USD Partners LP - Quarter Report: 2020 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended September 30, 2020


☐			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 ☒ 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 ☒ 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

☒

Non-accelerated filer

☐

Smaller reporting company

☒

Emerging growth company

☐

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. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

As of November 2, 2020, there were 26,844,337 common units and 461,136 general partner units outstanding.

TABLE OF CONTENTS


PART I — FINANCIAL INFORMATION

Item 1.	Financial Statements
	Consolidated Statements of Operations	1
	Consolidated Statements of Comprehensive Income (Loss)	2
	Consolidated Statements of Cash Flows	3
	Consolidated Balance Sheets	4
	Consolidated Statements of Partners’ Capital	5
	Notes to the Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	61
Item 4.	Controls and Procedures	61

PART II — OTHER INFORMATION

Item 1.	Legal Proceedings	62
Item 1A.	Risk Factors	62
Item 6.	Exhibits	62
SIGNATURES		64

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) the impact of the novel coronavirus (COVID-19) pandemic and related economic downturn and governmental regulations; (2) changes in general economic conditions and commodity prices; (3) the effects of competition, in particular, by pipelines and other terminalling facilities; (4) shut-downs or cutbacks at upstream production facilities, refineries or other related businesses; (5) government regulations regarding oil production, including if the Alberta Government were to resume setting production limits; (6) the supply of, and demand for, terminalling services for crude oil and biofuels; (7) the price and availability of debt and equity financing; (8) actions by third parties, including customers, lenders, construction-related services providers, and our sponsors; (9) hazards and operating risks that may not be covered fully by insurance; (10) disruptions due to equipment interruption or failure at our facilities or third-party facilities on which our business is dependent; (11) natural disasters, weather-related delays, casualty losses and other matters beyond our control; (12) changes in laws or regulations to which we are subject, including compliance with environmental and operational safety regulations, that may increase our costs or limit our operations; and (13) our ability to successfully identify and finance potential 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, 2019 and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, each of 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 OPERATIONS


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(unaudited; in thousands of US dollars, except per unit amounts)
Revenues
Terminalling services	$	28,905	$	23,709	$	75,449	$	63,437
Terminalling services — related party	1,041		4,459		8,929		15,622


Fleet leases — related party	984		984		2,951		2,951
Fleet services	51		50		152		158
Fleet services — related party	227		227		682		682
Freight and other reimbursables	64		272		750		973
Freight and other reimbursables — related party	65		193		66		254
Total revenues	31,337		29,894		88,979		84,077
Operating costs
Subcontracted rail services	2,300		3,689		8,433		10,953
Pipeline fees	5,936		5,411		17,678		15,374
Freight and other reimbursables	129		465		816		1,227
Operating and maintenance	2,299		2,481		7,944		8,202
Operating and maintenance — related party	2,102		2,471		6,194		2,471
Selling, general and administrative	2,510		2,940		8,310		8,139
Selling, general and administrative — related party	1,735		1,406		5,563		6,081
Goodwill impairment loss	—		—		33,589		—
Depreciation and amortization	5,430		5,300		16,055		15,317
Total operating costs	22,441		24,163		104,582		67,764
Operating income (loss)	8,896		5,731		(15,603)		16,313
Interest expense	2,045		3,005		7,040		9,174
Loss associated with derivative instruments	1,200		220		4,405		1,966
Foreign currency transaction loss (gain)	(246)		35		812		237
Other income, net	(33)		(49)		(876)		(52)
Income (loss) before income taxes	5,930		2,520		(26,984)		4,988
Provision for (benefit from) income taxes	(307)		414		(626)		612
Net income (loss)	$	6,237	$	2,106	$	(26,358)	$	4,376
Net income (loss) attributable to limited partner interests	$	6,131	$	1,888	$	(25,913)	$	3,817
Net income (loss) per common unit (basic and diluted)	$	0.23	$	0.08	$	(0.98)	$	0.15
Weighted average common units outstanding	26,844		24,411		26,403		23,965
Net income (loss) per subordinated unit (basic and diluted)	$	—	$	0.08	$	(0.04)	$	0.13
Weighted average subordinated units outstanding	—		2,093		382		2,476

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

USD PARTNERS LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(unaudited; in thousands of US dollars)
Net income (loss)	$	6,237	$	2,106	$	(26,358)	$	4,376
Other comprehensive income (loss) — foreign currency translation	689		(652)		(916)		1,903
Comprehensive income (loss)	$	6,926	$	1,454	$	(27,274)	$	6,279

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,
	2020		2019
	(unaudited; in thousands of US dollars)
Cash flows from operating activities:
Net income (loss)	$	(26,358)	$	4,376
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	16,055		15,317
Loss associated with derivative instruments	4,405		1,966
Settlement of derivative contracts	(631)		1
Unit based compensation expense	4,909		4,533
Deferred income taxes	(1,263)		(299)
Other	622		915
Goodwill impairment loss	33,589		—
Changes in operating assets and liabilities:
Accounts receivable	892		1,511
Accounts receivable — related party	(758)		(1,054)
Prepaid expenses and other assets	(1,303)		72
Other assets — related party	(899)		(329)
Accounts payable and accrued expenses	(609)		(411)
Accounts payable and accrued expenses — related party	(78)		2,429
Deferred revenue and other liabilities	6,218		5,590
Deferred revenue — related party	(1,031)		(462)

Net cash provided by operating activities	33,760		34,155
Cash flows from investing activities:
Additions of property and equipment	(395)		(7,072)
Net cash used in investing activities	(395)		(7,072)
Cash flows from financing activities:
Distributions	(17,020)		(30,994)
Payments for deferred financing costs	—		(7)
Vested phantom units used for payment of participant taxes	(1,789)		(1,826)

Proceeds from long-term debt	12,000		28,000
Repayments of long-term debt	(23,000)		(21,000)
Other financing activities	—		(13)
Net cash used in financing activities	(29,809)		(25,840)
Effect of exchange rates on cash	293		497
Net change in cash, cash equivalents and restricted cash	3,849		1,740
Cash, cash equivalents and restricted cash — beginning of period	10,684		12,383
Cash, cash equivalents and restricted cash — end of period	$	14,533	$	14,123

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

USD PARTNERS LP

CONSOLIDATED BALANCE SHEETS


	September 30, 2020		December 31, 2019
	(unaudited; in thousands of US dollars, except unit amounts)
ASSETS
Current assets
Cash and cash equivalents	$	6,928	$	3,083
Restricted cash	7,605		7,601
Accounts receivable, net	4,346		5,313
Accounts receivable — related party	2,508		1,778
Prepaid expenses	1,529		1,915

Other current assets	1,189		954
Other current assets — related party	35		343
Total current assets	24,140		20,987
Property and equipment, net	139,745		147,737
Intangible assets, net	64,644		74,099
Goodwill	—		33,589
Operating lease right-of-use assets	10,956		11,804
Other non-current assets	3,571		1,335
Other non-current assets — related party	1,227		15
Total assets	$	244,283	$	289,566

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable and accrued expenses	$	2,214	$	3,087
Accounts payable and accrued expenses — related party	384		465

Deferred revenue	5,607		6,104
Deferred revenue — related party	410		1,482
Operating lease liabilities, current	5,371		4,649
Other current liabilities	5,495		3,150
Total current liabilities	19,481		18,937
Long-term debt, net	207,273		217,651


Deferred income tax liabilities, net	10		458
Operating lease liabilities, non-current	5,685		7,386
Other non-current liabilities	12,111		4,078
Total liabilities	244,560		248,510
Commitments and contingencies
Partners’ capital
Common units (26,844,337 and 24,411,892 outstanding at September 30, 2020 and December 31, 2019, respectively)	(1,070)		61,013

Subordinated units (2,092,709 outstanding at December 31, 2019)	—		(22,597)
General partner units (461,136 outstanding at September 30, 2020 and December 31, 2019)	1,836		2,767
Accumulated other comprehensive loss	(1,043)		(127)
Total partners’ capital	(277)		41,056
Total liabilities and partners’ capital	$	244,283	$	289,566

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

USD PARTNERS LP

THREE MONTHS CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL


	Three Months Ended September 30,
	2020			2019
	Units	Amount		Units	Amount
	(unaudited; in thousands of US dollars, except unit amounts)
Common units
Beginning balance at July 1,	26,843,674	$	(5,670)	24,410,226	$	73,424

Common units issued for vested phantom units	663	(1)		1,054	(5)

Net income	—	6,131		—	1,739
Unit based compensation expense	—	1,599		—	1,421
Distributions	—	(3,129)		—	(9,339)
Ending balance at September 30,	26,844,337	(1,070)		24,411,280	67,240








Subordinated units
Beginning balance at July 1,	—	—		2,092,709	(21,290)

Net income	—	—		—	149

Distributions	—	—		—	(800)
Ending balance at September 30,	—	—		2,092,709	(21,941)
General Partner units
Beginning balance at July 1,	461,136	1,784		461,136	3,008

Net income	—	106		—	218

Distributions	—	(54)		—	(338)
Ending balance at September 30,	461,136	1,836		461,136	2,888
Accumulated other comprehensive loss
Beginning balance at July 1,		(1,732)			(454)
Cumulative translation adjustment		689			(652)
Ending balance at September 30,		(1,043)			(1,106)
Total partners’ capital at September 30,		$	(277)		$	47,081

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

USD PARTNERS LP

NINE MONTHS CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL


	Nine Months Ended September 30,
	2020			2019
	Units	Amount		Units	Amount
	(unaudited; in thousands of US dollars, except unit amounts)
Common units
Beginning balance at January 1,	24,411,892	$	61,013	21,916,024	$	107,903
Conversion of units	2,092,709	(23,423)		2,131,459	(19,631)
Common units issued for vested phantom units	339,736	(1,789)		363,797	(1,826)

Net income (loss)	—	(25,898)		—	3,506
Unit based compensation expense	—	4,749		—	4,154
Distributions	—	(15,722)		—	(26,866)
Ending balance at September 30,	26,844,337	(1,070)		24,411,280	67,240
Class A units
Beginning balance at January 1,	—	—		38,750	1,018
Conversion of units	—	—		(38,750)	(1,018)

Unit based compensation expense	—	—		—	14

Distributions	—	—		—	(14)
Ending balance at September 30,	—	—		—	—
Subordinated units
Beginning balance at January 1,	2,092,709	(22,597)		4,185,418	(39,723)
Conversion of units	(2,092,709)	23,423		(2,092,709)	20,637
Net income (loss)	—	(15)		—	311
Unit based compensation expense	—	—		—	2
Distributions	—	(811)		—	(3,168)
Ending balance at September 30,	—	—		2,092,709	(21,941)
General Partner units
Beginning balance at January 1,	461,136	2,767		461,136	3,275

Net income (loss)	—	(445)		—	559
Unit based compensation expense	—	1		—	—
Distributions	—	(487)		—	(946)
Ending balance at September 30,	461,136	1,836		461,136	2,888
Accumulated other comprehensive loss
Beginning balance at January 1,		(127)			(3,009)
Cumulative translation adjustment		(916)			1,903
Ending balance at September 30,		(1,043)			(1,106)
Total partners’ capital at September 30,		$	(277)		$	47,081

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. These arrangements are typically at fixed prices where we do not take commodity price exposure.

A substantial amount of the operating cash flows related to the terminalling services that we provide are generated from take-or-pay contracts with minimum monthly commitment fees 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.

