; and (iii) there are no arrearages in the payment of the minimum quarterly distribution on our common units. For each successive tranche, the four quarter period specified in clauses (i) and (ii) above must commence after the four quarter period applicable to any prior tranche of subordinated units. In February 2019, pursuant to the terms set forth in our partnership agreement, we converted the fourth tranche of 2,092,709 of our subordinated units into common units upon satisfaction of the conditions established for conversion.

Pursuant to the terms of the USD Partners LP Amended and Restated 2014 Long-Term Incentive Plan, which we refer to as the A/R LTIP, our phantom unit awards, or Phantom Units, granted to directors and employees of our general partner and its affiliates, which are classified as equity, are converted into our common units upon vesting. Equity-classified Phantom Units totaling 453,459 vested during the first nine months of 2019, of which 363,797 were converted into our common units after 162,979 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 18. 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.

18. UNIT BASED COMPENSATION

Class A units

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

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



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

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



	Three Months Ended September 30,				Nine months ended September 30,
	2019		2018		2019		2018
	(in thousands)
Selling, general and administrative	$	—	$	42	$	14	$	216

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

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

Long-term Incentive Plan

In 2019 and 2018, the board of directors of our general partner, acting in its capacity as our general partner, approved the grant of 633,637 and 553,940 Phantom Units, respectively, to directors and employees of our general partner and its affiliates under our A/R LTIP. At September 30, 2019, we had 1,382,511 Phantom Units remaining available for grant pursuant to the terms of our A/R LTIP. The Phantom Units are subject to all of the terms and conditions

of the A/R LTIP and the Phantom Unit award agreements, which are collectively referred to as the Award Agreements. Award amounts for each of the grants are generally determined by reference to a specified dollar amount based on an allocation formula which included a percentage multiplier of the grantee’s base salary, among other factors, converted to a number of units based on a closing price of one of our common units preceding the grant date, as determined by the board of directors of our general partner and quoted on the NYSE.

Phantom Unit awards generally represent rights to receive our common units upon vesting. However, with respect to the awards granted to directors and employees of our general partner and its affiliates domiciled in Canada, for each Phantom Unit that vests, a participant is entitled to receive cash for an amount equivalent to the closing market price of one of our common units on the vesting date. Each Phantom Unit granted under the Award Agreements includes an accompanying distribution equivalent right, or DER, which entitles each participant to receive payments at a per unit rate equal in amount to the per unit rate for any distributions we make with respect to our common units. The Award Agreements granted to employees of our general partner and its affiliates generally contemplate that the individual grants of Phantom Units will vest in four equal annual installments based on the grantee’s continued employment through the vesting dates specified in the Award Agreements, subject to acceleration upon the grantee’s death or disability, or involuntary termination in connection with a change in control of the Partnership or our general partner. Awards to independent directors of the board of our general partner and an independent consultant typically vest over a one year period following the grant date.

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



	Director and Independent Consultant Phantom Units		Employee Phantom Units		Weighted-Average Grant Date Fair Value Per Phantom Unit
Phantom Unit awards at December 31, 2018	34,611		1,130,685		$	11.19
Granted	37,139		544,857		$	11.37
Vested	(34,611	)	(418,848	)	$	11.00
Forfeited	—		(3,275	)	$	10.99
Phantom Unit awards at September 30, 2019	37,139		1,253,419		$	11.34



	Director and Independent Consultant Phantom Units		Employee Phantom Units		Weighted-Average Grant Date Fair Value Per Phantom Unit
Phantom Unit awards at December 31, 2017	24,999		1,111,849		$	10.90
Granted	34,611		487,839		$	11.54
Vested	(24,999	)	(338,071	)	$	10.86
Forfeited	—		(56,740	)	$	11.07
Phantom Unit awards at September 30, 2018	34,611		1,204,877		$	11.18

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



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



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

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

For the three months ended September 30, 2019 and 2018, we recognized $1.5 million and $1.4 million, respectively, and $4.5 million and $4.1 million for the nine months ended September 30, 2019 and 2018, respectively, of compensation expense associated with outstanding Phantom Units. As of September 30, 2019, we have unrecognized compensation expense associated with our outstanding Phantom Units totaling $11.8 million, which we expect to recognize over a weighted average period of 2.56 years. We have elected to account for actual forfeitures as they occur rather than using an estimated forfeiture rate to determine the number of awards we expect to vest.

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
	(in thousands)
Equity-classified Phantom Units ⁽¹⁾	$	471	$	440	$	1,358	$	1,269
Liability-classified Phantom Units	30		21		74		55
Total	$	501	$	461	$	1,432	$	1,324


⁽¹⁾	We had no significant reclassifications for the three months ended September 30, 2019 and 2018, and $8 thousand and $84 thousand for the nine months ended September 30, 2019 and 2018, respectively, to unit based compensation expense for DERs paid in relation to Phantom Units that have been forfeited.

19. SUPPLEMENTAL CASH FLOW INFORMATION

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



	Nine Months Ended September 30,
	2019		2018
	(in thousands)
Cash paid for income taxes	$	904	$	626
Cash paid for interest	$	8,860	$	7,499
Cash paid for operating leases ⁽¹⁾	$	4,526	$	—

⁽¹⁾We adopted the provisions of ASC 842 as of January 1, 2019. We applied the provision of ASC 840 in years prior to 2019, which did not produce comparable amounts to disclose for the prior year.

