USD Partners LP - Quarter Report: 2021 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, 2021


☐			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 1, 2021, there were 27,225,104 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	35
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	56
Item 4.	Controls and Procedures	56

PART II — OTHER INFORMATION

Item 1.	Legal Proceedings	57
Item 1A.	Risk Factors	57
Item 6.	Exhibits	57
SIGNATURES		59

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, development projects 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, 2020, 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,
	2021		2020		2021		2020
	(unaudited; in thousands of US dollars, except per unit amounts)
Revenues
Terminalling services	$	28,070	$	28,905	$	87,167	$	75,449
Terminalling services — related party	313		1,041		2,527		8,929


Fleet leases — related party	984		984		2,951		2,951
Fleet services	—		51		24		152
Fleet services — related party	227		227		682		682
Freight and other reimbursables	170		64		533		750
Freight and other reimbursables — related party	—		65		—		66
Total revenues	29,764		31,337		93,884		88,979
Operating costs
Subcontracted rail services	3,693		2,300		10,357		8,433
Pipeline fees	6,031		5,936		18,475		17,678
Freight and other reimbursables	170		129		533		816
Operating and maintenance	2,538		2,299		7,972		7,944
Operating and maintenance — related party	1,959		2,102		6,150		6,194
Selling, general and administrative	2,596		2,510		8,063		8,310
Selling, general and administrative — related party	1,649		1,735		4,951		5,563
Goodwill impairment loss	—		—		—		33,589
Depreciation and amortization	5,604		5,430		16,575		16,055
Total operating costs	24,240		22,441		73,076		104,582
Operating income (loss)	5,524		8,896		20,808		(15,603)
Interest expense	1,480		2,045		4,806		7,040
Loss (gain) associated with derivative instruments	(110)		1,200		(2,468)		4,405
Foreign currency transaction loss (gain)	294		(246)		192		812
Other expense (income), net	3		(33)		(13)		(876)
Income (loss) before income taxes	3,857		5,930		18,291		(26,984)
Provision for (benefit from) income taxes	49		(307)		439		(626)
Net income (loss)	$	3,808	$	6,237	$	17,852	$	(26,358)
Net income (loss) attributable to limited partner interests	$	3,744	$	6,131	$	17,553	$	(25,913)
Net income (loss) per common unit (basic and diluted)	$	0.13	$	0.23	$	0.65	$	(0.98)
Weighted average common units outstanding	27,225		26,844		27,161		26,403
Net income (loss) per subordinated unit (basic and diluted)	$	—	$	—	$	—	$	(0.04)
Weighted average subordinated units outstanding	—		—		—		382

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,
	2021		2020		2021		2020
	(unaudited; in thousands of US dollars)
Net income (loss)	$	3,808	$	6,237	$	17,852	$	(26,358)
Other comprehensive income (loss) — foreign currency translation	(924)		689		31		(916)
Comprehensive income (loss)	$	2,884	$	6,926	$	17,883	$	(27,274)

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,
	2021		2020
	(unaudited; in thousands of US dollars)
Cash flows from operating activities:
Net income (loss)	$	17,852	$	(26,358)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	16,575		16,055
Loss (gain) associated with derivative instruments	(2,468)		4,405
Settlement of derivative contracts	(829)		(631)
Unit based compensation expense	4,274		4,909
Loss associated with disposal of assets	11		—
Deferred income taxes	(225)		(1,263)
Amortization of deferred financing costs	622		622
Goodwill impairment loss	—		33,589
Changes in operating assets and liabilities:
Accounts receivable	12		892
Accounts receivable — related party	(182)		(758)
Prepaid expenses and other assets	1,467		(1,303)
Other assets — related party	(837)		(899)
Accounts payable and accrued expenses	684		(609)
Accounts payable and accrued expenses — related party	(84)		(78)
Deferred revenue and other liabilities	768		6,218
Deferred revenue and other liabilities — related party	44		(1,031)

Net cash provided by operating activities	37,684		33,760
Cash flows from investing activities:
Additions of property and equipment	(2,345)		(395)
Net cash used in investing activities	(2,345)		(395)
Cash flows from financing activities:
Distributions	(9,861)		(17,020)

Vested phantom units used for payment of participant taxes	(859)		(1,789)

Proceeds from long-term debt	—		12,000
Repayments of long-term debt	(23,000)		(23,000)

Net cash used in financing activities	(33,720)		(29,809)
Effect of exchange rates on cash	(135)		293
Net change in cash, cash equivalents and restricted cash	1,484		3,849
Cash, cash equivalents and restricted cash — beginning of period	10,994		10,684
Cash, cash equivalents and restricted cash — end of period	$	12,478	$	14,533

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

USD PARTNERS LP

CONSOLIDATED BALANCE SHEETS


	September 30, 2021		December 31, 2020
	(unaudited; in thousands of US dollars, except unit amounts)
ASSETS
Current assets
Cash and cash equivalents	$	4,392	$	3,040
Restricted cash	8,086		7,954
Accounts receivable, net	4,043		4,049
Accounts receivable — related party	2,658		2,460
Prepaid expenses	2,609		1,959

Other current assets	129		1,777
Other current assets — related party	259		15
Total current assets	22,176		21,254
Property and equipment, net	135,243		139,841
Intangible assets, net	52,037		61,492

Operating lease right-of-use assets	7,047		9,630
Other non-current assets	3,876		3,625
Other non-current assets — related party	2,290		1,706
Total assets	$	222,669	$	237,548