Recent Events

In December 2019, a novel coronavirus disease (“COVID-19”) was reported and in March 2020, the World Health Organization declared that the spread of COVID-19 qualified as a global pandemic. The COVID-19 pandemic has adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the pandemic has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement worldwide. In addition, in March 2020, members of the Organization of the Petroleum Exporting Countries (“OPEC”) and other oil producing countries (“OPEC+”) failed to agree on oil production levels, which led to a substantial decline in oil prices and an increasingly volatile market. In April 2020, even though OPEC+ announced that it had reached an agreement to cut production by 9.7 million barrels per day, or Mmbpd, oil prices did not meaningfully increase. Governments in the United States and Canada have limited movement of people and functioning of businesses in an effort to contain the spread of COVID-19. Mandatory and voluntary closures continue and their duration and impact remains unknown. As a result of these factors, there has been a significant reduction in demand for and prices of crude oil and natural gas liquids. Even when commodity prices have increased, they have remained highly volatile and at relatively low levels that have caused many oil and gas producers to suspend or reduce development programs. In July 2020, OPEC+ agreed to taper oil production cuts, which will scale back production cuts from 9.7 Mmbpd to 7.7 Mmbpd between August 2020 and January 2021. While COVID-19 is still a global pandemic, parts of the world have started to recover and some economies have started to reopen. However, certain jurisdictions that began re-opening have returned to restrictions in light of increased numbers of new COVID-19 cases. There still remains considerable uncertainty about the ultimate impact and duration of the pandemic and its effects on the global economy.

As a result of the overall downturn in the crude market and the decline in the demand for petroleum products, we tested the goodwill associated with our Casper terminal for impairment as of March 31, 2020, which resulted in an impairment loss recognized for the nine months ended September 30, 2020. Refer to Note 8. Goodwill and Intangible Assets for further discussion of the impairment loss at the Casper terminal.

If the current depressed pricing environment continues for an extended period, it may lead to a potential additional impairment of long-lived assets and customer demand for our services may also be negatively impacted. Any material non-payment or nonperformance by any of our key customers resulting from the current market conditions could have a material adverse effect on our business, financial condition, and results of operations in future periods.

In addition, in March 2020, United States legislation referred to as the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”), was signed into law. The CARES Act is an emergency economic stimulus package enacted in response to the coronavirus outbreak which, among other measures, contains numerous income tax provisions. Refer to Note 15. Income Taxes for further discussion of the impact of the CARES Act to our income taxes.

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, including adjustments made associated with the provisions of the CARES Act discussed above, and consisting only of normal recurring adjustments, which our management considers necessary to present fairly our financial position as of September 30, 2020, our results of operations for the three and nine months ended September 30, 2020 and 2019, and our cash flows for the nine months ended September 30, 2020 and 2019. We derived our consolidated balance sheet as of December 31, 2019 from the audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019. Our results of operations for the three and nine months ended September 30, 2020 and 2019 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, 2019.

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 accounts in our statement of operations 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.

2. RECENT ACCOUNTING PROUNOUNCEMENTS

Recently Adopted Accounting Pronouncements

Intangibles - Goodwill and Other (ASU 2017-04)

In January 2017, the Financial Accounting Standards Board, or 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 adopted the provisions of ASU 2017-04 on January 1, 2020. In March 2020, we tested the goodwill associated with our Casper terminal for impairment due to there being circumstances that suggested the fair value of the Casper reporting unit was less than its carrying amount. The circumstances identified related to the overall downturn in the crude market and the decline in the demand for petroleum products, which could lead to delays or reductions of expected throughput levels and changes in expectations for current and future contracts at the Casper terminal. Refer to Note 1. Organization and Basis of Presentation — Recent Events for more information. This standard requires us to recognize an impairment loss for the amount by which the carrying amount of our Casper terminal exceeds the fair value of the terminal. Accordingly, we have recognized an impairment loss in our goodwill asset for the nine months ended September 30, 2020. Refer to Note 8. Goodwill and Intangible assets for more information.

Recent Accounting Pronouncements Not Yet Adopted

Income Taxes (ASU 2019-12)

In December 2019, the FASB issued Accounting Standards Update No. 2019-12, or ASU 2019-12, which amends ASC Topic 740 by removing certain exceptions related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. It also simplifies aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill. In addition, under the provisions of ASU 2019-12, single-member limited liability companies and similar disregarded entities that are not subject to income tax are not required to recognize an allocation of consolidated income tax expense in their separate financial statements, but they could elect to do so.

The pronouncement is effective for fiscal years beginning after December 15, 2020, or for any interim periods within those fiscal years, with early adoption permitted. We do not expect to early adopt the provisions of this standard, nor do we anticipate that our adoption of this standard will have a material impact on our financial statements.

3. NET INCOME (LOSS) PER LIMITED PARTNER INTEREST

We allocate our net income or loss 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 or loss and any net income or loss 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)Calculated as if our general partner holds the original 2% general partner interest in us, which is currently at 1.7%.

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


	For the Three Months Ended September 30, 2020
	Common Units		Subordinated Units (7)		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)	$	6,131	$	—	$	—	$	106	$	6,237
Less: Distributable earnings (2)	3,129		—		—		54		3,183
Excess net income	$	3,002	$	—	$	—	$	52	$	3,054
Weighted average units outstanding (3)	26,844		—		—		461		27,305
Distributable earnings per unit (4)	$	0.12	$	—	$	—
Underdistributed earnings per unit (5)	0.11		—		—
Net income per limited partner unit (basic and diluted) (6)	$	0.23	$	—	$	—

(1)Represents net income allocated to each class of units based on the actual ownership of the Partnership during the period. There were no amounts attributed to the general partner for its incentive distribution rights.

(2)Represents the distributions payable for the period based upon the quarterly distribution amounts of $0.111 per unit or $0.444 on an annualized basis. Amounts presented for each class of units include a proportionate amount of the $152 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 additional amount per unit necessary to distribute the excess net income for the period among our limited partners and our general partners according to the distribution formula for available cash as set forth in our partnership agreement..

(6)Our computation of net income per limited partner unit excludes the effects of 1,366,355 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. Additionally, in February 2020, the final tranche of 2,092,709 subordinated units were converted into common units. Refer to Note 17. Partners Capital for more information.


	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 has been reduced by its proportionate amount of the $181 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 $0.3675 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 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 1,290,558 equity-classified phantom unit awards outstanding as they were anti-dilutive for the period presented.


	For the Nine Months Ended September 30, 2020
	Common Units		Subordinated Units (7)		Class A Units (7)		General Partner Units		Total
	(in thousands, except per unit amounts)
Net loss attributable to general and limited partner interests in USD Partners LP (1)	$	(25,898)	$	(15)	$	—	$	(445)	$	(26,358)
Less: Distributable earnings (2)	9,386		—		—		162		9,548
Distributions in excess of earnings	$	(35,284)	$	(15)	$	—	$	(607)	$	(35,906)
Weighted average units outstanding (3)	26,403		382		—		461		27,246
Distributable earnings per unit (4)	$	0.36	$	—	$	—
Overdistributed earnings per unit (5)	(1.34)		(0.04)		—
Net loss per limited partner unit (basic and diluted) (6)	$	(0.98)	$	(0.04)	$	—

(1)Represents net loss allocated to each class of units based on the actual ownership of the Partnership during the period. There were no amounts attributed to the general partner for its incentive distribution rights.

(2)Represents the per unit distribution paid of $0.111 per unit for the three months ended March 31, 2020 and June 30, 2020 and $0.111 per unit distributable for the three months ended September 30, 2020, representing a year-to-date distribution of $0.333 per unit. Amounts presented for each class of units include a proportionate amount of the $304 thousand distributed and $152 thousand distributable 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 loss per limited partner unit excludes the effects of 1,366,355 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 distribution 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 $1.4 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 1,290,558 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, 2020
	U.S.		Canada		Total
	(in thousands)
Third party	$	8,799	$	20,221	$	29,020
Related party	$	2,317	$	—	$	2,317


	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


	Nine Months Ended September 30, 2020
	U.S.		Canada		Total
	(in thousands)
Third party	$	22,501	$	53,850	$	76,351
Related party	$	6,737	$	5,891	$	12,628


	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

Remaining Performance Obligations

The transaction price allocated to the remaining performance obligations associated with our terminalling and fleet services agreements as of September 30, 2020 are as follows for the periods indicated:


	For the three months ending December 31, 2020		2021		2022		2023		Thereafter		Total
	(in thousands)
Terminalling Services (1) (2) (3)	$	25,364	$	95,878	$	72,203	$	36,613	$	146,460	$	376,518
Fleet Services	257		1,016		1,269		38		8		2,588
Total	$	25,621	$	96,894	$	73,472	$	36,651	$	146,468	$	379,106

(1)A significant portion of our terminalling services agreements are denominated in Canadian dollars. We have converted the remaining performance obligations associated with these Canadian dollar-denominated contracts using the year-to-date average exchange rate of 0.7392 U.S. dollars per each Canadian dollar at September 30, 2020.

(2)Includes fixed monthly minimum commitment fees per contracts and excludes constrained estimates of 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. Also excludes estimated constrained variable consideration included in certain of our terminalling services agreements that is based on crude oil pricing index differentials.

(3)Assumes USD’s Diluent Recovery Unit project goes into service in the second half of 2021, which will result in certain terminalling services agreements of our Hardisty terminal being automatically extended through mid-2031 and certain agreements at our Stroud terminal having a termination right in June 2022.

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.

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 had the following amounts outstanding associated with our contract assets on our consolidated balance sheets in the financial statement line items presented below in the following table for the indicated periods:


	September 30, 2020		December 31, 2019
	(in thousands)
Other current assets	$	1,044	$	171
Other current assets — related party	$	—	$	264

Deferred Revenue

Our deferred revenue is a form of a contract liability and consists 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 is currently 100% based on our experience and expectations around usage of these options. Accordingly, we had no deferred revenues at September 30, 2020 for estimated breakage associated with the make-up rights options we granted to our customers. There were $1.1 million of deferred revenues associated with make-up rights at December 31, 2019.

We also have deferred revenue that represents 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.

The following table presents the amounts outstanding on our consolidated balance sheets and changes associated with the balance of our deferred revenue for the nine months ended September 30, 2020:


	December 31, 2019		Cash Additions for Customer Prepayments		Revenue Recognized		September 30, 2020
	(in thousands)
Deferred revenue	$	6,104	$	5,607	$	(6,104)	$	5,607
Deferred revenue — related party (1)	$	1,072	$	—	$	(1,072)	$	—
Other non-current liabilities (2)	$	3,391	$	5,181	$	—	$	8,572

(1) Includes deferred revenue 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. Excludes deferred revenue from related parties associated with our fleet leases discussed below.

(2) Includes cumulative revenue that has been deferred due to tiered billing provisions included in certain of our Canadian dollar-denominated contracts, as discussed above. As such, the change in “Other non-current liabilities” presented has been reduced by approximately $88 thousand due to the impact of the change in the end of period exchange rate between December 31, 2019 and September 30, 2020.

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 included $0.4 million at each of September 30, 2020 and December 31, 2019 in “Deferred revenue — related party” on our consolidated balance sheets associated with customer prepayments for our fleet lease agreements. Refer to Note 7. Leases for additional discussion of our lease revenues.

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,
	2020		2019
	(in thousands)
Cash and cash equivalents	$	6,928	$	6,479
Restricted Cash	7,605		7,644
Total cash, cash equivalents and restricted cash	$	14,533	$	14,123

6. PROPERTY AND EQUIPMENT

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


	September 30, 2020		December 31, 2019		Estimated Depreciable Lives (Years)
	(in thousands)
Land	$	10,149	$	10,224	N/A
Trackage and facilities	124,338		126,008		10-30
Pipeline	32,735		32,916		20-30
Equipment	16,956		16,857		3-20
Furniture	64		66		5-10
Total property and equipment	184,242		186,071
Accumulated depreciation	(45,219)		(38,919)
Construction in progress (1)	722		585
Property and equipment, net	$	139,745	$	147,737

(1)The amounts classified as “Construction in progress” are excluded from amounts being depreciated. These amounts represent property that has not been placed into productive service as of the respective consolidated balance sheet date. We had no capitalized interest costs for the three and nine months ended September 30, 2020, and $170 thousand and $439 thousand for the three and nine months ended September 30, 2019, respectively

Depreciation expense associated with property and equipment totaled $2.3 million and $2.1 million for the three months ended September 30, 2020 and 2019, respectively, and $6.6 million and $5.9 million for the nine months ended September 30, 2020 and 2019, respectively.