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,
	2019		2018
	(in thousands)
Loss associated with disposal of assets	$	50	$	73
Amortization of deferred financing costs	865		646
	$	915	$	719

Non-cash activities

At September 30, 2019, accounts payable and accrued expenses included approximately $1.0 million of capital expenditures for which cash payment had not been made.

We recorded $17.3 million of right-of-use lease assets and the associated liabilities on our consolidated balance sheet as of January 1, 2019, representing non-cash activities resulting from our adoption and implementation of ASC 842, Leases. See Note 2. Recent Accounting Pronouncements and Note 7. Leases for further discussion.

20. SUBSEQUENT EVENTS

Distribution to Partners

On October 24, 2019, the board of directors of USD Partners GP LLC, acting in its capacity as our general partner, declared a quarterly cash distribution payable of $0.3675 per unit, or $1.47 per unit on an annualized basis, for the three months ended September 30, 2019. The distribution represents an increase of $0.0025 per unit, or 0.7% over the prior quarter distribution per unit, and is 27.8% over our minimum quarterly distribution per unit. The distribution will be paid on November 14, 2019, to unitholders of record at the close of business on November 4, 2019. The distribution will include payment of $5.5 million to our public common unitholders, an aggregate of $4.2 million to USDG as a holder of our common units and the sole owner of our subordinated units and $351 thousand to USD Partners GP LLC for its general partner interest and as holder of the IDRs.

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

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

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

Overview

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

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

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

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

Recent Developments

Market Update

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

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

In December 2018, the Alberta Government announced that it would curtail crude oil and bitumen production by 325,000 bpd beginning January 1, 2019, to an allowed production level of 3.56 million bpd. The Alberta Government’s objective was to reduce inventory levels to a targeted level to ensure more economical prices for WCS. In late August 2019, the Alberta Government announced changes to the curtailment policy including extending the curtailment end date to December 31, 2020, with possible earlier termination.

During 2019 to date, the Alberta Government has announced reductions to the curtailment level and increased the allowed production levels as depicted in the following chart:



Production Month		Allowed Production Level (Million barrels per day)
January 2019		3.56
February and March 2019		3.63
April 2019		3.66
May 2019		3.68
June and July 2019		3.71
August 2019		3.74
September 2019		3.76
October 2019		3.79
November 2019		3.80
December 2019		3.81

In late October 2019, the Alberta Government announced a special production allowance, whereby beginning with the December 2019 production month, producers will be allowed to produce above their curtailment order, as long as this extra production is shipped out of Alberta through additional rail capacity, which could increase demand for the transloading services of our Hardisty terminal and those of Hardisty South.

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

In response to the Alberta Government’s efforts discussed above, the WCS to West Texas Intermediate, or WTI, crude oil spread narrowed to between $9-$15 per barrel during the third quarter of 2019 as compared to $11-$50 per barrel during the fourth quarter of 2018. Additionally, apportionment levels on the primary heavy crude oil pipelines of the largest export pipeline system from Western Canada to the U.S. have averaged approximately 44% and apportionment on the light crude oil pipelines on the system have averaged approximately 28% during the third quarter of 2019 (representing the percentage of barrels nominated that were not shipped due to pipeline capacity constraints). Additionally, although inventory levels have decreased in 2019, they still remain high.

Future WCS versus WTI spreads published by Bloomberg through 2023 average approximately $20 per barrel and are indicative of the continued expected imbalance between supply and takeaway capacity. The latest data available as published by the U.S. Energy Information Administration, or EIA, indicates Canadian crude-by-rail imports into the United States increased to approximately 285,000 bpd through July 2019 on a year-to-date basis. This represents an approximate 53% increase in crude-by-rail imports from Canada into the United States over the 2018 comparative period and a 20% increase over the 2018 yearly average. As such, based on current customer indications, we expect future demand for and utilization of our terminals to be higher.

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

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

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

Commercial Developments

Hardisty Terminal

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

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

Additionally, in connection with the July 2019 renewal of the terminalling services agreement with the investment grade customer of our Hardisty terminal discussed above, the same customer entered into a multi-year renewal and extension of the terminalling services agreement with USDM that covers approximately 30% of the destination capacity at the Stroud terminal. The renewal was effective from the expiration date of the original agreement in June 2019. This agreement between the customer and USDM is subject to the Marketing Services Agreement established between

USDM and our Stroud terminal at the time of the Stroud purchase. Pursuant to the Marketing Services Agreement, USDM will pay us a nominal fee for all throughput under this agreement in excess of the throughput necessary for the Stroud terminal to generate Adjusted EBITDA that is at least equal to the average monthly Adjusted EBITDA derived from the initial Stroud terminal customer, which nominal fee generally covers our costs to operate the Stroud terminal.

Casper Terminal

The Casper terminal receives inbound crude oil primarily through our dedicated direct pipeline connection from Enbridge’s Express Pipeline, which is subsequently loaded onto unit or manifest trains.

The Casper Terminal executed an agreement with a multi-national, investment grade customer for an initial three-year term commencing September 1, 2018. The agreement contains take-or-pay terms for terminalling and storage services, as well as fees associated with actual throughput volumes and other services. Pursuant to this agreement and to supplement rail loading options from the terminal, we are constructing an outbound pipeline connection from the Casper Terminal to the nearby Platte Terminal located at the termination point of the Express pipeline. In the event the outbound pipeline is not placed into service on or before November 30, 2019, the customer has the right, in its sole discretion, to terminate the agreement upon 30 days prior notice. If the Casper Terminal agreement is terminated, then we may recognize an impairment of the Casper Terminal’s goodwill, and we may be unable to replace the cash flows derived from this agreement on a long-term contracted basis. We have completed construction of the outbound pipeline and it will be placed into service upon completion of the connection to the Platte Terminal. Based on discussions with the owner of the Platte Terminal, who is responsible for constructing the connection with our outbound pipeline, we currently expect the connection to be completed and the outbound pipeline to be placed into service during December 2019. Based on discussions with our customer, we do not expect the agreement to be terminated should the in-service date occur after the deadline in the agreement. However, we can provide no assurances as to the ultimate outcome of the situation.