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable and accrued expenses	$	2,566	$	1,865
Accounts payable and accrued expenses — related party	299		383

Deferred revenue	5,569		6,367
Deferred revenue — related party	410		410
Operating lease liabilities, current	5,180		5,291
Other current liabilities	6,963		4,222
Other current liabilities — related party	28		—
Total current liabilities	21,015		18,538
Long-term debt, net	173,102		195,480



Operating lease liabilities, non-current	1,823		4,392
Other non-current liabilities	9,303		12,870
Other non-current liabilities — related party	16		—
Total liabilities	205,259		231,280
Commitments and contingencies
Partners’ capital
Common units (27,225,104 and 26,844,715 outstanding at September 30, 2021 and December 31, 2020, respectively)	14,806		3,829
General partner units (461,136 outstanding at September 30, 2021 and December 31, 2020)	2,026		1,892
Accumulated other comprehensive income	578		547
Total partners’ capital	17,410		6,268
Total liabilities and partners’ capital	$	222,669	$	237,548

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,
	2021			2020
	Units	Amount		Units	Amount
	(unaudited; in thousands of US dollars, except unit amounts)
Common units
Beginning balance at July 1,	27,224,441	$	13,100	26,843,674	$	(5,670)

Common units issued for vested phantom units	663	(2)		663	(1)

Net income	—	3,744		—	6,131
Unit based compensation expense	—	1,283		—	1,599
Distributions	—	(3,319)		—	(3,129)
Ending balance at September 30,	27,225,104	14,806		26,844,337	(1,070)








Subordinated units
Beginning balance at July 1,	—	—		—	—

Net income	—	—		—	—

Distributions	—	—		—	—
Ending balance at September 30,	—	—		—	—
General Partner units
Beginning balance at July 1,	461,136	2,018		461,136	1,784

Net income	—	64		—	106

Distributions	—	(56)		—	(54)
Ending balance at September 30,	461,136	2,026		461,136	1,836
Accumulated other comprehensive income (loss)
Beginning balance at July 1,		1,502			(1,732)
Cumulative translation adjustment		(924)			689
Ending balance at September 30,		578			(1,043)
Total partners’ capital at September 30,		$	17,410		$	(277)

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,
	2021			2020
	Units	Amount		Units	Amount
	(unaudited; in thousands of US dollars, except unit amounts)
Common units
Beginning balance at January 1,	26,844,715	$	3,829	24,411,892	$	61,013
Conversion of units	—	—		2,092,709	(23,423)
Common units issued for vested phantom units	380,389	(859)		339,736	(1,789)

Net income (loss)	—	17,553		—	(25,898)
Unit based compensation expense	—	3,979		—	4,749
Distributions	—	(9,696)		—	(15,722)
Ending balance at September 30,	27,225,104	14,806		26,844,337	(1,070)








Subordinated units
Beginning balance at January 1,	—	—		2,092,709	(22,597)
Conversion of units	—	—		(2,092,709)	23,423
Net income (loss)	—	—		—	(15)

Distributions	—	—		—	(811)
Ending balance at September 30,	—	—		—	—
General Partner units
Beginning balance at January 1,	461,136	1,892		461,136	2,767

Net income (loss)	—	299		—	(445)
Unit based compensation expense	—	—		—	1
Distributions	—	(165)		—	(487)
Ending balance at September 30,	461,136	2,026		461,136	1,836
Accumulated other comprehensive income (loss)
Beginning balance at January 1,		547			(127)
Cumulative translation adjustment		31			(916)
Ending balance at September 30,		578			(1,043)
Total partners’ capital at September 30,		$	17,410		$	(277)

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

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.

Basis of Presentation

Our accompanying unaudited interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States, or GAAP, for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all the information and disclosures required by GAAP for complete consolidated financial statements. In the opinion of our management, they contain all adjustments, consisting only of normal recurring adjustments, which our management considers necessary to present fairly our financial position as of September 30, 2021, our results of operations for the three and nine months ended September 30, 2021 and 2020, and our cash flows for the nine months ended September 30, 2021 and 2020. We derived our consolidated balance sheet as of December 31, 2020 from the audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2020. Our results of operations for the three and nine months ended September 30, 2021 and 2020 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, 2020.

COVID-19 Update

During 2020, the COVID-19 pandemic adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. As a result, beginning in March 2020, there was significant reductions in demand for crude oil, natural gas and natural gas liquids, which led to a decline in commodity prices. This drove Canadian producers to curtail production, which in turn resulted in lower crude oil supply levels and led

to lower throughput volume through our facilities. However, the decline in throughput volumes at our facilities did not have a material impact on our results of operations or cash flows during 2020, as a substantial amount of our terminalling services operating cash flows are generated from take-or-pay contracts with minimum monthly commitment fees with mainly investment grade customers. While production has generally returned to pre-COVID levels, there still remains significant uncertainty given the unprecedented and evolving nature of the COVID-19 pandemic and the state of the commodity markets. As such, we will continue to actively monitor their impact on our operations and financial condition.

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 accounts are translated into our reporting currency based on the average exchange rate for each monthly period. Fluctuations in the exchange rates 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.