Our depreciation expense reflects a reduction to our asset retirement obligation, or ARO, of $0.2 million and $0.6 million for the nine months ended September 30, 2020 and 2019, respectively, due to refinement of our estimates. We had no change in our estimates for the three months ended September 30, 2020 and 2019. The ARO was associated with restoration of the property at our San Antonio facility. All remediation activities associated with the ARO are now deemed complete and this position has not been disputed by the property owner. There is no remaining balance related to ARO on our consolidated balance sheet at September 30, 2020.

7. LEASES

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


	Nine Months Ended September 30, 2020
Weighted-average discount rate	5.8	%
Weighted average remaining lease term in years	2.09

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


		Three Months Ended September 30,				Nine Months Ended September 30,
		2020		2019		2020		2019
	(in thousands)

Operating lease cost		$	1,483	$	1,483	$	4,461	$	4,451
Short term lease cost		46		48		138		147
Variable lease cost		1		—		12		—
Sublease income		(1,341)		(1,332)		(4,024)		(4,002)
Total		$	189	$	199	$	587	$	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, 2020 (in thousands):


2020	$	1,527
2021	5,714
2022	4,507
2023	22


Total lease payments	$	11,770
Less: imputed interest	(714)
Present value of lease liabilities	$	11,056

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,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in thousands, except weighted average term)
Lease income (1)	$	2,545	$	2,363	$	7,097	$	7,512
Weighted average remaining lease term in years							2.06

(1)Lease income associated with crude oil storage tanks we lease to customers of our terminals totaling $1.5 million and $1.4 million for the three months ended September 30, 2020 and 2019, and $4.1 million and $4.5 million for the nine months ended September 30, 2020 and 2019, respectively, is included in “Terminalling services” revenues on our consolidated statements of operations.

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, 2020 (in thousands):


2020	$	2,186
2021	8,290
2022	5,354



Total	$	15,830

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.

In March 2020, we tested the goodwill associated with our Casper terminal for impairment due to the overall downturn in the crude market and the decline in the demand for petroleum products, which could lead to delays or reductions of expected throughput levels and changes in expectations for current and future contracts at the Casper terminal. Refer to Note 1. Organization and Basis of Presentation — Current Events for more information.

The critical assumptions used in our analysis include the following:

1)a weighted average cost of capital of 12%;

2)a capital structure consisting of approximately 65% debt and 35% equity based on the capital structure of market participants;

3)a range of EBITDA multiples derived from equity prices of public companies with similar operating and investment characteristics, from 7.25x to 8.25x;

4)a range of EBITDA multiples for transactions based on actual sales and purchases of comparable businesses, from 8.0x to 9.0x; and

5)a range of incremental volumes expected at our Casper terminal of approximately 4,000 to 25,000 bpd for terminalling and storage services resulting from the anticipated successful completion of the Enbridge DRA project in the second half 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 determined that the carrying amount of our Casper terminal reporting unit exceeded its fair value at March 31, 2020. Accordingly, we recognized an impairment loss of $33.6 million in our goodwill asset and included this charge in “Goodwill impairment loss” within our consolidated statement of operations for the nine months ended September 30, 2020. For additional information see Note 2. Recent Accounting Pronouncements. At September 30, 2020, we had no goodwill balance in our consolidated balance sheet.

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, 2020		December 31, 2019
	(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	(61,371)		(51,923)
Other	(51)		(44)
Total accumulated amortization	(61,422)		(51,967)
Total intangible assets, net	$	64,644	$	74,099

Amortization expense associated with intangible assets totaled $3.2 million for the three months ended September 30, 2020 and 2019, and $9.5 million for the nine months ended September 30, 2020 and 2019.

We determined the overall downturn in the crude market and the decline in the demand for petroleum products, which could lead to delays or reduction of expected throughput levels and changes in expectations for current and future contracts in our terminalling services at the Casper terminal, was an event that required us to evaluate our Casper terminal asset group for impairment. We measured the fair value of our Casper terminal assets at March 31, 2020, by using projections of the undiscounted cash flows expected to be derived from the operation and disposition of the Casper terminal asset.

The critical assumptions underlying our projections included the following:

1)a range of incremental volumes expected at our Casper terminal of approximately 4,000 to 25,000 bpd for terminalling and storage services resulting from the anticipated successful completion of the Enbridge DRA project in the second half of 2020;

2)expected volumes for our blended services business for distribution to local refiners;

3)a 15 year remaining useful life of the primary asset, represented by our property and equipment of the Casper terminal asset group; and

4)a residual value of 8.0x projected cash flows for the Casper terminal at the end of the 15 year remaining life of the primary asset.

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 amount of the asset group as of March 31, 2020, the date of our evaluation, indicating cash flows were expected to be sufficient to recover the carrying amount of the Casper terminal asset group. Accordingly, we did not recognize any impairment of our asset. 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, 2020.

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, 2020		December 31, 2019
	(in thousands)

Revolving Credit Facility	$	209,000	$	220,000
Less: Deferred financing costs, net	(1,727)		(2,349)
Total long-term debt, net	$	207,273	$	217,651

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


	September 30, 2020		December 31, 2019
	(in millions)
Aggregate borrowing capacity under Credit Agreement	$	385.0	$	385.0
Less: Revolving Credit Facility amounts outstanding	209.0		220.0

Available under the Credit Agreement based on capacity	$	176.0	$	165.0
Available under the Credit Agreement based on covenants (1)	$	37.2	$	28.8

(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 $37.2 million and $28.8 million of borrowing capacity available at September 30, 2020 and December 31, 2019, respectively.

The weighted average interest rate on our outstanding indebtedness was 2.91% and 4.24% at September 30, 2020 and December 31, 2019, 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, 2020, 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,
	2020		2019		2020		2019
	(in thousands)
Interest expense on the Credit Agreement	$	1,837	$	2,967	$	6,418	$	8,748
Capitalized interest on construction in progress	—		(170)		—		(439)
Amortization of deferred financing costs	208		208		622		865
Total interest expense	$	2,045	$	3,005	$	7,040	$	9,174

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 $5.9 million and $5.4 million for the three months ended September 30, 2020 and 2019, and $17.7 million and $15.4 million for the nine months ended September 30, 2020 and 2019, respectively, which are presented as “Pipeline fees” in our consolidated statements of operations. We have included a liability related to this agreement in “Other Current Liabilities” on our consolidated balance sheets of $3.1 million and $1.2 million at September 30, 2020 and December 31, 2019.

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, 2020 and December 31, 2019, as well as our maximum exposure to losses from entities in which we have a variable interest, but are not the primary beneficiary. Generally, our maximum exposure to losses is limited to amounts receivable for services we provided, reduced by any deferred revenues.


	September 30, 2020
	Total assets		Total liabilities		Maximum exposure to loss
	(in thousands)
Accounts receivable	$	10	$	—	$	—

Deferred revenue	—		10		—

	$	10	$	10	$	—


	December 31, 2019
	Total assets		Total liabilities		Maximum exposure to loss
	(in thousands)
Accounts receivable	$	11	$	—	$	1

Deferred revenue	—		10		—

	$	11	$	10	$	1

We have assigned certain payment and performance obligations under the leases and master fleet service agreements for 1,232 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, 2020, 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, 2020, owns 11,557,090 of our common units representing a 42.3% limited partner interest in us. As of September 30, 2020, 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. However, our general partner has no obligation to, does not intend to and has not implied that it would, provide financial support to or fund cash flow deficits of the Partnership.

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 one and one-half 120-railcar unit trains of transloading capacity per day, or approximately 112,500 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, or Omnibus Agreement, 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, 2020 and 2019 was $1.7 million and $1.4 million, respectively, and for the nine months ended September 30, 2020 and 2019 was $5.6 million and $6.1 million, respectively, which amounts are included in “Selling, general and administrative — related party” in our consolidated statements of operations. We had a payable balance of $0.3 million and $0.4 million with respect to these costs at September 30, 2020 and December 31, 2019, respectively included in “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 now 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. We incurred $2.1 million and $6.2 million of expenses pursuant to the arrangement for the three and nine months ended September 30, 2020 and $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 operations. 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 operations. Additionally, in conjunction with this agreement, we recorded a contract asset of $1.2 million at September 30, 2020 on our consolidated balance sheet in “Other non-current assets — related party”, representing long-term prepaid expense associated with this agreement due to tiered billing provisions in the related terminalling services agreements. We had no recorded asset at December 31, 2019, associated with this agreement.

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. USDTC 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. The terms and conditions of these agreements were similar to the terms and conditions of agreements we have with other parties at the Hardisty terminal that are not related to us. USDM’s agreement with the third party customer was renewed and extended, effective July 1, 2020, and USDM subsequently assigned its terminalling services agreement with the third party customer directly to us and is therefore no longer a customer at our Hardisty terminal. USDM controlled approximately 25% of the available monthly capacity of the Hardisty terminal through June 30, 2020.

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” in our consolidated statements of operations. 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” and “Fleet services — related party” and in our consolidated statements of operations.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in thousands)
Terminalling services — related party	$	1,041	$	4,459	$	8,929	$	15,622
Fleet leases — related party	984		984		2,951		2,951
Fleet services — related party	227		227		682		682
Freight and other reimbursables — related party	65		193		66		254
	$	2,317	$	5,863	$	12,628	$	19,509

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, 2020		December 31, 2019
	(in thousands)
Accounts receivable — related party	$	2,508	$	1,778
Accounts payable and accrued expenses — related party (1)	$	64	$	87
Other current and non-current assets — related party (2)	$	1,262	$	358
Deferred revenue — related party (3)	$	410	$	1,482

(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)Includes 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. Also includes a contract asset associated with the Hardisty Terminal Services Agreement with USDTC II, as discussed above.

(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

We paid the following aggregate cash distributions to USDG as a holder of our common units, and with respect to the February 2020 payment date, the sole owner of our subordinated units and to USD Partners GP LLC as sole holder of our general partner interest and IDRs.