In July 2019, Enbridge announced a program to increase the capacity of the Express pipeline by up to an additional 50,000 bpd with the use of drag reducing agent, or DRA, and pump stations. Enbridge anticipates that the additional capacity of 50,000 bpd will be placed into service in the first quarter of 2020. We anticipate that some of the additional volumes resulting from the increased capacity on the Express pipeline could be delivered to our Casper terminal, as we believe outbound pipeline connections from the Express pipeline and nearby terminals are at or near full capacity.

How We Generate Revenue

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

Terminalling Services

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

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

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

Our Casper terminal is a crude oil storage, blending and railcar loading terminal. The terminal currently offers six storage tanks with 900,000 bbls of total capacity, unit train-capable railcar loading capacity in excess of 100,000 bpd, as well as truck transloading capacity. Our Casper terminal is supplied with multiple grades of Canadian crude oil through a direct connection with the Express Pipeline. Additionally, the Casper terminal has a connection from the Platte terminal, where it has access to other pipelines and can receive other grades of crude oil, including locally sourced Wyoming sour crude oil. The Casper terminal can also receive volumes through one truck unloading station and is also equipped with one truck loading station. In connection with an agreement that was executed in 2018, we are constructing an outbound pipeline connection from the Casper terminal to complement our existing inbound pipeline connection and we may construct additional storage tanks to facilitate blending and staging operations for our customers, if needed. We have completed construction of the outbound pipeline and expect the connection to the Platte Terminal to be completed in December 2019.

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

Fleet Services

We provide our customers with leased railcars and fleet services related to the transportation of liquid hydrocarbons and biofuels by rail on multi-year, take-or-pay terms under master fleet services agreements for initial periods ranging from five to nine years. We do not own any railcars. As of September 30, 2019, our railcar fleet consisted of 1,683 railcars, which we leased from various railcar manufacturers and financial entities, including 1,308 coiled and insulated, or C&I, railcars. We have assigned certain payment and performance obligations under the leases and master fleet service agreements for 1,483 of the railcars to other parties, but we have retained certain rights and obligations with respect to the servicing of these railcars. The weighted average remaining contract life on our railcar fleet is 2.5 years as of September 30, 2019.

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

How We Evaluate Our Operations

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

Adjusted EBITDA and Distributable Cash Flow

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


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


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

We define Distributable Cash Flow, or DCF, as Adjusted EBITDA less net cash paid for interest, income taxes and maintenance capital expenditures. DCF does not reflect changes in working capital balances. DCF is a non-GAAP,

supplemental financial measure used by management and by external users of our financial statements, such as investors and commercial banks, to assess:


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


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


•	the sustainability of our current distribution rate per unit.

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

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(in thousands)
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA and Distributable cash flow:
Net cash provided by operating activities	$	14,648		$	12,628		$	34,155		$	32,216
Add (deduct):
Amortization of deferred financing costs	(208		)	(216		)	(865		)	(646		)
Deferred income taxes	(104		)	731			299			3,269
Changes in accounts receivable and other assets	(2,498		)	(5,836		)	(200		)	578
Changes in accounts payable and accrued expenses	(9		)	4,767			(2,018		)	1,789
Changes in deferred revenue and other liabilities	(2,666		)	150			(5,128		)	386
Interest expense, net	2,983			2,827			9,133			8,025
Provision for (benefit from) income taxes	414			(430		)	612			(2,247		)
Foreign currency transaction loss (gain) ⁽¹⁾	35			(89		)	237			(183		)
Other income	(27		)	—			(69		)	—
Non-cash deferred amounts ⁽²⁾	1,435			(51		)	1,545			(154		)
Adjusted EBITDA	14,003			14,481			37,701			43,033
Add (deduct):
Cash paid for income taxes	(297		)	(177		)	(904		)	(626		)
Cash paid for interest	(3,045		)	(2,678		)	(8,860		)	(7,499		)
Maintenance capital expenditures	(131		)	(18		)	(176		)	(98		)
Distributable cash flow	$	10,530		$	11,608		$	27,761		$	34,810


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

⁽²⁾

Operating Costs

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

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

Volumes

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


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


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


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

General Trends and Outlook

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

Casper Terminal Customer Contract Renewals and Expirations

One of the existing terminalling services agreements at our Casper Terminal expired at the end of August 2019 and was not renewed or extended. The expired agreement contributed approximately $9.3 million to our “Terminalling Services” revenue and approximately $6.5 million of Adjusted EBITDA during the twelve months preceding the expiration of the agreement. We continue to seek other opportunities to enhance the utilization and profitability of the Casper terminal with other producers, refiners and marketers of crude oil. For example, in late 2018, we executed a three-year agreement with an investment-grade rated customer at the Casper Terminal. Additionally, we have entered into a one-year terminalling service agreement, effective January 1, 2019, which contains take-or-pay terms for storage services and variable fees associated with actual throughput volumes and other services. Our ability to secure additional commercial opportunities and replace the revenue previously generated under the expired contract may be limited until our recently completed outbound pipeline is connected to the Platte Terminal, which we expect to occur in December

2019, and Enbridge successfully completes its DRA project, which we expect to occur in the first quarter of 2020. We cannot make any assurances regarding the success of Enbridge’s DRA project or the outcome of our efforts.