2. RECENT ACCOUNTING PRONOUNCEMENTS

Recently Adopted Accounting Pronouncements

Income Taxes (ASU 2019-12)

In December 2019, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update No. 2019-12, or ASU 2019-12, which amends the FASB Accounting Standards Codification, or 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 adopted the provisions of ASU 2019-12 on January 1, 2021. Our adoption of this standard did not have an 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 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, 2021
	Common Units		Subordinated 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)	$	3,744	$	—	$	64	$	3,808
Less: Distributable earnings (2)	3,387		—		58		3,445
Excess net income	$	357	$	—	$	6	$	363
Weighted average units outstanding (3)	27,225		—		461		27,686
Distributable earnings per unit (4)	$	0.12	$	—
Underdistributed earnings per unit (5)	0.01		—
Net income per limited partner unit (basic and diluted) (6)	$	0.13	$	—

(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 $0.1185 per unit or $0.474 per unit on an annualized basis. Amounts presented for each class of units include a proportionate amount of the $164 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 1,409,713 equity-classified phantom unit awards outstanding as they were anti-dilutive for the period presented.

(7)In February 2020, the final tranche of 2,092,709 subordinated units were converted into common units and therefore there were no subordinated units outstanding during 2021. Refer to Note 16. Partners' Capital for more information.


	For the Three Months Ended September 30, 2020
	Common Units		Subordinated 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	$	—

(2)Represents the distributions paid for the period based upon the quarterly distribution amount of $0.111 per unit or $0.444 per unit 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.

(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 2020, the final tranche of 2,092,709 subordinated units were converted into common units. Refer to Note 16. Partners' Capital for more information.


	For the Nine Months Ended September 30, 2021
	Common Units		Subordinated 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)	$	17,553	$	—	$	299	$	17,852
Less: Distributable earnings (2)	9,955		—		168		10,123
Excess net income	$	7,598	$	—	$	131	$	7,729
Weighted average units outstanding (3)	27,161		—		461		27,622
Distributable earnings per unit (4)	$	0.37	$	—
Underdistributed earnings per unit (5)	0.28		—
Net income per limited partner unit (basic and diluted) (6)	$	0.65	$	—

(2)Represents the per unit distribution paid of $0.1135 per unit for the three months ended March 31, 2021, the per unit distribution paid of $0.116 per unit for the three months ended June 30, 2021, and $0.1185 distributable for the three months ended September 30, 2021, representing a year-to-date distribution of $0.348 per unit. Amounts presented for each class of units include a proportionate amount of the $325 thousand distributed and $164 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.

(6)Our computation of net income per limited partner unit excludes the effects of $1,409,713 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)		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 distributed 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 $456 thousand distributed to holders of the Equity-classified Phantom Units pursuant to the distribution equivalent rights granted under the USD Partners LP 2014 Amended and Restated Long-Term Incentive Plan.

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

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

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

(6)Our computation of net 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.

(7)In February 2020, the final tranche of 2,092,709 subordinated units were converted into common units. Refer to Note 16. Partners' Capital for more information.

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, 2021
	U.S.		Canada		Total
	(in thousands)
Third party	$	7,814	$	20,426	$	28,240
Related party	$	1,524	$	—	$	1,524


	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


	Nine Months Ended September 30, 2021
	U.S.		Canada		Total
	(in thousands)
Third party	$	25,306	$	62,418	$	87,724
Related party	$	6,160	$	—	$	6,160


	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

Remaining Performance Obligations

The transaction price allocated to the remaining performance obligations associated with our terminalling and fleet services agreements as of September 30, 2021 are as follows for the periods indicated:


	For the three months ending December 31, 2021		2022		2023		2024		Thereafter		Total
	(in thousands)
Terminalling Services (1) (2)	$	23,705	$	75,911	$	38,026	$	19,551	$	128,711	$	285,904
Fleet Services	227		1,195		—		—		—		1,422
Total	$	23,932	$	77,106	$	38,026	$	19,551	$	128,711	$	287,326

(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 0.7994 U.S. dollars for each Canadian dollar at September 30, 2021.

(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.

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, 2021		December 31, 2020
	(in thousands)
Other current assets	$	—	$	1,622

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 approximately 100% based on our expectations around usage of these options. Accordingly, we had no deferred revenues at September 30, 2021 for estimated breakage associated with the make-up rights options we granted to our customers. In addition, we had no deferred revenues associated with make-up rights at December 31, 2020.

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 current liabilities” and “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, 2021:


	December 31, 2020		Cash Additions for Customer Prepayments		Balance Sheet Reclassification		Revenue Recognized		September 30, 2021
	(in thousands)
Deferred revenue	$	6,367	$	5,569	$	—	$	(6,367)	$	5,569

Other current liabilities	$	—	$	—	$	4,077	$	(496)	$	3,581
Other non-current liabilities (1)	$	10,087	$	3,201	$	(4,077)	$	—	$	9,211

(1) 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 increased by $24 thousand due to the impact of the change in the end of period exchange rate between December 31, 2020 and September 30, 2021.

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 September 30, 2021 and December 31, 2020, respectively, 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,
	2021		2020
	(in thousands)
Cash and cash equivalents	$	4,392	$	6,928
Restricted Cash	8,086		7,605
Total cash, cash equivalents and restricted cash	$	12,478	$	14,533

6. PROPERTY AND EQUIPMENT

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


	September 30, 2021		December 31, 2020		Estimated Depreciable Lives (Years)
	(in thousands)
Land	$	10,295	$	10,288	N/A
Trackage and facilities	127,560		127,401		10-30
Pipeline	32,735		32,735		20-30
Equipment	17,607		17,337		3-20
Furniture	67		67		5-10
Total property and equipment	188,264		187,828
Accumulated depreciation	(55,701)		(48,630)
Construction in progress (1)	2,680		643
Property and equipment, net	$	135,243	$	139,841

(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.