Distribution Declaration Date	Record Date	Distribution Payment Date	Amount Paid to USDG		Amount Paid to USD Partners GP LLC
			(in thousands)
January 30, 2020	February 10, 2020	February 19, 2020	$	4,276	$	372
April 23, 2020	May 5, 2020	May 15, 2020	$	1,283	$	51
July 23, 2020	August 4, 2020	August 14, 2020	$	1,283	$	51

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, 2020
	Terminalling services		Fleet services		Corporate		Total
	(in thousands)
Revenues
Terminalling services	$	28,905	$	—	$	—	$	28,905
Terminalling services — related party	1,041		—		—		1,041

Fleet leases — related party	—		984		—		984
Fleet services	—		51		—		51
Fleet services — related party	—		227		—		227
Freight and other reimbursables	32		32		—		64
Freight and other reimbursables — related party	—		65		—		65
Total revenues	29,978		1,359		—		31,337
Operating costs
Subcontracted rail services	2,300		—		—		2,300
Pipeline fees	5,936		—		—		5,936
Freight and other reimbursables	32		97		—		129
Operating and maintenance	3,375		1,026		—		4,401
Selling, general and administrative	1,315		197		2,733		4,245
Goodwill impairment loss	—		—		—		—
Depreciation and amortization	5,430		—		—		5,430
Total operating costs	18,388		1,320		2,733		22,441
Operating income (loss)	11,590		39		(2,733)		8,896
Interest expense	—		—		2,045		2,045
Loss associated with derivative instruments	—		—		1,200		1,200
Foreign currency transaction loss (gain)	46		1		(293)		(246)
Other income, net	(25)		(8)		—		(33)
Benefit from income taxes	(293)		(14)		—		(307)
Net income (loss)	$	11,862	$	60	$	(5,685)	$	6,237


	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
Goodwill impairment loss	—		—		—		—
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


	Nine Months Ended September 30, 2020
	Terminalling services		Fleet services		Corporate		Total
	(in thousands)
Revenues
Terminalling services	$	75,449	$	—	$	—	$	75,449
Terminalling services — related party	8,929		—		—		8,929

Fleet leases — related party	—		2,951		—		2,951
Fleet services	—		152		—		152
Fleet services — related party	—		682		—		682
Freight and other reimbursables	681		69		—		750
Freight and other reimbursables — related party	—		66		—		66
Total revenues	85,059		3,920		—		88,979
Operating costs
Subcontracted rail services	8,433		—		—		8,433
Pipeline fees	17,678		—		—		17,678
Freight and other reimbursables	681		135		—		816
Operating and maintenance	11,067		3,071		—		14,138
Selling, general and administrative	4,455		723		8,695		13,873
Goodwill impairment loss	33,589		—		—		33,589
Depreciation and amortization	16,055		—		—		16,055
Total operating costs	91,958		3,929		8,695		104,582
Operating loss	(6,899)		(9)		(8,695)		(15,603)
Interest expense	—		—		7,040		7,040
Loss associated with derivative instruments	—		—		4,405		4,405
Foreign currency transaction loss (gain)	53		(2)		761		812
Other income, net	(864)		(8)		(4)		(876)
Benefit from income taxes	(132)		(494)		—		(626)
Net income (loss)	$	(5,956)	$	495	$	(20,897)	$	(26,358)


	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
Goodwill impairment loss	—		—		—		—
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

Segment Adjusted EBITDA

The following tables present the computation of Segment Adjusted EBITDA, which is a measure determined in accordance with GAAP, for each of our segments for the periods indicated:


	Three Months Ended September 30,				Nine Months Ended September 30,
Terminalling Services Segment	2020		2019		2020		2019
	(in thousands)
Net income (loss)	$	11,862	$	8,072	$	(5,956)	$	24,675

Interest income (1)	(1)		(18)		(24)		(33)
Depreciation and amortization	5,430		5,300		16,055		15,317
Provision for (benefit from) income taxes	(293)		406		(132)		596
Foreign currency transaction loss (gain) (2)	46		33		53		(62)
Loss associated with disposal of assets	—		—		—		50
Goodwill impairment loss	—		—		33,589		—
Other income	—		(27)		—		(69)
Non-cash deferred amounts (3)	(16)		1,435		1,540		1,545

Segment Adjusted EBITDA	$	17,028	$	15,201	$	45,125	$	42,019

(1) Represents interest income associated with our Terminalling Services segment that is included in “Other income, net” in our consolidated statements of operations.

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

(3) Represents the change in non-cash contract assets and liabilities associated with revenue recognized at blended rates based on tiered rate structures in certain of our 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	2020		2019		2020		2019
	(in thousands)
Net income	$	60	$	19	$	495	$	8
Provision for (benefit from) income taxes	(14)		8		(494)		16
Interest income (1)	(8)		—		(8)		—
Foreign currency transaction loss (gain) (2)	1		(2)		(2)		6
Segment Adjusted EBITDA	$	39	$	25	$	(9)	$	30

(1) Represents interest income associated with our Fleet Services segment that is included in “Other income, net” in our consolidated statements of operations.

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

15. INCOME TAXES

CARES Act

On March 27, 2020, the CARES Act was signed into law. The CARES Act is an emergency economic stimulus package enacted in response to the coronavirus outbreak which, among other measures, contains numerous income tax provisions. Some of these tax provisions are expected to be effective retroactively for tax years ending before the date of enactment. For us, the most significant change included in the CARES Act was the impact to U.S. net operating loss carryback provisions. U.S. net operating losses incurred in tax years 2018, 2019, and 2020 can

now be carried back to the preceding five tax years and may be used to fully offset taxable income (i.e. they are not subject to the 80 percent net income offset limitation of Section 172 of the U.S. Tax Code).

As a result of these CARES Act changes, for the three and nine months ended September 30, 2020 we recognized a current tax benefit of $3 thousand and $533 thousand, respectively, for a claimable tax refund by carrying back U.S. net operating losses incurred in 2018, 2019, and the first nine months of 2020. We also recognized a one-time deferred tax expense of $46 thousand in the first quarter of 2020 due to the net effect of utilizing all U.S. net operating loss deferred tax assets and releasing the corresponding U.S. valuation allowance as of December 31, 2019. We expect to recognize an additional tax benefit in 2020 due to anticipated tax losses. The tax impacts of the CARES Act were computed with the best available information, and will be adjusted after the 2020 U.S. tax return is finalized. However, we do not expect these adjustments to result in a material change to the tax provision in future periods.

Goodwill Impairment Tax Impact

For the nine months ended September 30, 2020, we recognized a loss before income taxes of $27.0 million due primarily to a goodwill impairment loss recognized during the first quarter of 2020 associated with our Casper terminal included in our terminalling services segment. Refer to Note 8. Goodwill and Intangible Assets for more information.

Our tax provision for the nine months ended September 30, 2020 was not impacted by the goodwill impairment loss as our terminalling services activities in the U.S. 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.

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

16. DERIVATIVE FINANCIAL INSTRUMENTS

Our net income, or loss, 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 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.

In November 2017, we entered into a five-year interest rate collar contract with a $100 million notional value. The collar established a range where we paid the counterparty if the one-month Overnight Index Swap, or OIS, fell below the established floor rate of 1.70%, and the counterparty paid us if the one-month OIS rate exceeded the established ceiling rate of 2.50%. The collar settled monthly through the termination date. No payments or receipts were exchanged on the interest rate collar contracts unless interest rates rose above or fell below the predetermined ceiling or floor rate. 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.

In September 2020, we terminated our existing interest rate collar discussed above and simultaneously entered into a new interest rate swap that was made effective as of August 2020. In lieu of settling the liability value

of the existing interest rate collar agreement of $3.5 million that existed at the time the agreement was terminated, the value of the liability was rolled into the fixed rate of the new interest rate swap agreement. The new interest rate swap is a five-year contract with a $150 million notional value that fixes our one-month LIBOR to 0.84% for the notional value of the swap agreement instead of the variable rate that we pay under our Credit Agreement. The swap settles monthly through the termination date in August 2025.

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, 2020		December 31, 2019
	(in thousands)


Other current liabilities	$	(1,060)	$	(139)
Other non-current liabilities	(3,539)		(687)
	$	(4,599)	$	(826)

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 associated with derivative instruments” in our consolidated statements of operations. 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,
	2020		2019		2020		2019
	(in thousands)
Loss associated with derivative instruments	$	1,200	$	220	$	4,405	$	1,966

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:


					September 30, 2020		December 31, 2019
	Notional		Interest Rate Parameters		Fair Value		Fair Value
					(in thousands)
Swap Agreements
Swap maturing August 2025	$	150,000,000	0.84	%	$	(4,599)	$	—


					September 30, 2020		December 31, 2019
	Notional		Interest Rate Parameters		Fair Value		Fair Value
					(in thousands)
Collar Agreements
Ceiling	$	100,000,000	2.5	%	$	—	$	83
Floor	$	100,000,000	1.7	%	—		(909)
Total					$	—	$	(826)

We record the fair market value of our derivative financial instruments in our consolidated balance sheets as current and non-current assets or liabilities on a net basis by counterparty. The terms of the International Swaps and Derivatives Association Master Agreement, which governs our financial contracts, 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.


	December 31, 2019
	Current assets		Non-current assets		Current liabilities		Non-current liabilities		Total
	(in thousands)
Fair value of derivatives — gross presentation	$	—	$	83	$	(139)	$	(770)	$	(826)
Effects of netting arrangements	—		(83)		—		83		—
Fair value of derivatives — net presentation	$	—	$	—	$	(139)	$	(687)	$	(826)

17. PARTNERS’ CAPITAL

Our common units represent and subordinated units represented limited partner interests in us. The holders of common units are and subordinated units were 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, 2020. 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.

All of our subordinated units converted into common units on a one-for-one basis in separate sequential tranches. Each tranche was comprised of 20.0% of the subordinated units issued in conjunction with our IPO. Each separate tranche was 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 were 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 have commenced after the four quarter period applicable to any prior tranche of subordinated units. In February 2020, pursuant to the terms set forth in our partnership agreement, we converted the fifth and final tranche of 2,092,709 of our subordinated units into common units upon satisfaction of the conditions established for conversion.

Our partnership agreement provides that, while any subordinated units remained outstanding, holders of our common units had 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 were made on the subordinated units.

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 519,350 vested during the first nine months in 2020, of which 339,736 were converted into our common units after 179,614 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. For the quarter ended September 30, 2020, the board of directors of our general partner determined that we had sufficient available cash after the establishment of cash reserves and the payment of our expenses to distribute $0.111 per unit on all of our units.

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 in 2019 and no Class A units remain outstanding at September 30, 2020.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2020	2019	2020	2019
Class A units outstanding at beginning of period	—	—	—	38,750
Vested	—	—	—	(38,750)
Forfeited	—	—	—	—
Class A units outstanding at end of period	—	—	—	—

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,
	2020		2019		2020		2019
	(in thousands)
Selling, general and administrative	$	—	$	—	$	—	$	14

For the three and nine months ended September 30, 2020 and 2019 we had no forfeitures of 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 were included in “Distributions” as presented in our consolidated statements of cash flows and our consolidated statements 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, 2020 or 2019, for distributions paid on Class A units that were forfeited.

Long-term Incentive Plan

In 2020 and 2019, the board of directors of our general partner, acting in its capacity as our general partner, approved the grant of 694,140 and 633,637 Phantom Units, respectively, to directors and employees of our general partner and its affiliates under our A/R LTIP. At September 30, 2020, we had 943,489 Phantom Units remaining available for issuance. 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 the 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, 2019	37,139	1,252,544	$	11.34
Granted	40,065	594,912	$	10.15
Vested	(37,139)	(482,211)	$	10.84
Forfeited	—	(38,955)	$	11.07
Phantom Unit awards at September 30, 2020	40,065	1,326,290	$	10.98


	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

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, 2019	12,177	44,620	$	11.53
Granted	13,136	46,027	$	10.15
Vested	(12,177)	—	$	11.37

Phantom Unit awards at September 30, 2020	13,136	90,647	$	10.76


	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

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 operations 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 operations, with an offset to common units within the Partners’ Capital section of our consolidated balance sheet.

For the three months ended September 30, 2020 and 2019, we recognized $1.6 million and $1.5 million, respectively, and for the nine months ended September 30, 2020 and 2019, we recognized $4.9 million and $4.5 million, respectively, of compensation expense associated with outstanding Phantom Units. As of September 30, 2020, we have unrecognized compensation expense associated with our outstanding Phantom Units totaling $11.3 million, which we expect to recognize over a weighted average period of 2.52 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,
	2020		2019		2020		2019
	(in thousands)
Equity-classified Phantom Units (1)	$	152	$	471	$	781	$	1,358
Liability-classified Phantom Units	12		30		45		74
Total	$	164	$	501	$	826	$	1,432

(1) We had no significant reclassifications to unit based compensation expense for DERs paid in relation to Phantom Units that have been forfeited for the three months ended September 30, 2020 and 2019. We reclassified $57 thousand and $8 thousand for the nine months ended September 30, 2020 and 2019, respectively, for forfeitures.