Factors Affecting the Comparability of Our Financial Results

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

Income Taxes

In conjunction with our adoption of ASC 606 in the prior year, we recognized a deferred tax liability associated with the previously deferred revenues net of previously deferred pipeline fees. We recovered a portion of that deferred tax liability during the three and nine months ended September 30, 2018. For Canadian tax purposes, the previously deferred revenue, net of previously deferred expenses associated with our adoption of ASC 606 was fully recognized ratably during 2018. The deferred tax recovery of $0.9 million (representing C$1.2 million) for the three months ended September 30, 2018, and $2.7 million (representing C$3.6 million) for the nine months ended September 30, 2018, was partially offset by the Canadian tax liability attributable to our current earnings for the three and nine months ended September 30, 2018. Our financial results for the three and nine months ended September 30, 2019 were not affected by similar activities.

RESULTS OF OPERATIONS

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

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(in thousands)
Operating income (loss)
Terminalling services	$	8,466		$	10,593		$	25,165		$	31,542
Fleet services	25			(162		)	30			(1		)
Corporate and other	(2,760		)	(2,609		)	(8,882		)	(8,458		)
Total operating income	5,731			7,822			16,313			23,083
Interest expense	3,005			2,827			9,174			8,025
Loss (gain) associated with derivative instruments	220			(413		)	1,966			(1,823		)
Foreign currency transaction loss (gain)	35			(89		)	237			(183		)
Other expense (income), net	(49		)	(1		)	(52		)	71
Provision for (benefit from) income taxes	414			(430		)	612			(2,247		)
Net income	$	2,106		$	5,928		$	4,376		$	19,240

Summary Analysis of Operating Results

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


•	activities associated with our terminalling services business including:


–	higher rates on certain of our terminalling services agreements at our Hardisty terminal that became effective July 1, 2019;


–	higher revenues at our Stroud terminal from two new contracts and price escalations; and


–	lower depreciation resulting from a revised estimate of the asset retirement obligation associated with our San Antonio terminal;


–	offsetting the above increases were lower operating income resulting from the conclusion of contracts at our Casper terminal in December 2018 and August 2019;


–	increased costs associated with subcontracted rail services at our Hardisty terminal; and


–	increased maintenance costs at our Stroud terminal related to our steaming equipment.


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


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


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

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

RESULTS OF OPERATIONS — BY SEGMENT

TERMINALLING SERVICES

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(in thousands)
Revenues
Terminalling services	$	28,168		$	27,785		$	79,059		$	82,000
Freight and other reimbursables	220			302			748			1,065
Total revenues	28,388			28,087			79,807			83,065
Operating costs
Subcontracted rail services	3,689			3,674			10,953			10,047
Pipeline fees	5,411			5,267			15,374			16,109
Freight and other reimbursables	220			302			748			1,065
Operating and maintenance	3,934			1,634			7,622			4,362
Selling, general and administrative	1,368			1,346			4,628			4,133
Depreciation and amortization	5,300			5,271			15,317			15,807
Total operating costs	19,922			17,494			54,642			51,523
Operating income	8,466			10,593			25,165			31,542
Foreign currency transaction loss (gain)	33			(30		)	(62		)	32
Other expense (income), net	(45		)	(1		)	(44		)	71
Provision for (benefit from) income taxes	406			(431		)	596			(2,265		)
Net income	$	8,072		$	11,055		$	24,675		$	33,704
Average daily terminal throughput (bpd)	131,482			121,983			110,829			98,936

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

Terminalling Services Revenue

Revenue generated by our Terminalling services segment increased $0.3 million to $28.4 million for the three months ended September 30, 2019, as compared with $28.1 million for the three months ended September 30, 2018. This increase was primarily due to higher revenue at our Hardisty terminal as a result of higher rates on a portion of our terminalling services agreements that became effective July 1, 2019 due to our re-contracting efforts. The increase in revenue at our Hardisty terminal was partially offset by revenue that we deferred for the three months ended September 30, 2019 associated with the make-up right options we granted to customers of our Hardisty terminal that are expected to be exercised prior to the end of 2019. Additionally, we had lower revenue at our Casper terminal resulting from the conclusion of customer agreements at the end of 2018 and in August 2019.

Average daily terminal throughput increased 9,499 bpd to 131,482 bpd for the three months ended September 30, 2019, as compared with 121,983 bpd for the three months ended September 30, 2018. Our throughput volumes increased primarily as a result of increased Western Canadian crude oil production and constrained pipeline takeaway capacity out of the region, which increased the demand for and utilization of our terminalling services by customers of our Hardisty terminal. Additionally, deliveries to our Stroud terminal increased as a result of the widening spreads between WTI and WCS, which makes delivery into the Cushing oil hub an economically favorable destination. Partially offsetting the increased utilization of our Hardisty and Stroud terminals was decreased utilization of the capacity

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

Our terminalling services revenue for the three months ended September 30, 2019, would have been $0.2 million more if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the three months ended September 30, 2019, was the same as the average exchange rate for the three months ended September 30, 2018. The average exchange rate for the Canadian dollar in relation to the U.S. dollar was 0.7575 for the three months ended September 30, 2019 as compared with 0.7652 for three months ended September 30, 2018.