Depreciation expense associated with property and equipment totaled $2.5 million and $2.3 million for the three months ended September 30, 2021 and 2020, respectively, and $7.1 million and $6.6 million for the nine months ended September 30, 2021 and 2020, respectively.

7. LEASES

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


	Nine Months Ended September 30, 2021
Weighted-average discount rate	5.7	%
Weighted average remaining lease term in years	2.32

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


		Three Months Ended September 30,				Nine Months Ended September 30,
		2021		2020		2021		2020
	(in thousands)

Operating lease cost		$	1,514	$	1,483	$	4,501	$	4,461
Short term lease cost		45		46		137		138
Variable lease cost		7		1		34		12
Sublease income		(1,347)		(1,341)		(4,043)		(4,024)
Total		$	219	$	189	$	629	$	587

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, 2021 (in thousands):


2021	$	1,630
2022	4,859
2023	147
2024	115
2025	113
Thereafter	622
Total lease payments	$	7,486
Less: imputed interest	(483)
Present value of lease liabilities	$	7,003

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,
	2021		2020		2021		2020
	(in thousands, except weighted average term)
Lease income (1)	$	2,078	$	2,545	$	6,432	$	7,097
Weighted average remaining lease term in years							3.60

(1)Lease income presented above includes lease income from related parties. Refer to Note 12. Transactions with Related Parties for additional discussion of lease income from a related party. Lease income associated with crude oil storage tanks we lease to customers of our terminals totaling $1.1 million and $1.5 million for the three months ended September 30, 2021 and 2020, and $3.5 million and $4.1 million for the nine months ended September 30, 2021 and 2020, 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, 2021 (in thousands):


2021	$	2,053
2022	7,669
2023	2,656
2024	2,663
2025	2,656
Thereafter	2,430
Total	$	20,127

8. 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, 2021		December 31, 2020
	(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	(73,967)		(64,520)
Other	(62)		(54)
Total accumulated amortization	(74,029)		(64,574)
Total intangible assets, net	$	52,037	$	61,492

Amortization expense associated with intangible assets totaled $3.2 million for the three months ended September 30, 2021 and 2020, and $9.5 million for the nine months ended September 30, 2021 and 2020.

9. DEBT

In November 2018, we amended and restated our senior secured credit agreement, which we originally established 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.

On October 29, 2021, we amended our Credit Agreement as discussed in more detail in Note 19 . Subsequent E vents.

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


	September 30, 2021		December 31, 2020
	(in thousands)

Revolving Credit Facility	$	174,000	$	197,000
Less: Deferred financing costs, net	(898)		(1,520)
Total long-term debt, net	$	173,102	$	195,480

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


	September 30, 2021		December 31, 2020
	(in millions)
Aggregate borrowing capacity under Credit Agreement	$	385.0	$	385.0
Less: Revolving Credit Facility amounts outstanding	174.0		197.0

Available under the Credit Agreement based on capacity	$	211.0	$	188.0
Available under the Credit Agreement based on covenants (1)	$	87.4	$	53.2

(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 $87.4 million and $53.2 million of borrowing capacity available at September 30, 2021 and December 31, 2020, respectively.

The weighted average interest rate on our outstanding indebtedness was 2.34% and 2.66% at September 30, 2021 and December 31, 2020, 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, 2021, 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,
	2021		2020		2021		2020
	(in thousands)
Interest expense on the Credit Agreement	$	1,272	$	1,837	$	4,184	$	6,418

Amortization of deferred financing costs	208		208		622		622
Total interest expense	$	1,480	$	2,045	$	4,806	$	7,040

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 $6.0 million and $5.9 million for the three months ended September 30, 2021 and 2020, respectively, and $18.5 million and $17.7 million for the nine months ended September 30, 2021 and 2020, 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 $1.0 million and $2.3 million at September 30, 2021 and December 31, 2020, respectively. As discussed in Note 4. Revenues, we have deferred revenue that represents cumulative revenue that has been deferred due to tiered billing provisions, which also results in a deferred pipeline fee expense that is recorded as assets on our Consolidated Balance Sheet. As such, we have included assets related to this agreement in “Prepaid expenses” of

$1.1 million at September 30, 2021 and “Other non-current assets” of $2.4 million and $2.9 million at September 30, 2021 and December 31, 2020, respectively, which we will recognize as expense concurrently with the recognition of the associated revenue at out Hardisty Terminal. We had no amounts related to this agreement in “Prepaid expenses” at December 31, 2020.

11. NONCONSOLIDATED VARIABLE INTEREST ENTITIES

Historically we entered into purchase, assignment and assumption agreements to assign payment and performance obligations for certain operating lease agreements with lessors, as well as customer fleet service payments related to these operating leases, with unconsolidated entities in which we had variable interests. These variable interest entities, or VIEs, included LRT Logistics Funding LLC, USD Fleet Funding LLC, USD Fleet Funding Canada Inc., and USD Logistics Funding Canada Inc. We treated those 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 were not the primary beneficiary of the VIEs, as we did not have the power to direct the activities that most significantly affected the economic performance of the VIEs, nor did we have the power to remove the managing member under the terms of the VIEs’ limited liability company agreements. Accordingly, we did not consolidate the results of the VIEs in our consolidated financial statements.

As of the end of February 2021, the remaining railcar leases associated with these VIEs were either assigned directly to our customers or have expired. As such, we have terminated our relationship with these VIEs discussed herein effective as of the end of February 2021.