19. SUPPLEMENTAL CASH FLOW INFORMATION

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


	Nine Months Ended September 30,
	2020		2019
	(in thousands)
Cash paid for income taxes	$	623	$	904
Cash paid for interest	$	6,837	$	8,860
Cash paid for operating leases	$	4,607	$	4,526

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,
	2020		2019
	(in thousands)
Loss associated with disposal of assets	$	—	$	50
Amortization of deferred financing costs	622		865
	$	622	$	915

Non-cash activities

Leases

We recorded $3.1 million of right-of-use lease assets and the associated liabilities on our consolidated balance sheet as of September 30, 2020, representing non-cash activities resulting from new or extended lease agreements. See Note 7. Leases for further discussion.

Non-cash Investing Activities

For the nine months ended September 30, 2020 and 2019, we had non-cash investing activities for capital expenditures for property and equipment that were financed through accounts payable and accrued expenses as presented in the table below for the periods indicated:


	Nine months ended September 30,
	2020		2019
	(in thousands)
Property and equipment financed through accounts payable accrued liabilities	$	(229)	$	1,044

20. SUBSEQUENT EVENTS

Distribution to Partners

On October 22, 2020, the board of directors of USD Partners GP LLC, acting in its capacity as our general partner, declared a quarterly cash distribution payable of $0.111 per unit, or $0.444 per unit on an annualized basis, for the three months ended September 30, 2020. Consistent with the distribution declared for the first quarter of 2020, the distribution represents a decrease of $0.259 per unit, or 70.0% below the distribution with respect to the fourth quarter of 2019. The distribution will be paid on November 13, 2020, to unitholders of record at the close of business on November 3, 2020. The distribution will include payment of $1.7 million to our public common unitholders, $1.3 million to USDG as a holder of our common units and $51 thousand to USD Partners GP LLC as a holder of the general partner interest.

Revolving Credit Facility Activity

Subsequent to September 30, 2020, we made additional repayments of $4.0 million under the terms of our existing $385 million Revolving Credit Facility. The Credit Agreement provides for borrowings of up to $385.0 million, expandable to $500.0 million, with lender consent, and expires on November 2, 2022. As of November 2, 2020, we had amounts outstanding of $205.0 million under the Revolving Credit Facility and $180.0 million available for borrowings under the Revolving Credit Facility based on capacity that is subject to certain covenants. Refer to Note 9. Debt for more information.

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, 2019. 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, 2019, our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, 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 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 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. We may on occasion 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 any exposure to changes in commodity prices.

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, referred to herein as Hardisty South, which added one and one-half 120-railcar unit trains of transloading capacity per day, or approximately 112,500 barrels per day, or bpd.

USD, along with its partner, Gibson, is also pursuing long-term solutions to transport heavier grades of crude oil produced in Western Canada through the construction of a Diluent Recovery Unit, or DRU, at the Hardisty terminal. Construction of the project has commenced and USD expects that it will be placed into service in the second quarter of 2021. As previously disclosed, USD has secured the necessary financing, obtained all material permits and entered into fixed-price construction contracts regarding the construction of the project. USD’s patented

DRU technology separates the diluent that has been added to the raw bitumen in the production process which meets two important market needs – it returns the recovered diluent for reuse in the Alberta market, reducing delivered costs for diluent, and it creates DRUbit™, a proprietary heavy Canadian crude oil specifically designed for rail transportation. DRUbit™ is crude oil or bitumen that has been returned to a more concentrated, viscous state that is classified as a non-hazardous, non-flammable commodity when transported by rail in Canada and the U.S. DRUbit™ is a market access solution that will satisfy demand for heavy Canadian crude oil on the U.S. Gulf Coast and in other markets at a cost that is economically competitive to the crude oil that is transported by pipeline today. In addition, USD is constructing a new destination terminal in Port Arthur, Texas for the DRUbit™ that will be transloaded at our Hardisty origination terminal.

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.

COVID-19 and Crude Oil Pricing Environment Update

In December 2019, a novel coronavirus disease (“COVID-19”) was reported and on March 11, 2020, the World Health Organization declared that the spread of COVID-19 qualified as a global pandemic. The COVID-19 pandemic has adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the pandemic has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement worldwide. As a result, there has been a significant reduction in demand for and prices of crude oil, natural gas and natural gas liquids. In addition, in March 2020, members of the Organization of the Petroleum Exporting Countries, or OPEC+, failed to agree on oil production levels, which led to a substantial decline in oil prices and an increasingly volatile market. In March and April 2020, domestic oil and natural gas producers announced dramatic reductions or curtailments of their development programs, as well as plans to shut-in production. In April 2020, even though OPEC+ announced that it had reached an agreement to cut production by 9.7 million barrels per day, or Mmbpd, oil prices did not meaningfully increase. As concerns about domestic oil storage capacity being fully subscribed in May 2020 grew, on April 20, 2020, WTI oil futures priced at historic lows. While COVID-19 is still a global pandemic, parts of the world have started to recover and some economies have started to reopen. However, certain jurisdictions that began re-opening have returned to restrictions in light of increased numbers of new COVID-19 cases. There still remains considerable uncertainty about the ultimate impact and duration of the pandemic and its effects on the global economy.

Despite these uncertainties, recent efforts to reopen the economy have led to marginal increases in the demand for crude oil and petroleum products, which resulted in a modest recovery in and the stabilization of oil prices as compared to the lower price levels that were present at the end of the first quarter and during the second quarter of 2020. As a result, as of the beginning of July 2020, producers in Canada and the U.S. started to bring back small amounts of temporary shut-in production from the first quarter of 2020. Additionally, OPEC+ agreed in July 2020 to taper oil production cuts, which will scale back production cuts from 9.7 Mmbpd to 7.7 Mmbpd between August 2020 and January 2021. In the third quarter of 2020, it was expected that more production volume would come back online but pipeline outages and unplanned maintenance delayed the expected production increases. We believe that if the increases in demand continue, additional producers in Canada and the U.S. will likely announce that they are bringing back further production throughout the end of the year as maintenance is completed. However, there still remains significant uncertainty given the unprecedented and evolving nature of the COVID-19 pandemic, and the extent and duration of any increases in demand and price levels are difficult to predict, if such increases

occur at all. As demand and prices increase, the need for crude by rail export capacity from our terminals is also expected to increase.

The broader implications of COVID-19 and lower oil and natural gas prices on our results of operations and overall financial performance remain uncertain. We have implemented protocols and procedures designed to manage risk associated with the direct impact of COVID-19 on our operations. We have not experienced material disruptions to our operations or material increase in our cash expenses. Currently, we expect to have sufficient liquidity to operate our business and remain in compliance with the financial covenants under our credit agreement for at least the next twelve months following the filing of this report and we do not expect our customers to terminate existing contracts. However, if the pandemic continues for an extended period of time and/or oil prices decline or remain at relatively low levels, these conditions may have an adverse effect on the Company’s results of future operations, financial position, and liquidity. Given the unprecedented and evolving nature of the COVID-19 pandemic and the state of the commodity markets, we continue to actively monitor their impact on our operations and financial condition. Refer to Item 1A. Risk Factors in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 for further discussion of certain risks relating to the COVID-19 pandemic.

These events have negatively impacted our customers and thereby limited our ability to grow our business. For example, as a result of the overall downturn in the crude market and the decline in the demand for petroleum products, in March 2020, we tested the goodwill associated with our Casper terminal for impairment, which resulted in an impairment loss. Declining demand for petroleum products could lead to delays or reductions of expected throughput levels and changes in expectations for current contracts in place at the Casper terminal. Refer to Part I. Item 1. Financial Statements, Note 8. Goodwill and Intangible Assets of this Report for further discussion of the impairment loss at the Casper terminal.

Given the uncertainty in the energy industry, the board of directors of our general partner elected to reduce the quarterly distribution per unit declared for the first, second and third quarters of 2020 by 70% as compared to the distribution for the fourth quarter of 2019 as a proactive measure to strengthen our financial position and redeploy certain free cash flow to de-lever. During the second and third quarters of 2020, we made net repayments of $6 million and $9 million, respectively, of the outstanding balance of our Revolving Credit Facility. Refer to Liquidity and Capital Resources — Cash Requirement — Distributions for further discussion.

Impact of Current Market Events

The WCS to West Texas Intermediate, or WTI, crude oil spread narrowed to between $6-$12 per barrel during the third quarter of 2020, as a result of the decline in global oil supply described in COVID-19 and Crude Oil Pricing Environment Update discussed above. The narrowing of the WCS to WTI crude oil spread resulted in a decrease in the demand for additional export capacity by customers of our Hardisty terminal and as a result we experienced a significant decrease in the average daily throughput during the second and third quarters of 2020 at the terminal. In September 2020, our Hardisty terminal experienced a slight increase in daily terminal throughput as compared to previous recent months. Producers have started to marginally increase supply as prices improve. Therefore, we expect that throughput volumes at our Hardisty terminal will continue to trend upwards through the end of 2020 and into 2021, from the low levels that existed during the second and third quarters of 2020 that resulted from the impacts of the COVID-19 pandemic.

Apportionment levels on the primary heavy crude oil pipelines from Western Canada to the U.S. decreased significantly to an average of 13% in the second quarter of 2020 (representing the percentage of barrels nominated that were not shipped due to pipeline capacity constraints). Consistent with production trending towards levels that existed prior to the COVID-19 pandemic, in the third quarter of 2020, apportionment levels on the primary heavy crude oil pipelines from Western Canada to the U.S. started to increase modestly in July 2020 from the low levels that existed at the end of the second quarter and reached 18% in September 2020. Heavy Canadian crude oil supply levels are also expected to increase due to winter pipeline specification changes, as required pipeline blending ratios are higher in the winter months. As such, apportionment is also expected to increase due to this factor and as supply increases and lack of available pipeline takeaway capacity remains. Finally, inventory levels in Western Canada at the end of the third quarter of 2020 have decreased by approximately 45% compared to the levels that existed at the end of 2019, driven primarily by producers’ responses to the change in demand that resulted from the COVID-19

pandemic and unplanned maintenance and pipeline outages that occurred in the third quarter of 2020. Given the expectation of increases in supply and higher apportionment levels, it is our expectation that inventory levels will increase in the fourth quarter of 2020. There still remains significant uncertainty given the unprecedented and evolving nature of the COVID-19 pandemic, and the extent and duration of any increases in apportionment or inventory levels are difficult to predict, if such increases occur at all.

Future WCS to WTI spreads published by Bloomberg through 2024 average approximately $15 per barrel. Given the current market conditions, as stated above, and as pipeline uncertainty remains, supply is expected to be higher than pipeline takeaway capacity and as a result, the WCS to WTI spread should widen from current levels. As this occurs, crude by rail volumes from Western Canada to the United States are expected to further increase, possibly in the latter part of 2020 and into 2021.

Additionally, projects to increase pipeline export capacity have continued to experience significant regulatory delays. For example, the anticipated in-service date of Enbridge’s Line 3 Replacement project to upgrade and expand an existing pipeline delivering Western Canadian crude to U.S. markets in the second half of 2020 is now uncertain, due to regulatory issues on the U.S. portion of the pipeline. In March 2020, the government of Alberta announced that it had reached an agreement to invest $1.5 billion in equity investment in the Keystone XL crude oil pipeline project in 2020 followed by a $6 billion loan guarantee in 2021 in order to enable the completion of the project by 2023. However, in April 2020, a U.S. judge cancelled a key permit needed for the construction of the Keystone XL crude oil pipeline. The construction of the Keystone XL pipeline is now on hold until at least 2021. In July 2020, the White House issued a permit to expand the cross-border shipping limit on the existing Keystone pipeline to 760,000 bpd from 590,000 bpd. TC Energy plans to expand the pipeline by 50,000 bpd in 2021 with the use of drag reducing agent, or DRA. The additional capacity will be assessed in the future and may require additional capital expenditures. Current pipeline operators are also facing legal challenges to keep their pipelines in operation. The Dakota Access Pipeline is in the middle of a legal dispute to determine whether the pipeline can continue to operate without a key easement. The decision is now delayed until the end of the year but the pipeline can operate until a decision is made. As pipeline export capacity environmental, regulatory and political challenges remain, crude by rail exports will remain a valuable egress solution.