Operating Costs

The operating costs of our Terminalling services segment increased $2.4 million to $19.9 million for the three months ended September 30, 2019, as compared with $17.5 million for the three months ended September 30, 2018. The increase is primarily due to expenses incurred pursuant to a new servicing agreement at our Hardisty terminal, as discussed below under “Operating and maintenance.”

Our terminalling services operating costs for the three months ended September 30, 2019, would have been $0.1 million more if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the three months ended September 30, 2019, was the same as the average exchange rate for the three months ended September 30, 2018.

Operating and maintenance. Our operating and maintenance costs increased $2.3 million to $3.9 million for the three months ended September 30, 2019 as compared with $1.6 million for the three months ended September 30, 2018. This increase was primarily due to expenses incurred pursuant to a new agreement whereby a related party will provide terminalling services to a customer of our Hardisty terminal for contracted capacity that exceeds the current transloading capacity available at our Hardisty Terminal. These costs represent the same rate, on a per barrel basis, that we received as revenue from our third-party customer, which produced the higher revenues from our Hardisty terminal, as discussed above.

Other Expenses

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

Our income taxes for the Terminalling services segment increased $0.8 million to a provision of $0.4 million for the three months ended September 30, 2019, from a $0.4 million benefit from income taxes for the three months ended September 30, 2018. In connection with our adoption of ASC 606, in 2018, we recovered a deferred tax liability associated with previously deferred revenues net of previously deferred pipeline fees. During the three months ended September 30, 2018, we recovered $0.9 million (C$1.2 million), representing a portion of that deferred tax liability, which produced a benefit from income taxes. We did not have a similar recovery of a deferred tax liability during the three months ended September 30, 2019.

Nine months ended September 30, 2019 compared with nine months ended September 30, 2018

Terminalling Services Revenue

Revenue generated by our Terminalling services segment decreased $3.3 million to $79.8 million for the nine months ended September 30, 2019, as compared with $83.1 million for the nine months ended September 30, 2018. This decrease was primarily due to lower revenue at our Casper terminal resulting from the conclusion of customer agreements at the end of 2018 and August 2019, partially offset by additional contracts that we have executed and our commercial efforts to market the available capacity. Additionally, we deferred revenue from our Hardisty terminal during the third quarter of 2019 associated with the make-up right options we granted to our customers that are expected to be exercised prior to the end of 2019. These factors contributing to the decrease in terminalling services revenue were partially offset by increased revenue at our Hardisty terminal resulting from higher rates included in some of our terminalling services agreements that became effective July 1, 2019 due to our re-contracting efforts. The revenue at our Stroud terminal also increased due to price escalations.

Our average daily terminal throughput increased 11,893 bpd to 110,829 bpd for the nine months ended September 30, 2019 as compared with 98,936 bpd for the nine months ended September 30, 2018. Our throughput volumes increased primarily due to the increased demand for export capacity by customers of our Hardisty terminal a portion of which drives the demand for deliveries to our Stroud terminal and its connection to the Cushing oil hub. The volume increases at our Hardisty and Stroud terminals were partially offset by lower throughput volumes at our Casper terminal. The increased demand associated with our Hardisty terminal resulted from increased Western Canadian crude oil production and constrained pipeline takeaway capacity out of the region during the first nine months of 2019. Our terminalling services revenues are recognized based upon the contractual terms set forth in our agreements that contain primarily “take-or-pay” provisions, where we are entitled to the payment of minimum monthly commitment fees from our customers, which are recognized as revenue as we provide terminalling services. Increases in the average daily terminal throughput activity usually only affect revenue to the extent such amounts are in excess of the minimum monthly committed volumes. However, increases in actual and expected throughput activity can result in increases in the variable operating costs associated with our terminals, as discussed below.

Our terminalling services revenue for the nine months ended September 30, 2019, would have been $1.6 million more if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the nine months ended September 30, 2019, was the same as the average exchange rate for the nine months ended September 30, 2018. The average exchange rate for the Canadian dollar in relation to the U.S. dollar was 0.7524 for the nine months ended September 30, 2019 as compared with 0.7769 for the nine months ended September 30, 2018.

Operating Costs

The operating costs of our Terminalling services segment increased $3.1 million to $54.6 million for the nine months ended September 30, 2019, as compared with the $51.5 million for the nine months ended September 30, 2018. The increase is primarily attributable to expenses incurred pursuant to a new servicing agreement at our Hardisty terminal, as discussed below under “Operating and maintenance,” coupled with additional variable operating costs at our Hardisty and Stroud terminals resulting from subcontracted rail service costs that increased due to higher throughput volumes. We also incurred increased operating costs at our Stroud terminal in connection with utilization of the steaming equipment we installed for alleviating unloading issues due to cold weather. These costs were partially offset by a decrease in pipeline fees and depreciation expense, as discussed in more detail below.

Our terminalling services operating costs for the nine months ended September 30, 2019, would have been $0.9 million more if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the nine months ended September 30, 2019, was the same as the average exchange rate for the nine months ended September 30, 2018.

Subcontracted rail services. Our subcontracted rail services costs increased $0.9 million to $11.0 million for the nine months ended September 30, 2019, as compared with the nine months ended September 30, 2018. This increase was primarily due to the increased throughput at our Stroud terminal associated with the additional contracts that were executed in March and April of 2018 and increased throughput at our Hardisty terminal, offset by a reduction in such services at our Casper terminal resulting from the conclusion of customer agreements at the end of 2018 and in August 2019.