The following table summarizes the total assets and liabilities between us and the VIEs as reflected in our consolidated balance sheet at December 31, 2020, as well as our maximum exposure to losses from entities in which we had a variable interest, but were not the primary beneficiary. Generally, our maximum exposure to losses was limited to amounts receivable for services we provided, reduced by any related liabilities.


	December 31, 2020
	Total assets		Total liabilities		Maximum exposure to loss
	(in thousands)
Accounts receivable	$	43	$	—	$	33

Deferred revenue	—		10		—

	$	43	$	10	$	33

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, 2021, owns 11,557,090 of our common units representing a 41.7% limited partner interest in us. As of September 30, 2021, 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.

USD Clean Fuels LLC, or USDCF, is a newly formed subsidiary of USD organized for the purpose of providing production and logistics solutions to the growing market for clean energy transportation fuels.

Omnibus Agreement

We are party to an omnibus agreement with USD, USDG and certain of their subsidiaries, or the 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.

In June 2021, we entered into an Amended and Restated Omnibus Agreement, or the Amended Omnibus Agreement, with USD, USDG and certain of their subsidiaries, which amends and restates the Omnibus Agreement, dated October 15, 2014, to extend the termination date of the right of first offer period, or ROFO Period, as defined in the Amended Omnibus Agreement, by an additional five years such that the ROFO Period will terminate on October 15, 2026 unless a Partnership Change of Control, as defined in the Amended Omnibus Agreement, occurs prior to such date.

The total amounts charged to us under the Omnibus Agreement for the three months ended September 30, 2021 and 2020 was $1.6 million and $1.7 million, respectively, and for the nine months ended September 30, 2021 and 2020 was $5.0 million and $5.6 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 with respect to these costs at September 30, 2021 and December 31, 2020, included in “Accounts payable and accrued expenses — related party” in our consolidated balance sheets.

From time to time, in the ordinary course of business, USD and its affiliates may receive vendor payments or other amounts due to us or our subsidiaries. In addition, we may make payments to vendors and other unrelated parties on behalf of USD and its affiliates for which they routinely reimburse us. We had a receivable balance at September 30, 2021 of $0.1 million related to these transactions included in “Accounts receivable — related party” within our consolidated balance sheet. We had no balance related to these transactions at December 31, 2020.

Marketing Services Agreement - Stroud Terminal

In connection with our purchase of the Stroud Terminal, we entered into a Marketing Services Agreement with USDM, or the Stroud Terminal MSA, 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 Stroud Terminal MSA during the periods presented in this Report are discussed below under the heading “Related Party Revenue and Deferred Revenue.”

Marketing Services Agreement - West Colton Terminal

In June 2021, we entered into a new Terminalling Services Agreement with USDCF that is supported by a minimum throughput commitment to USDCF from an investment-grade rated, refining customer as well as a performance guaranty from USD. The Terminal Services Agreement provides for the inbound shipment of renewable diesel on rail at our West Colton Terminal and the outbound shipment of the product on tank trucks to local consumers. The new terminalling services agreement has an initial term of five years with a target commencement date of December 1, 2021, and we are currently in the process of modifying our existing West Colton Terminal so that it will have the capability to transload renewable diesel in addition to the ethanol that it is currently transloading.

In exchange for the new terminalling agreement at our West Colton Terminal with USDCF discussed above, we also entered into a Marketing Services Agreement in June 2021, or the West Colton MSA, with USDCF pursuant to which we agreed to grant USDCF marketing and development rights pertaining to future renewable diesel opportunities associated with the West Colton Terminal in excess of the initial renewable diesel terminalling services agreement simultaneously executed in June 2021 between us and USDCF. These rights entitle USDCF to market all additional renewable diesel opportunities at the West Colton Terminal during the initial term of the USDCF agreement, and following the initial term of that agreement, all renewable diesel opportunities at the West Colton Terminal in excess of the throughput necessary to generate Adjusted EBITDA for the West Colton Terminal that is at least equal to the average monthly Adjusted EBITDA derived from the initial USDCF agreement during the 12 months prior to expiration of that agreement’s initial five-year term. Pursuant to the West Colton MSA, USDCF will fund any related capital costs associated with increasing the throughput or efficiency of the terminal to handle additional renewable diesel opportunities. In addition, we granted USDCF the right to develop other renewable diesel projects at the West Colton Terminal in exchange for a per barrel fee covering our associated operating costs. Any such development projects would be wholly-owned by USD and would be subject to the right of first offer with respect to midstream infrastructure developed by USD. There have been no payments made under the West Colton MSA during the periods presented in this Report.

Hardisty Terminal Services Agreement

We entered into a terminal services agreement with USDTC II in 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 $1.9 million and $2.1 million of expenses pursuant to the arrangement for the three months ended September 30, 2021 and 2020, respectively, and $6.1 million and $6.2 million for the nine months ended September 30, 2021 and 2020, respectively, 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 the agreement, we recorded a contract asset of $2.5 million and $1.7 million at September 30, 2021 and December 31, 2020, respectively, on our consolidated balance sheet in “Other current assets — related party” and “Other non-current assets — related party”, representing prepaid expense associated with this agreement due to tiered billing provisions in the related terminalling services agreements.