As producers in Western Canada start to bring back production, we expect demand for and utilization of our rail terminals will increase as produced barrels will need to be exported, in the event relative price differentials make it economic to do so, which continues to remain uncertain and difficult to predict. In the long-term, 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. Also, USD is pursuing long-term solutions to transport heavier grades of crude oil produced in Western Canada through the construction of a Diluent Recovery Unit, or DRU, at the Hardisty terminal, which we expect will be placed into service in the second quarter of 2021. This project is expected to maximize benefits to producers, refiners and railroads. 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.

Alberta Government Update

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. 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.

To date in 2020, the allowed production level under the curtailment has remained at 3.81 million bpd. In late October 2020, the Alberta Government announced that while the government will extend its regulatory authority to curtail oil production through December 2021, it will not set production limits as of December 2020. The Alberta Government has stated that it will closely monitor production, inventories, pipeline capacity and rail shipments. The Alberta Government could put production limits back in place, particularly if forecasts show storage inventories approaching maximum capacity.

To address 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 engaged CIBC Capital Markets to help oversee the divestment of this crude-by-rail program and its transition to the private sector. In February 2020, the Alberta Government announced that it had agreed to divest of its contracts to move additional crude by rail to market, but has not released any other details as the agreements are still being finalized.

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. We generally have no direct commodity price exposure, although fluctuating commodity prices could indirectly influence our activities and results of operations over the long term. We may on occasion enter into buy-sell arrangements in which we take temporary title to commodities while in our terminals. We expect any such agreements to be at fixed prices where we do not take commodity price exposure.

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 barrels 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. Additionally, to supplement the rail loading options from the terminal, we constructed an outbound pipeline connection from the Casper terminal to the nearby

Platte terminal located at the termination point of the Express pipeline that was placed into service 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, 2020, our railcar fleet consisted of 1,432 railcars, which we leased from various railcar manufacturers and financial entities, including 1,058 coiled and insulated, or C&I, railcars. We have assigned certain payment and performance obligations under the leases and master fleet service agreements for 1,232 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 1.8 years as of September 30, 2020. At the end of June 2020, leases on 250 railcars were assigned directly to one of our customers. This transfer did not have a material impact on our business, cash flow, or results of operations.

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 fleet services.

Historically, we contracted with railroads on behalf of some of our customers to arrange for the movement of railcars from our terminals to the destinations selected by our customers. We were the contracting party with the railroads for those shipments and were responsible to the railroads for the related fees charged by the railroads, for which we were reimbursed by our customers. Both the fees charged by the railroads to us and the reimbursement of these fees by our customers are included in our consolidated statements of operations in the revenues and operating costs line items entitled “Freight and other reimbursables.”

How We Evaluate Our Operations

Our management uses a variety of financial and operating metrics to evaluate our operations. When we evaluate our consolidated operations and related liquidity, 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. When evaluating our operations at the segment level, we evaluate using Segment Adjusted EBITDA. Refer to Part I, Item 8. Financial Statements and Supplementary Data, Note 14. Segment Reporting.

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 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,
	2020		2019		2020		2019
	(in thousands)
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA and Distributable cash flow:
Net cash provided by operating activities	$	16,634	$	14,648	$	33,760	$	34,155
Add (deduct):
Amortization of deferred financing costs	(208)		(208)		(622)		(865)
Deferred income taxes	722		(104)		1,263		299
Changes in accounts receivable and other assets	(69)		(2,498)		2,068		(200)
Changes in accounts payable and accrued expenses	(545)		(9)		687		(2,018)
Changes in deferred revenue and other liabilities	(2,365)		(2,666)		(5,187)		(5,128)

Interest expense, net	2,036		2,983		7,004		9,133
Provision for (benefit from) income taxes	(307)		414		(626)		612
Foreign currency transaction loss (gain) (1)	(246)		35		812		237
Other income	—		(27)		—		(69)

Non-cash deferred amounts (2)	(16)		1,435		1,540		1,545

Adjusted EBITDA	15,636		14,003		40,699		37,701
Add (deduct):
Cash paid for income taxes	(190)		(297)		(623)		(904)
Cash paid for interest	(1,880)		(3,045)		(6,837)		(8,860)
Maintenance capital expenditures	(16)		(131)		(130)		(176)
Distributable cash flow	$	13,550	$	10,530	$	33,109	$	27,761

(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 our 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.

Operating Costs

Our operating costs are comprised primarily of subcontracted rail services, 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. We expect to incur additional operating costs, including subcontracted rail services and pipeline fees, when we handle additional volumes at our terminals.

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 operations.

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 and recent developments 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, 2019. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results. The unprecedented nature of the COVID-19 pandemic, its impact on world economic conditions and the decline in the oil and natural gas markets have created increased uncertainty with respect to future conditions and our ability to accurately predict future results.

Casper Terminal Customer Contract Expirations and Goodwill Impairment

The final legacy terminalling services agreement at our Casper Terminal expired at the end of August 2019 and was not renewed or extended. 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. The revenue provided by the current agreements at our Casper terminal, certain of which contain take-or-pay terms for storage services and variable fees associated with actual throughput volumes and other services, may be less predictable than the revenue historically provided by the legacy contracts, which were based on minimum volume commitments. We have not yet entered into arrangements to replace all of the revenue previously provided by the legacy contracts at the Casper Terminal.

In July 2019, Enbridge Inc. announced a program to increase the capacity of the Express pipeline by up to an additional 50,000 bpd with the use of DRA and pump stations. 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. Our ability to secure additional commercial opportunities and replace the revenue previously generated under the expired contracts may be limited until Enbridge successfully completes its DRA project. In late July 2020, Enbridge announced that it had placed 25,000 bpd of the additional capacity on its Express pipeline into service and plans to place the additional 25,000 bpd into service during 2021.

In Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — General Trends and Outlook — Casper Terminal Customer Contract Renewals and Expirations in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019, we previously disclosed that we may recognize an impairment of the Casper terminal’s goodwill under certain conditions. In March 2020, in light of the overall downturn in the crude oil market and the decline in the demand for petroleum products, we tested the goodwill associated with our Casper terminal for impairment since such downturn could lead to delays or reductions of expected throughput levels and changes in expectations for current contracts in place at the Casper terminal. As a result of our impairment testing, we recognized an impairment loss of $33.6 million of goodwill associated with our Casper terminal for the nine months ended September 30, 2020. Refer to Part I. Item 1. Financial Statements, Note 8. Goodwill and Intangible Assets of this Report for further discussion.

Income Taxes

In June 2019, the Canadian Province of Alberta enacted a tax rate decrease that reduces 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 will be phased in over three years beginning with a reduction to an 11% rate effective July 1, 2019, with further reductions of 1% in each successive year until it reaches 8% on January 1, 2022. In October 2020, the Alberta Government introduced legislation to accelerate the income tax rate reduction to 8% effective July 1, 2020. We expect that this legislation will be enacted during the fourth quarter of 2020.

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.

Casper Terminal Customer Contract Expirations and Goodwill Impairment

Our last legacy terminalling services agreement at our Casper Terminal expired at the end of August 2019 and was not renewed or extended. The expired agreement contributed $9.3 million to our “Terminalling Services” revenue and $6.5 million of Adjusted EBITDA during the twelve months preceding the expiration of the agreement. Furthermore, in March 2020, we tested the goodwill associated with our Casper terminal for impairment due to the overall downturn in the crude market and the decline in the demand for petroleum products, which could lead to delays or reductions of expected throughput levels and changes in expectations for current contracts in place at the Casper terminal. As a result of our impairment testing, we recognized an impairment loss of $33.6 million for the nine months ended September 30, 2020.

Income Tax

In June 2019, the Canadian Province of Alberta enacted a tax rate decrease that reduces 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 will be phased in over three years beginning with a reduction to an 11% rate 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 income tax rate on business income for Alberta businesses in 2020 is 10% as of September 30, 2020. The rate in 2019 was 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.

CARES Act

On March 27, 2020, United States legislation referred to as the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”), was signed into law. The CARES Act is an emergency economic stimulus package enacted in response to the coronavirus outbreak which, among other measures, contains numerous income tax provisions. Some of these tax provisions are expected to be effective retroactively for tax years ending before the date of enactment. For us, the most significant change included in the CARES Act was the impact to U.S. net operating loss carryback provisions. U.S. net operating losses incurred in tax years 2018, 2019, and 2020 can now be fully carried back to the preceding five tax years and may be used to fully offset taxable income (i.e. they are not subject to the 80 percent net income offset limitation of Section 172 of the U.S. Tax Code).

As a result of these CARES Act changes, for the three and nine months ended September 30, 2020, we recognized a current tax benefit of $3 thousand and $533 thousand, respectively, for a claimable tax refund by carrying back U.S. net operating losses incurred in 2018, 2019, and in the first nine months of 2020. We also recognized a one-time deferred tax expense of $46 thousand in the first quarter of 2020 due to the net effect of utilizing all U.S. net operating loss deferred tax assets and releasing the corresponding U.S. valuation allowance as of December 31, 2019. We expect to recognize an additional tax benefit in 2020 due to anticipated tax losses. The tax impacts of the CARES Act were computed with the best available information, and will be adjusted after the 2020 U.S. tax return is finalized. However, we do not expect these adjustments to result in a material change to the tax provision in future periods.

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 each of the periods indicated:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in thousands)
Operating income (loss)
Terminalling services	$	11,590	$	8,466	$	(6,899)	$	25,165
Fleet services	39		25		(9)		30
Corporate and other	(2,733)		(2,760)		(8,695)		(8,882)
Total operating income (loss)	8,896		5,731		(15,603)		16,313
Interest expense	2,045		3,005		7,040		9,174
Loss associated with derivative instruments	1,200		220		4,405		1,966
Foreign currency transaction loss (gain)	(246)		35		812		237
Other income, net	(33)		(49)		(876)		(52)
Provision for (benefit from) income taxes	(307)		414		(626)		612
Net income (loss)	$	6,237	$	2,106	$	(26,358)	$	4,376

Summary Analysis of Operating Results

Changes in our operating results for the three and nine months ended September 30, 2020, as compared with our operating results for the three and nine months ended September 30, 2019, were primarily driven by:

•activities associated with our terminalling services business including:

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

◦higher revenue associated with revenue that was recognized in the first nine months of 2020 that we previously deferred associated with the make-up right options we granted to customers of our Hardisty terminal;

◦higher revenue due to higher rates at our Stroud terminal during the current quarter that are based on crude oil pricing index differentials;

◦lower operating income (loss) resulting from the conclusion of a contract at our Casper terminal in August 2019 and lower subcontracted rail service costs due to lower throughput;

◦higher operating costs resulting from a non-cash impairment of the goodwill associated with our Casper terminal due to current economic conditions as a result of the COVID-19 pandemic, the overall downturn in the crude market and the decline in the demand for petroleum products.

•a decrease in interest expense due to lower weighted average interest rates;

•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 benefit from income taxes associated with our fleet services segment primarily related to net operating loss carrybacks made available by provisions in the CARES Act coupled with a tax recovery recognized in the current quarter on the Canadian tax filings associated with an adjustment in the appropriate taxable economic return from our Hardisty terminal.