Pipeline fees. We incur pipeline fees related to a facilities connection agreement with Gibson for the delivery of crude oil from Gibson’s Hardisty storage terminal to our Hardisty terminal via pipeline. The pipeline fees we pay to Gibson are based on a predetermined formula, which includes amounts collected from customers at our Hardisty terminal less direct operating costs. Our pipeline fees decreased $0.7 million to $15.4 million for the nine months ended September 30, 2019 as compared with $16.1 million for the nine months ended September 30, 2018, primarily due to higher direct operating costs, which reduce the amounts we pay to Gibson, partially offset by higher revenues at our Hardisty terminal. Additionally, we deferred pipeline fees during the nine months ended September 30, 2019, associated with the revenue we deferred for our customers’ expected future use of make-up rights at our Hardisty terminal, as discussed above. We will recognize the expense for pipeline fees concurrently with our recognition of the related revenue.

Operating and maintenance. Operating and maintenance expense increased $3.3 million to $7.6 million for the nine months ended September 30, 2019 as compared with the nine months ended September 30, 2018. The increased operating and maintenance expenses are primarily due to expenses incurred pursuant to a new agreement with a related party for providing terminalling services on our behalf to a customer of our Hardisty terminal for contacted capacity that exceeds the current transloading capacity available at our Hardisty terminal. These costs represent the same rate, on a per barrel basis, that we received as revenue from our third-party customer, which produced the higher revenues from our Hardisty terminal, as discussed above. Additionally, we incurred higher costs for operating the steaming equipment at our Stroud terminal, which was placed into service in July 2018 to alleviate unloading issues related to cold weather at the terminal. We also incurred higher repairs and maintenance expenses at our Hardisty and Stroud terminals primarily due to increased transloading volumes.

Selling, general and administrative. Our selling, general and administrative costs increased $0.5 million to $4.6 million for the nine months ended September 30, 2019, as compared with $4.1 million for the nine months ended September 30, 2018. This increase was primarily due to higher compliance consulting and legal costs at our Casper terminal.

Depreciation and amortization. Depreciation and amortization expense decreased $0.5 million to $15.3 million for the nine months ended September 30, 2019 from $15.8 million for the nine months ended September 30, 2018. The decrease is due to a revised estimate of our asset retirement obligations, or ARO, associated with our San Antonio facility that we recorded during the first quarter of 2019.

Other Expenses

Our income taxes for the Terminalling services segment increased $2.9 million to a provision of $0.6 million for the nine months ended September 30, 2019, from a benefit of $2.3 million from income taxes for the nine months ended September 30, 2018. In connection with our adoption of ASC 606, in 2018, we recovered a deferred tax liability associated with previously deferred revenues net of previously deferred pipeline fees. During the nine months ended September 30, 2018, we recovered $2.7 million (C$3.6 million), representing a portion of that deferred tax liability, which produced a benefit from income taxes. We did not have a similar recovery of a deferred tax liability during the nine months ended September 30, 2019.

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,
	2019			2018			2019		2018
	(in thousands)
Revenues
Fleet leases	$	984		$	984		$	2,951	$	2,951
Fleet services	277			307			840		1,187
Freight and other reimbursables	245			208			479		1,693
Total revenues	1,506			1,499			4,270		5,831
Operating costs
Freight and other reimbursables	245			208			479		1,693
Operating and maintenance	1,018			1,052			3,051		3,178
Selling, general and administrative	218			401			710		961
Total operating costs	1,481			1,661			4,240		5,832
Operating income (loss)	25			(162		)	30		(1		)
Foreign currency transaction loss (gain)	(2		)	3			6		(4		)
Provision for income taxes	8			5			16		21
Net income (loss)	$	19		$	(170	)	$	8	$	(18	)

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

Revenues from our Fleet services segment remained relatively constant at $1.5 million for the three months ended September 30, 2019, and for the three months ended September 30, 2018. Selling, general and administrative costs of our Fleet services segment decreased $0.2 million to $0.2 million for the three months ended September 30, 2019, as compared with $0.4 million for three months ended September 30, 2018. The decrease in selling, general and administrative costs is primarily due to higher consulting fees in the three months ended September 30, 2018.

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

Nine months ended September 30, 2019 compared with nine months ended September 30, 2018

Revenues from our Fleet services segment decreased $1.6 million to $4.3 million for the nine months ended September 30, 2019, as compared with the nine months ended September 30, 2018. The decrease in revenue was primarily attributable to fewer customer reimbursements to us for freight and other reimbursable charges that we have incurred on their behalf. The decrease in Freight and other reimbursables revenue was exactly offset by a corresponding decrease in Freight and other reimbursables operating costs that primarily arose from railcar repairs and returns, which occurred during the nine months ended September 30, 2018. We did not incur similar costs during the nine months ended September 30, 2019 as we had no returns of railcars during this period. Additionally, fleet services revenues decreased over the prior year associated with approximately 500 fewer railcars outstanding for which we provided fleet services, as compared with the same period in 2018. Selling, general and administrative costs of our Fleet services segment decreased $0.3 million to $0.7 million for the nine months ended September 30, 2019, as compared with

$1.0 million for the nine months ended September 30, 2018. The decrease in selling, general and administrative costs is primarily due to higher consulting fees in the nine months ended September 30, 2018.