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 agreement with us. 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,
	2021		2020		2021		2020
	(in thousands)
Terminalling services — related party	$	313	$	1,041	$	2,527	$	8,929
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		—		66
	$	1,524	$	2,317	$	6,160	$	12,628

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, 2021		December 31, 2020
	(in thousands)
Accounts receivable — related party	$	2,658	$	2,460
Accounts payable and accrued expenses — related party (1)	$	42	$	64
Other current and non-current assets — related party (2)	$	2,549	$	1,721
Other current and non-current liabilities — related party (3)	$	44	$	—
Deferred revenue — related party (4)	$	410	$	410

(1)Does not include amounts payable to related parties associated with the Omnibus Agreement, as discussed above.

(2)Includes a contract asset associated with the Hardisty Terminal Services Agreement with USDTC II, as discussed above. Also includes a contract asset associated with a lease agreement with USDM. Refer to Note 4. Revenues for further discussion.

(3)Represents a contract liability associated with a lease agreement with USDM and cumulative revenue that has been deferred due to tiered billing provisions. Refer to Note 4. Revenues for further discussion.

(4)Represents deferred revenues associated with our fleet services agreements with USD and affiliates for amounts we have collected from them for their prepaid leases.

Cash Distributions

We paid the following aggregate cash distributions to USDG as a holder of our common 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 28, 2021	February 10, 2021	February 19, 2021	$	1,283	$	51
April 22, 2021	May 5, 2021	May 14, 2021	$	1,312	$	52
July 21, 2021	August 4, 2021	August 13, 2021	$	1,341	$	53

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 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 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.

Segment Allocation of Certain Selling, General and Administrative Costs

Historically, we have allocated certain selling, general and administrative expenses to our Terminalling services and Fleet services segments that included corporate function personnel costs for managing our business that are allocated to us by our general partner, as well as other administrative expenses including audit fees and certain consulting fees. Beginning with the first quarter in 2021, these selling, general, and administrative expenses that are not directly related to operating our Terminalling services and Fleet services segments will now be allocated to corporate selling, general, and administrative expenses to better reflect the financial results of our Terminalling services and Fleet services segments.


	Three Months Ended September 30, 2021
	Terminalling services		Fleet services		Corporate		Total
	(in thousands)
Revenues
Terminalling services	$	28,070	$	—	$	—	$	28,070
Terminalling services — related party	313		—		—		313

Fleet leases — related party	—		984		—		984
Fleet services	—		—		—		—
Fleet services — related party	—		227		—		227
Freight and other reimbursables	135		35		—		170
Freight and other reimbursables — related party	—		—		—		—
Total revenues	28,518		1,246		—		29,764
Operating costs
Subcontracted rail services	3,693		—		—		3,693
Pipeline fees	6,031		—		—		6,031
Freight and other reimbursables	135		35		—		170
Operating and maintenance	3,504		993		—		4,497
Selling, general and administrative	1,205		63		2,977		4,245
Goodwill impairment loss	—		—		—		—
Depreciation and amortization	5,604		—		—		5,604
Total operating costs	20,172		1,091		2,977		24,240
Operating income (loss)	8,346		155		(2,977)		5,524
Interest expense	—		—		1,480		1,480
Gain associated with derivative instruments	—		—		(110)		(110)
Foreign currency transaction loss (gain)	59		(1)		236		294
Other expense (income), net	4		—		(1)		3
Provision for income taxes	31		18		—		49
Net income (loss)	$	8,252	$	138	$	(4,582)	$	3,808


	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


	Nine Months Ended September 30, 2021
	Terminalling services		Fleet services		Corporate		Total
	(in thousands)
Revenues
Terminalling services	$	87,167	$	—	$	—	$	87,167
Terminalling services — related party	2,527		—		—		2,527

Fleet leases — related party	—		2,951		—		2,951
Fleet services	—		24		—		24
Fleet services — related party	—		682		—		682
Freight and other reimbursables	435		98		—		533
Freight and other reimbursables — related party	—		—		—		—
Total revenues	90,129		3,755		—		93,884
Operating costs
Subcontracted rail services	10,357		—		—		10,357
Pipeline fees	18,475		—		—		18,475
Freight and other reimbursables	435		98		—		533
Operating and maintenance	11,138		2,984		—		14,122
Selling, general and administrative	3,279		228		9,507		13,014
Goodwill impairment loss	—		—		—		—
Depreciation and amortization	16,575		—		—		16,575
Total operating costs	60,259		3,310		9,507		73,076
Operating income (loss)	29,870		445		(9,507)		20,808
Interest expense	—		—		4,806		4,806
Gain associated with derivative instruments	—		—		(2,468)		(2,468)
Foreign currency transaction loss (gain)	249		—		(57)		192
Other income, net	(11)		—		(2)		(13)
Provision from income taxes	373		66		—		439
Net income (loss)	$	29,259	$	379	$	(11,786)	$	17,852


	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)

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	2021		2020		2021		2020
	(in thousands)
Net income (loss)	$	8,252	$	11,862	$	29,259	$	(5,956)

Interest income (1)	—		(1)		(1)		(24)
Depreciation and amortization	5,604		5,430		16,575		16,055
Provision for (benefit from) income taxes	31		(293)		373		(132)
Foreign currency transaction loss (2)	59		46		249		53
Loss associated with disposal of assets	6		—		11		—
Goodwill impairment loss	—		—		—		33,589

Non-cash deferred amounts (3)	118		(16)		2,344		1,540

Segment Adjusted EBITDA	$	14,070	$	17,028	$	48,810	$	45,125

(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	2021		2020		2021		2020
	(in thousands)
Net income	$	138	$	60	$	379	$	495
Provision for (benefit from) income taxes	18		(14)		66		(494)
Interest income (1)	—		(8)		—		(8)
Foreign currency transaction loss (gain) (2)	(1)		1		—		(2)
Segment Adjusted EBITDA	$	155	$	39	$	445	$	(9)