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,
	2020		2019		2020		2019
	(in thousands)
Revenues
Terminalling services	$	29,946	$	28,168	$	84,378	$	79,059
Freight and other reimbursables	32		220		681		748
Total revenues	29,978		28,388		85,059		79,807
Operating costs
Subcontracted rail services	2,300		3,689		8,433		10,953
Pipeline fees	5,936		5,411		17,678		15,374
Freight and other reimbursables	32		220		681		748
Operating and maintenance	3,375		3,934		11,067		7,622
Selling, general and administrative	1,315		1,368		4,455		4,628
Goodwill impairment loss	—		—		33,589		—
Depreciation and amortization	5,430		5,300		16,055		15,317
Total operating costs	18,388		19,922		91,958		54,642
Operating income (loss)	11,590		8,466		(6,899)		25,165


Foreign currency transaction loss (gain)	46		33		53		(62)
Other income, net	(25)		(45)		(864)		(44)
Provision for (benefit from) income taxes	(293)		406		(132)		596
Net income (loss)	$	11,862	$	8,072	$	(5,956)	$	24,675
Average daily terminal throughput (bpd)	18,143		131,482		71,649		110,829

Three Months Ended September 30, 2020 compared with the three months ended September 30, 2019

Terminalling Services Revenue

Revenue generated by our Terminalling services segment increased $1.6 million to $30.0 million for the three months ended September 30, 2020, as compared with the three months ended September 30, 2019. This increase was primarily due to higher rates at our Stroud terminal during the quarter that are based on crude oil pricing index differentials coupled with increased revenue at our Hardisty terminal resulting from increased rates in some of our contracts. The increases in revenues were partially offset by lower revenue at our Casper terminal resulting from the conclusion of a customer agreement in August 2019.

Our average daily terminal throughput decreased 113,339 bpd to 18,143 bpd for the three months ended September 30, 2020, as compared with 131,482 bpd for the three months ended September 30, 2019. Our throughput volumes decreased primarily due to a decrease in 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 decreased demand associated with our Hardisty terminal resulted from the narrowed WCS to WTI pricing spreads during the three months ended September 30, 2020, primarily as a result of the decline in global oil demand,

as described in Recent Developments- Market Update- COVID-19 and Crude Oil Pricing Environment Update. 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.

Our terminalling services revenue for the three months ended September 30, 2020, 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, 2020, was the same as the average exchange rate for the three months ended September 30, 2019. The average exchange rate for the Canadian dollar in relation to the U.S. dollar was 0.7506 for the three months ended September 30, 2020 as compared with 0.7575 for the three months ended September 30, 2019.

Operating Costs

The operating costs of our Terminalling services segment decreased $1.5 million to $18.4 million for the three months ended September 30, 2020, as compared with the $19.9 million for the three months ended September 30, 2019. The decrease was primarily attributable to a decrease in subcontracted rail services costs and lower operating and maintenance costs, partially offset by an increase in pipeline fees.

Our terminalling services operating costs for the three months ended September 30, 2020, 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, 2020, was the same as the average exchange rate for the three months ended September 30, 2019.

Subcontracted rail services. Our costs for subcontracted rail services decreased $1.4 million to $2.3 million for the three months ended September 30, 2020, from $3.7 million for the three months ended September 30, 2019, primarily due to the reduced throughput at our terminals discussed above.

Operating and maintenance. Operating and maintenance expense decreased $0.6 million to $3.4 million for the three months ended September 30, 2020, as compared with the three months ended September 30, 2019. The decreased operating and maintenance expenses are primarily due to a decrease in costs incurred pursuant to an 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.

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 at the corporate income tax rates enacted by the Canadian federal and provincial governments which totals 25% on a combined basis as of September 30, 2020.

Our income taxes for the Terminalling services segment decreased $0.7 million to a benefit of $0.3 million for the three months ended September 30, 2020, as compared with a provision of $0.4 million for the three months ended September 30, 2019. This decrease resulted primarily from a benefit recognized in the current quarter associated with the 2019 Canadian tax filings and an adjustment to the appropriate economic return from the Hardisty terminal.

Nine months ended September 30, 2020 compared with nine months ended September 30, 2019

Terminalling Services Revenue

Revenue generated by our Terminalling services segment increased $5.3 million to $85.1 million for the nine months ended September 30, 2020, as compared with $79.8 million for the nine months ended September 30, 2019. This increase was primarily due to increased revenue at our Hardisty terminal resulting from revenue recognized during the first nine months of 2020 for contracted capacity that exceeded the transloading capacity of the terminal pursuant to an agreement that commenced in July 2019. This revenue was offset by additional operating costs incurred pursuant to an agreement with a related party for providing terminalling services for the additional capacity on our behalf at the same rate, on a per barrel basis, that we received as revenue in the first nine months of 2020. Higher rates included in some of our terminalling services agreements that became effective July 1, 2019 at our Hardisty terminal due to our re-contracting efforts and increased rates in some of our contracts for the current quarter also contributed to the increase in revenues. Additionally, we recognized revenue in the first nine months of 2020 that we previously deferred associated with the make-up right options we granted to customers of our Hardisty terminal, as the likelihood that the make-up right options would be utilized in future periods was deemed remote and the make-up right options have now expired. In addition to the increases in revenue that were attributable to our Hardisty terminal, we also had increased revenue at our Stroud terminal in the current quarter due to higher rates that are based on crude oil pricing index differentials. These increases in revenues were partially offset by lower revenue at our Casper terminal resulting from the conclusion of a customer agreement in August 2019.

Our average daily terminal throughput decreased 39,180 bpd to 71,649 bpd for the nine months ended September 30, 2020, as compared with 110,829 bpd for the nine months ended September 30, 2019. Our throughput volumes decreased primarily due to a decrease in demand for export capacity by customers of our Hardisty terminal that occurred during the second quarter of 2020 and continued into the third quarter of 2020, a portion of which drives the demand for deliveries to our Stroud terminal and its connection to the Cushing oil hub. The decreased demand associated with our Hardisty terminal resulted from the narrowed WCS to WTI pricing spreads during the second and third quarters of 2020, primarily as a result of the decline in global oil demand, as described in Recent Developments- Market Update- COVID-19 and Crude Oil Pricing Environment Update. 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.

Our terminalling services revenue for the nine months ended September 30, 2020, would have been $1.0 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, 2020, was the same as the average exchange rate for the nine months ended September 30, 2019. The average exchange rate for the Canadian dollar in relation to the U.S. dollar was 0.7392 for the nine months ended September 30, 2020 as compared with 0.7524 for the nine months ended September 30, 2019.

Operating Costs

The operating costs of our Terminalling services segment increased $37.3 million to $92.0 million for the nine months ended September 30, 2020, as compared with the nine months ended September 30, 2019. The increase is primarily attributable to an impairment of our goodwill recognized in the first quarter of 2020 at our Casper terminal due to current economic conditions, an increase in operating and maintenance costs, higher pipeline fees and increased depreciation and amortization, partially offset by lower subcontracted rail services costs.

Our terminalling services operating costs for the nine months ended September 30, 2020, would have been $0.6 million more if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the nine months ended September 30, 2020, was the same as the average exchange rate for the nine months ended September 30, 2019.

Subcontracted rail services. Our costs for subcontracted rail services decreased $2.5 million to $8.4 million for the nine months ended September 30, 2020, as compared with the nine months ended September 30, 2019, primarily due to the reduced throughput at our terminals that occurred during the second and third quarters of 2020, as discussed above.

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 increased $2.3 million to $17.7 million for the nine months ended September 30, 2020, as compared with the nine months ended September 30, 2019, primarily due to higher revenues at our Hardisty terminal. Additionally, we recognized pipeline fees during the nine months ended September 30, 2020, associated with revenue that we previously deferred associated with the make-up right options we granted to customers of our Hardisty terminal, since the likelihood that the make-up right options would be utilized in future periods was deemed remote and the make-up right options have now expired.

Operating and maintenance. Operating and maintenance expense increased $3.4 million to $11.1 million for the nine months ended September 30, 2020, as compared with the nine months ended September 30, 2019. The increased operating and maintenance expenses are primarily due to expenses incurred pursuant to an agreement that commenced in July 2019 with a related party for providing terminalling services on our behalf 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.

Goodwill impairment loss. In March 2020, we tested the goodwill associated with our Casper terminal for impairment due to the overall downturn in the crude market and the decline in the demand for petroleum products. As a result of our impairment testing, we recognized an impairment loss of $33.6 million for the nine months ended September 30, 2020. Refer to Part I. Item 1. Financial Statements, Note 2. Recent Accounting Pronouncements and Note 8. Goodwill and Intangible Assets of this Quarterly Report for further discussion.

Depreciation and amortization. Depreciation and amortization expense increased $0.7 million to $16.1 million for the nine months ended September 30, 2020, as compared with the nine months ended September 30, 2019. The increase is primarily due to a revised estimate of our asset retirement obligations, or ARO, that decreased depreciation and amortization expense by $0.6 million in the first quarter of 2019 associated with our decommissioned San Antonio rail terminal as compared to a revised ARO estimate that decreased depreciation and amortization by only $0.2 million during the second quarter of 2020 associated with the same terminal, coupled with an increase in depreciation associated with the outbound pipeline at our Casper terminal that was placed into service in December 2019.

Other Expenses (Income)

Other income, net. Other income, net increased $0.8 million for the nine months ended September 30, 2020, as compared with the nine months ended September 30, 2019. This increase is primarily attributable to income that we earned in 2020 as an incentive for railcar movements of a customer at our Hardisty terminal associated with new railroad incentive agreements.

Our income taxes for the Terminalling services segment decreased $0.7 million to a benefit of $0.1 million for the nine months ended September 30, 2020, as compared with a provision of $0.6 million for the nine months ended September 30, 2019. This decrease resulted primarily from a benefit recognized in the third quarter of 2020 associated with the 2019 Canadian tax filings and an adjustment to the appropriate economic return from the Hardisty terminal.

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,
	2020		2019		2020		2019
	(in thousands)
Revenues
Fleet leases	$	984	$	984	$	2,951	$	2,951
Fleet services	278		277		834		840
Freight and other reimbursables	97		245		135		479
Total revenues	1,359		1,506		3,920		4,270
Operating costs
Freight and other reimbursables	97		245		135		479
Operating and maintenance	1,026		1,018		3,071		3,051
Selling, general and administrative	197		218		723		710
Total operating costs	1,320		1,481		3,929		4,240
Operating income (loss)	39		25		(9)		30
Foreign currency transaction loss (gain)	1		(2)		(2)		6
Other income, net	(8)		—		(8)		—
Provision for (benefit from) income taxes	(14)		8		(494)		16
Net income	$	60	$	19	$	495	$	8

Three Months Ended September 30, 2020 compared with the three months ended September 30, 2019

Revenues from our Fleet services segment decreased $0.1 million to $1.4 million for the three months ended September 30, 2020, as compared with $1.5 million for the three months ended September 30, 2019. 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 for the same reason.

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 it has then leased to customers. Although we expect to continue assisting our customers with obtaining railcars for their use transporting crude oil from our terminals, as our existing lease agreements expire, or are otherwise terminated, or assigned to our existing customers, 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, 2020 compared with nine months ended September 30, 2019

Revenues from our Fleet services segment decreased $0.4 million to $3.9 million for the nine months ended September 30, 2020, as compared with $4.3 million for the nine months ended September 30, 2019. The decrease in Freight and other reimbursables revenue and operating costs for the current period as compared to the same period in prior year were due to the same reasons cited above in our three month analysis.