CORPORATE ACTIVITIES

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(in thousands)
Operating costs
Selling, general and administrative	$	2,760		$	2,609		$	8,882		$	8,458
Operating loss	(2,760		)	(2,609		)	(8,882		)	(8,458		)
Interest expense	3,005			2,827			9,174			8,025
Loss (gain) associated with derivative instruments	220			(413		)	1,966			(1,823		)
Foreign currency transaction loss (gain)	4			(62		)	293			(211		)
Other income, net	(4		)	—			(8		)	—
Provision for (benefit from) income taxes	—			(4		)	—			(3		)
Net loss	$	(5,985	)	$	(4,957	)	$	(20,307	)	$	(14,446	)

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

Costs associated with our corporate activities increased $1.0 million to $6.0 million for the three months ended September 30, 2019. Our “Interest expense” increased $0.2 million to $3.0 million, due to an increase in the interest rates we were charged under our Credit Agreement, as well as a higher weighted average balance of debt outstanding during the three months ended September 30, 2019, as compared with the same period of 2018. Also contributing to the increase in costs associated with our corporate activities during the three months ended September 30, 2019 was a non-cash loss of $0.2 million associated with our interest rate derivatives as compared with a non-cash gain of $0.4 million for the corresponding period in 2018.

Nine months ended September 30, 2019 compared with nine months ended September 30, 2018

Costs associated with our corporate activities increased $5.9 million to $20.3 million for the nine months ended September 30, 2019, for the same reasons cited above in our three month analysis. In addition, however, our “Selling, general and administrative” expenses increased $0.4 million to $8.9 million for the nine months ended September 30, 2019 as compared with the same period of 2018, primarily due to additional unit based compensation expense associated with the Phantom Units granted in February 2019 to directors and employees of our general partner and its affiliates.

LIQUIDITY AND CAPITAL RESOURCES

Our principal liquidity requirements include:


•	financing current operations;


•	servicing our debt;


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


•	making distributions to our unitholders.

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

Liquidity Sources

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

For information regarding our Credit Agreement, please see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Agreement in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018 and Part I. Item 1. Financial Statements, Note 9. Debt of this Quarterly Report.

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



	September 30, 2019		December 31, 2018
	(in millions)
Cash and cash equivalents ⁽¹⁾	$	6.5	$	6.4
Aggregate borrowing capacity under Credit Agreement	385.0		385.0
Less: Revolving Credit Facility amounts outstanding	216.0		209.0
Letters of credit outstanding	—		0.6
Total available liquidity ⁽²⁾	$	175.5	$	181.8


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


⁽²⁾	Pursuant to the terms of our Credit Agreement, our borrowing capacity currently is limited to 4.5 times our trailing 12-month consolidated EBITDA, which equates to approximately $37 million of availability at September 30, 2019.

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

Cash Flows

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



	Nine Months Ended September 30,
	2019			2018
	(in thousands)
Net cash provided by (used in):
Operating activities	$	34,155		$	32,216
Investing activities	(7,072		)	(207		)
Financing activities	(25,840		)	(31,923		)
Effect of exchange rates on cash	497			(679		)
Net change in cash, cash equivalents and restricted cash	$	1,740		$	(593	)

Operating Activities

Net cash provided by operating activities increased $1.9 million to $34.2 million for the nine months ended September 30, 2019, as compared with the nine months ended September 30, 2018. The increase in Net cash provided by operating activities was primarily due to the timing of receipts and payments on accounts receivable, accounts payable and deferred revenue balances.

Investing Activities

Net cash used in investing activities increased to $7.1 million for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018 primarily due to the pipeline construction at the Casper terminal.

Financing Activities

Net cash used in financing activities decreased to $25.8 million for the nine months ended September 30, 2019 from $31.9 million for the nine months ended September 30, 2018. Our proceeds from long-term debt during the nine months ended September 30, 2019 were $8.0 million higher than the amounts we borrowed during the nine months ended September 30, 2018. We used these proceeds to fund construction of the outbound pipeline at our Casper terminal. Partially offsetting the cash provided from our borrowing activities, are increases in cash we used during the nine months ended September 30, 2019, for cash distributions and participant withholding taxes associated with vested Phantom Units, both of which exceeded amounts paid during the nine months ended September 30, 2018, for similar items.

Cash Requirements

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

Capital Requirements

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

Our partnership agreement requires that we categorize our capital expenditures as either expansion capital expenditures, maintenance capital expenditures, or investment capital expenditures. Although we have not experienced significant maintenance capital expenditures in prior years, as the age and usage of our assets increase, we expect that costs we incur to maintain them in compliance with sound business practice, our contractual relationships and applicable regulatory requirements will likely increase. Some of these costs will be characterized as maintenance capital

expenditures. We incurred $131 thousand and $176 thousand for maintenance capital expenditures during the three and nine months ended September 30, 2019, respectively.

Our total expansion capital expenditures for the nine months ended September 30, 2019 were $6.9 million, primarily used for construction of the outbound pipeline connection from the Casper Terminal to the Platte Terminal. We expect to fund future capital expenditures from cash on our balance sheet, cash flow generated from our operating activities, borrowings under our Credit Agreement and the issuance of additional partnership interests or long-term debt.

Debt Service

We anticipate reducing our outstanding indebtedness to the extent we generate cash flows in excess of our operating, investing and distribution needs. During the nine months ended September 30, 2019, we received proceeds from borrowings of $28.0 million on our Revolving Credit Facility which we used for general partnership purposes and made repayments of $21.0 million on our Revolving Credit Facility from cash flow in excess of our operating and investing needs.