(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. 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. 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 and foreign currency exchange rates, 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. 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, 2021		December 31, 2020
	(in thousands)

Other non-current assets	558		—
Other current liabilities	$	(1,091)	$	(1,086)
Other non-current liabilities	—		(2,743)
	$	(533)	$	(3,829)

We have not designated our derivative financial instruments as hedges of our interest rate exposure. As a result, changes in the fair value of these derivatives are recorded as “Loss (gain) associated with derivative instruments” in our consolidated statements of 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,
	2021		2020		2021		2020
	(in thousands)
Loss (gain) associated with derivative instruments	$	(110)	$	1,200	$	(2,468)	$	4,405

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, 2021		December 31, 2020
	Notional		Interest Rate Parameters		Fair Value		Fair Value
					(in thousands)
Swap Agreements
Swap maturing August 2025	$	150,000,000	0.84	%	$	(533)	$	(3,829)

16. 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.

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.

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 558,454 vested during the first nine months in 2021, of which 380,389 were converted into our common units after 178,065 Phantom Units were withheld from participants for the payment of applicable employment-related withholding taxes. The conversion of these Phantom Units did not have any economic impact on Partners’ Capital, since the economic impact is recognized over the vesting period. Additional information and discussion regarding our unit based compensation plans is included below in Note 17. Unit Based Compensation.

The board of directors of our general partner has adopted a cash distribution policy pursuant to which we intend to distribute at least the minimum quarterly distribution of $0.2875 per unit ($1.15 per unit on an annualized basis) on all of our units to the extent we have sufficient available cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. The board of directors of our general partner may change our distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis. The amount of distributions we pay under our cash distribution policy and the decision to make any distribution are determined by our general partner. For the quarter ended September 30, 2021, 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 $0.1185 per unit on all of our units.

17. UNIT BASED COMPENSATION

Long-term Incentive Plan

In 2021 and 2020, the board of directors of our general partner, acting in its capacity as our general partner, approved the grant of 667,543 and 694,140 Phantom Units, respectively, to directors and employees of our general partner and its affiliates under our A/R LTIP. At September 30, 2021, we had 509,589 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, 2020	40,065	1,324,837	$	10.98
Granted	40,065	573,204	$	4.82
Vested	(40,065)	(518,389)	$	11.33
Forfeited	—	(10,004)	$	8.27
Phantom Unit awards at September 30, 2021	40,065	1,369,648	$	8.18


	Director and Independent Consultant Phantom Units	Employee Phantom Units	Weighted-Average Grant Date Fair Value Per Phantom Unit
Phantom Unit awards at December 31, 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

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, 2020	13,136	59,284	$	10.58
Granted	13,136	41,138	$	4.82
Vested	(13,136)	—	$	10.15

Phantom Unit awards at September 30, 2021	13,136	100,422	$	7.88


	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

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, 2021 and 2020, we recognized $1.3 million and $1.6 million, respectively, and for the nine months ended September 30, 2021 and 2020, we recognized $4.3 million and $4.9 million, respectively, of compensation expense associated with outstanding Phantom Units. As of September 30, 2021, we have unrecognized compensation expense associated with our outstanding Phantom Units totaling $8.8 million, which we expect to recognize over a weighted average period of 2.28 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,
	2021		2020		2021		2020
	(in thousands)
Equity-classified Phantom Units (1)	$	164	$	152	$	477	$	781
Liability-classified Phantom Units	13		12		34		45
Total	$	177	$	164	$	511	$	826

(1) We reclassified $1 thousand to unit based compensation expense for DERs paid in relation to Phantom Units that have been forfeited for the three months ended September 30, 2021, and $8 thousand and $57 thousand for the nine months ended September 30, 2021 and 2020, respectively, for forfeitures. We had no reclassifications to unit based compensation expense for forfeitures for the three months ended September 30, 2020.

18. SUPPLEMENTAL CASH FLOW INFORMATION

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


	Nine Months Ended September 30,
	2021		2020
	(in thousands)
Cash paid for income taxes (1)	$	678	$	173
Cash paid for interest	$	4,296	$	6,837
Cash paid for operating leases	$	4,637	$	4,607

(1) Includes the net effect of tax refunds of $480 thousand received in the third quarter of 2020 associated with carrying back U.S. net operating losses incurred during 2020 and prior periods allowed for by the provisions of the CARES Act.

Non-cash Investing Activities

For the nine months ended September 30, 2021 and 2020, 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,
	2021		2020
	(in thousands)
Property and equipment financed through accounts payable and accrued expenses	$	29	$	(229)

We recorded $1.6 million and $3.1 million of right-of-use lease assets and the associated liabilities on our consolidated balance sheet as of September 30, 2021 and 2020, respectively, representing non-cash activities resulting from either new or extended lease agreements. See Note 7. Leases for further discussion.

19. SUBSEQUENT EVENTS

Distribution to Partners

On October 21, 2021, the board of directors of USD Partners GP LLC, acting in its capacity as our general partner, declared a quarterly cash distribution payable of $0.1185 per unit, or $0.474 per unit on an annualized basis, for the three months ended September 30, 2021. The distribution will be paid on November 12, 2021, to unitholders of record at the close of business on November 3, 2021. The distribution will include payment of $1.9 million to our

public common unitholders, $1.4 million to USDG as a holder of our common units and $55 thousand to USD Partners GP LLC as a holder of the general partner interest.