Our benefit for income taxes in the Fleet services segment increased $0.5 million to a benefit of $0.5 million for nine months ended September 30, 2020 as compared with a provision of $16 thousand for the nine months ended September 30, 2019. This increase in benefit is due to a provision in the CARES Act that allows U.S. net operating losses incurred in tax years 2018, 2019, and 2020 to be carried back to the preceding five years and generate a tax

refund. Under prior guidance, these net operating losses could only be carried forward.

CORPORATE ACTIVITIES

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in thousands)
Operating costs
Selling, general and administrative	$	2,733	$	2,760	$	8,695	$	8,882
Operating loss	(2,733)		(2,760)		(8,695)		(8,882)
Interest expense	2,045		3,005		7,040		9,174
Loss associated with derivative instruments	1,200		220		4,405		1,966
Foreign currency transaction loss (gain)	(293)		4		761		293
Other income, net	—		(4)		(4)		(8)

Net loss	$	(5,685)	$	(5,985)	$	(20,897)	$	(20,307)

Three Months Ended September 30, 2020 compared with the three months ended September 30, 2019

Costs associated with our corporate activities decreased $0.3 million to $5.7 million for the three months ended September 30, 2020, as compared to $6.0 million for the three months ended September 30, 2019. Our interest expense costs decreased $1.0 million to $2.0 million primarily due to a decrease in interest rates we were charged under our Credit Agreement during the three months ended September 30, 2020, as compared to the same period in 2019.

In addition, we incurred a non-cash loss of $1.2 million on our interest rate derivatives for the three months ended September 30, 2020, as compared to a non-cash loss of $0.2 million for the same period in 2019. In September 2020, we terminated our existing interest rate collar and simultaneously entered into a new interest rate swap that was made effective as of August 2020. In lieu of settling the liability value of the existing interest rate collar agreement of $3.5 million that existed at the time the agreement was terminated, the value of the liability was rolled into the fixed rate of the new interest rate swap agreement. The new interest rate swap is a five-year contract with a $150 million notional value that fixes our one-month LIBOR to 0.84% for the notional value of the swap agreement instead of the variable rate that we pay under our Credit Agreement. The swap settles monthly through the termination date in August 2025.

Nine months ended September 30, 2020 compared with nine months ended September 30, 2019

Costs associated with our corporate activities increased $0.6 million to $20.9 million for the nine months ended September 30, 2020 as compared with the same period in 2019. Our costs for interest expense decreased $2.1 million to $7.0 million for the nine months ended September 30, 2020, as compared with the same period in 2019, due to the same reasons cited above in our three month analysis. In addition, we incurred a higher non-cash loss of $4.4 million on our interest rate derivatives for the nine months ended September 30, 2020, as compared to a non-cash loss of $2.0 million for the same period in 2019 as discussed above in our three month analysis. We also had a foreign currency transaction loss of $0.8 million for the nine months ended September 30, 2020 primarily due to repayments and anticipated repayments to us related to an intercompany loan with one of our consolidated subsidiaries.

LIQUIDITY AND CAPITAL RESOURCES

Our principal liquidity requirements include:

•financing current operations;

•servicing our debt;

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

•making distributions to our unitholders.

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

Liquidity Sources

We expect our ongoing sources of liquidity to include borrowings under our senior secured credit agreement, issuances of debt securities and additional partnership interests 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 at current levels for the next 12 months.

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, 2019 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, 2020		December 31, 2019
	(in millions)
Cash and cash equivalents (1)	$	6.9	$	3.1
Aggregate borrowing capacity under Credit Agreement	385.0		385.0

Less: Revolving Credit Facility amounts outstanding	209.0		220.0

Available liquidity based on Credit Agreement capacity (2)	$	182.9	$	168.1
Available liquidity based on Credit Agreement covenants (2)	$	44.1	$	31.9

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

(2) Pursuant to the terms of our Credit Agreement, our borrowing capacity currently is limited to 4.5 times our trailing 12-month consolidated EBITDA, which equates to $37.2 million and $28.8 million of borrowing capacity available at September 30, 2020 and December 31, 2019, respectively.

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 is not in the ordinary course of business.

Cash Flows

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


	Nine Months Ended September 30,
	2020		2019
	(in thousands)
Net cash provided by (used in):
Operating activities	$	33,760	$	34,155
Investing activities	(395)		(7,072)
Financing activities	(29,809)		(25,840)
Effect of exchange rates on cash	293		497
Net change in cash, cash equivalents and restricted cash	$	3,849	$	1,740

Operating Activities

Net cash provided by operating activities decreased $0.4 million to $33.8 million for the nine months ended September 30, 2020, as compared with $34.2 million for the nine months ended September 30, 2019. The decrease in net cash provided by operating activities was primarily due to the timing of receipts and payments on accounts receivable, accounts payable and deferred revenue balances.

Investing Activities

Net cash used in investing activities decreased to $0.4 million for the nine months ended September 30, 2020 compared to $7.1 million for the nine months ended September 30, 2019 primarily due to the construction of the outbound pipeline connection from our Casper terminal to the Platte terminal located at the termination point of the Express pipeline that was placed into service in December 2019.

Financing Activities

Net cash used in financing activities increased to $29.8 million for the nine months ended September 30, 2020 from $25.8 million for the nine months ended September 30, 2019. Our net payments on our long-term debt during the nine months ended September 30, 2020 were $18.0 million higher than the net amounts we borrowed during the nine months ended September 30, 2019. Additionally, cash paid for distributions decreased during the nine months ended September 30, 2020, as compared to the same period in 2019.

Cash Requirements

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

Capital Requirements

Our historical capital expenditures have primarily consisted of the costs to construct and acquire energy-related logistics assets. Our operations are expected to require investments to expand, upgrade or enhance existing facilities and to meet environmental and operational regulations. We also occasionally invest in our assets to expand their capacity or capability, such as the pipeline connection from our Casper Terminal to the Platte Terminal. We may incur unanticipated costs in connection with any expansion projects, which costs could be material or be incurred in periods after the project is completed.

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.

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 $130 thousand for maintenance capital expenditures during the nine months ended September 30, 2020. Our total expansion capital expenditures for the nine months ended September 30, 2020 were $0.3 million.

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, 2020, we received proceeds from borrowings of $12.0 million on our Revolving Credit Facility which we used for general partnership purposes and made repayments of $23.0 million on our Revolving Credit Facility from cash flow in excess of our operating and investing needs. Subsequent to September 30, 2020 and as of November 2, 2020, we have made additional repayments of $4.0 million of the outstanding balance of our Revolving Credit Facility. As of November 2, 2020, we had amounts outstanding of $205.0 million under the Revolving Credit Facility and $180.0 million available for borrowings under the Revolving Credit Facility based on capacity that is subject to certain covenants. Refer to Part I. Item 1. Financial Statements, Note 9. Debt of this Quarterly Report for more information.

Distributions

Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis, and we do not have a legal obligation to distribute any particular amount per common unit.

For the quarter ended September 30, 2020, the board of directors of our general partner determined that we had sufficient available cash after the establishment of cash reserves and the payment of our expenses to distribute $0.111 per unit on all of our units. Our current quarterly distribution of $0.111 per unit equates to $3.0 million per quarter, or $12.1 million per year, based on the number of common and general partner units outstanding as of November 3, 2020. This distribution represents a decrease of 70.0% from the distribution with respect to the fourth quarter of 2019, and is consistent with the distribution declared for the first and second quarters of 2020. Given the uncertainty in the energy industry, the board of directors made a proactive decision to strengthen our financial position by reducing our quarterly distribution and redeploying certain free cash flow to de-lever. During the second and third quarters of 2020, we made net repayments of $6 million and $9 million, respectively, of the outstanding balance of our Revolving Credit Facility. Subsequent to September 30, 2020 and as of November 2, 2020, we have made additional repayments of $4.0 million of the outstanding balance of our Revolving Credit Facility.

The board of directors of our general partner may change our distribution policy or suspend distributions at any time and from time to time. 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 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, 2019, 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. Historically, goodwill was only included in our Terminalling services segment as part of our Casper terminal reporting unit.

We did not amortize goodwill, but tested it for impairment annually based on the carrying amounts of our reporting units on the first day of the third quarter of each year or more frequently if impairment indicators arose that suggested the carrying amount of goodwill might 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 amount of goodwill, we made critical assumptions that included but were 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 recognized an impairment loss when the carrying amount of a reporting unit exceeded its implied fair value. We reduced the carrying amount of goodwill to its fair value at the time we determined that an impairment has occurred.

Our goodwill originated from our acquisition of the Casper terminal in November 2015 and was 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 was 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)a weighted average cost of capital of 12%;

2)a capital structure consisting of approximately 65% debt and 35% equity based on the capital structure of market participants;

3)a range of EBITDA multiples derived from equity prices of public companies with similar operating and investment characteristics, from 7.25x to 8.25x;

4)a range of EBITDA multiples for transactions based on actual sales and purchases of comparable businesses, from 8.0x to 9.0x; and

The key assumptions listed above were based upon economic and other operational conditions existing at or prior to our March 31, 2020 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.

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 the assumption 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 first quarter of 2020, we completed our goodwill impairment analysis and determined that the carrying amount of the Casper terminal reporting unit exceeded its fair value at March 31, 2020. Accordingly, we recognized an impairment loss of $33.6 million in our goodwill asset and included this charge in “Goodwill impairment loss” within our consolidated statement of operations for the nine months ended September 30, 2020. At September 30, 2020, we had no goodwill balance in our consolidated balance sheet.

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 amount exceeds the estimated fair value of the long-lived asset.

We determined the overall downturn in the crude market and the decline in the demand for petroleum products, which could lead to delays or reduction of expected throughput levels and changes in expectations for current and future contracts in our terminalling services at the Casper terminal was an event that required us to evaluate our Casper terminal asset group for impairment. We measured the fair value of our Casper terminal assets by using projections of the undiscounted cash flows expected to be derived from the operation and disposition of the Casper terminal asset.

The critical assumptions underlying our projections included the following:

2)expected volumes for our blended services business for distribution to local refiners;

3)a 15 year remaining useful life of the primary asset, represented by our property and equipment of the Casper terminal asset group; and

4)a residual value of 8.0x projected cash flows for the Casper terminal at the end of the 15 year remaining life of the primary asset.

our evaluation, indicating cash flows were expected to be sufficient to recover the carrying amount of the Casper terminal asset group. Accordingly, we did not recognize any impairment of our Casper terminal 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. Moreover, these assumptions may change over time in response to the effects of the COVID-19 pandemic and the state of the commodity markets, which are inherently uncertain and difficult to predict.

We have not observed any events or circumstances subsequent to our analysis at March 31, 2020 that would suggest the fair value of our Casper terminal asset is below its carrying amount as of September 30, 2020.

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, 2020. 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, 2020, 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, 2020 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, 2019 and in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020. We may be subject to additional risks and uncertainties that we currently consider immaterial or that are unknown to us but may have a material impact on our business, financial condition and results of operations.

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*						Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document

101.SCH*						Inline XBRL Schema Document

101.CAL*						Inline XBRL Calculation Linkbase Document

101.LAB*						Inline XBRL Label Linkbase Document

101.PRE*						Inline XBRL Presentation Linkbase Document

101.DEF*						Inline XBRL Definition Linkbase Document

104*						The cover page of the USD Partners LP Quarterly Report on Form 10-Q for the quarter ended September 30, 2020, formatted in Inline XBRL (included within the Exhibit 101 attachments)

* 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 5, 2020	By:	/s/ Dan Borgen
			Dan Borgen Chief Executive Officer and President (Principal Executive Officer)

Date:	November 5, 2020	By:	/s/ Adam Altsuler
			Adam Altsuler Senior Vice President and Chief Financial Officer (Principal Financial Officer)