Distributions

We intend to pay a minimum quarterly distribution of at least $0.2875 per unit per quarter. Our current quarterly distribution of $0.3675 per unit that we expect to pay, equates to $10.1 million per quarter, or $40.4 million per year, based on the number of common, subordinated, and general partner units outstanding as of November 4, 2019. We do not have a legal obligation to distribute any particular amount per common unit. Additionally, members of our general partner’s board of directors appointed by Energy Capital Partners must approve any distributions made by us.

Other Items Affecting Liquidity

Credit Risk

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

Foreign Currency Exchange Risk

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

SUBSEQUENT EVENTS

Refer to Note 20. Subsequent events of our consolidated financial statements included in Part I — Financial Information, Item 1. Financial Statements of this Report for a discussion regarding subsequent events.

RECENT ACCOUNTING PRONOUNCEMENTS — NOT YET ADOPTED

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

OFF BALANCE SHEET ARRANGEMENTS

In the normal course of business, we are a party to off-balance sheet arrangements relating to various master fleet services agreements, whereby we have agreed to assign certain payment and other obligations to third party special

purpose entities that are not consolidated with us. We have also entered into agreements to provide fleet services to these special purpose entities for fixed servicing fees and reimbursement of out-of-pocket expenses. The purpose of these transactions is to remove the risk to us of non-payment by our customers, which would otherwise negatively impact our financial condition and results of operations. For more information on these special purpose entities, see the discussion of our relationship with the variable interest entities described in Note 11. Nonconsolidated Variable Interest Entities to our consolidated financial statements included in Part I — Financial Information, Item 1. Financial Statements of this Report. Assets and liabilities related to these arrangements are generally not reflected in our consolidated balance sheets, and we do not expect any material impact on our cash flows, results of operations or financial condition as a result of these off-balance sheet arrangements.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

There have been no changes to our critical accounting policies and estimates described in the Annual Report on Form 10-K for the year ended December 31, 2018, that have had a material impact on our consolidated financial statements and related notes, 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 $33.6 million balance of our goodwill originated from our acquisition of the Casper terminal in November 2015 and is wholly attributed to this reporting unit. We measured the fair value of our Casper terminal reporting unit using customary business valuation techniques including an income analysis, market analysis and transaction analysis, which we weighted at 50%, 25% and 25%, respectively. Our weighting of the measurement methods is consistent with weightings used to value organizations that are similar to the Casper terminal reporting unit. The critical assumptions used in our analysis include the following:


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


(2)	A range of incremental volumes expected at our Casper terminal of approximately 20,000 to 40,000 bpd for terminalling and storage services resulting from the anticipated successful completion of the Enbridge DRA project in the first quarter of 2020;


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


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


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


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

The key assumptions listed above were based upon economic and other operational conditions existing at or prior to the July 1, 2019, valuation date. Our weighted average cost of capital is subject to variability and is dependent upon such factors as changes in benchmark rates of interest established by the Federal Open Market Committee of the Federal Reserve Board, the British Bankers Association and other central banking regulatory authorities, as well as perceptions of risk and market uncertainty regarding our business, industry and those of our peers and our underlying capital structure. We expect our long-term underlying capital structure to approximate a weighting of 50% debt and 50% equity. Each of the above assumptions are likely to change due to economic uncertainty surrounding global and North American energy markets that are highly correlated with crude oil, natural gas and other energy-related commodity prices and other market factors.

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

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

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

As indicated above, our estimate of fair value for the Casper terminal reporting unit required us to use significant unobservable inputs representative of Level 3 fair value measurements, including assumptions related to the future performance of our Casper terminal. During the third quarter of 2019, 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, 2019. 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, 2019.

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 2019, 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, 2019. 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, 2019. 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;


•	Incremental volumes at our Casper terminal of approximately 20,000 to 40,000 bpd for terminalling and storage services resulting from the anticipated successful completion of the Enbridge DRA project in the first quarter of 2020, as discussed above in Recent Developments — Commercial Developments — Casper Terminal;


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


•	A six 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 six year remaining life of the primary asset.

To the extent that our assumptions as set forth above do not materialize, 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.

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


Item 4.	Controls and Procedures.

DISCLOSURE CONTROLS AND PROCEDURES

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended, or the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2019. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow for timely decisions regarding required disclosure and to ensure information is recorded, processed, summarized and reported

within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2019, at the reasonable assurance level.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

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

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

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

Item 6. Exhibits

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



		Index of Exhibits
Exhibit Number		Description

3.1		Certificate of Limited Partnership of USD Partners LP (incorporated by reference herein to Exhibit 3.1 to the Registration Statement on Form S-1 (File No. 333-198500) filed on August 29, 2014, as amended).

3.2		Second Amended and Restated Agreement of Limited Partnership of USD Partners LP dated October 15, 2014, by and between USD Partners GP LLC and USD Group LLC (incorporated by reference herein to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-36674) filed on October 21, 2014).

31.1*		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

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

101.INS*		XBRL Instance Document

101.SCH*		XBRL Schema Document

101.CAL*		XBRL Calculation Linkbase Document

101.LAB*		XBRL Labels Linkbase Document

101.PRE*		XBRL Presentation Linkbase Document

101.DEF*		XBRL Definition Linkbase Document


*	Filed herewith.


**	Furnished herewith.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		USD PARTNERS LP (Registrant)

		By:	USD Partners GP LLC, its General Partner

Date:	November 7, 2019	By:	/s/ Dan Borgen
			Dan Borgen Chief Executive Officer and President (Principal Executive Officer)

Date:	November 7, 2019	By:	/s/ Adam Altsuler
			Adam Altsuler Senior Vice President and Chief Financial Officer (Principal Financial Officer)