Revolving Credit Facility Amendment

On October 29, 2021, we entered into an amendment to our Credit Agreement, referred to as the Credit Agreement, as amended, with a syndicate of lenders. The Credit Agreement, as amended, extends the maturity date of the agreement by one year to November 2, 2023 and decreases the aggregate borrowing capacity of the facility from $385 million to $275 million. The Credit Agreement, as amended, also reflects the resignation of Citibank, N.A. as administrative agent and swing line lender under the facility and the appointment of Bank of Montreal as the successor administrative agent and swing line lender under the facility. The Credit Agreement, as amended, also includes an option to increase the maximum amount of credit available on the facility to $390 million, subject to receiving increased commitments from lenders and satisfaction of certain conditions. The terms and conditions of the Credit Agreement, as amended, are substantially similar to the terms and conditions in the Credit Agreement prior to the amendment, except that the Credit Agreement, as amended, sets forth provisions for replacing LIBOR with an alternative benchmark rate. After giving effect to the amendment, the Partnership has the ability to request one additional one-year maturity date extension, subject to the satisfaction of certain conditions, including consent of the lenders.

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, 2020. 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, 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 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’s Diluent Recovery Unit and Port Arthur Terminal Projects

USD, along with its partner, Gibson, are progressing on a long-term solution 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 and USD’s new destination terminal in Port Arthur, Texas, or PAT. Construction of the DRU and PAT

projects is complete and both the DRU and PAT are now operating in the start-up phase, and throughput volumes are consistent with contractual obligations and our customer’s expectations.

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 United States. DRUbit™ is a market access solution that will help 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. PAT is currently capable of receiving DRUbit™ by rail and diluent and C5 blends stocks from the newly constructed pipeline and by barge at the terminal. The terminal can facilitate the blending of the products on site through newly constructed storage tanks and deliver the blended product back through the pipeline or barged via the marine facility to U.S Gulf Coast refineries.

The successful commencement of USD’s DRU project enhances the sustainability and quality of our cash flows by significantly increasing the tenor of three terminalling services agreements at our Hardisty Terminal, representing approximately 32% of the terminal’s capacity, through mid-2031. Refer to the discussion in Commercial Developments — Hardisty and Stroud Terminal Services Agreements below for more detail.

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

Vaccination implementation and efforts to reopen the economy to date in 2021 have driven demand for crude oil and petroleum products to near pre-COVID levels. As a result, crude oil prices have recovered and stabilized at higher than pre-pandemic levels and continued to strengthen through the third quarter of 2021. In October of 2021, WTI prices topped $80 per barrel, which represents the highest price levels for WTI since 2014. Given these higher prices and currently tight discount levels in the Canadian heavy market, Canadian producers are achieving higher netbacks than pre-pandemic levels. We believe that if the increases in demand for oil and natural gas continue, global production levels will generally be higher during the remainder of 2021, continuing into 2022. However, there still remains significant uncertainty given the unprecedented and evolving nature of the COVID-19 pandemic, and the extent of any increases in demand and price levels are difficult to predict.

The broader implications of COVID-19 and volatile 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 a further extended period of time, COVID-19 related lockdowns or other restrictions are reinstated and/or oil prices decrease to 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 Annual Report on Form 10-K for the fiscal year ended December 31, 2020 for further discussion of certain risks relating to the COVID-19 pandemic.

Impact of Current Market Events

Given that crude oil prices have recovered and are higher than pre-COVID levels, Canadian production that was temporarily shut-in due to COVID-19 has also returned to pre-COVID levels. Additionally, in January 2021, the Canadian Association of Petroleum Producers, or CAPP, announced that they are forecasting more than a $3 billion dollar increase in planned upstream oil and gas spending as compared to 2020 levels. Recent quarterly earnings calls and announcements indicate that Canadian producers are generating excess cash flow and have expressed plans to reinvest the profits into production expansions and optimizations, which, to the extent such plans are carried out, we anticipate could drive supply to greater than pre-COVID levels through 2022.

Although supply has increased to date in 2021, relative to 2020, during the third quarter of 2021, specific unanticipated supply and demand events have delayed Canadian producers' return to crude by rail egress solutions. For example, planned and unplanned outages or maintenance on production assets of certain Canadian producers and COVID-19 impacts on planned ramp-up schedules created an unexpected reduction to Canadian supply during the third quarter of 2021. Additionally, pipeline projects previously anticipated to be delayed by the regulatory process went into service on schedule, creating additional pipeline egress capacity. The in-service activities of these pipelines in the U.S. and Canada create an incremental one-time demand for crude oil to satisfy pipeline line fill requirements, causing an additional draw on Canadian crude inventories. The specific supply reductions and one-time demand event increases during the third quarter of 2021 and carryover impacts of these events into the fourth quarter of 2021 have resulted in a temporary delay in the demand for Canadian crude by rail egress solutions that is expected to carry into 2022.

Despite the macro events impacting Western Canadian supply and demand balances described above, apportionment levels (representing the percentage of barrels nominated that were not shipped due to pipeline capacity constraints) on the primary heavy crude oil pipelines from Western Canada to the U.S. increased to an average of 53%. Crude inventory levels decreased during the third quarter of 2021 as compared to levels that existed at the end of the second quarter in 2021 due to those supply and demand events previously discussed but still remain at high levels on an annual relative basis. Consistent with the increases in supply and apportionment levels that have occurred throughout 2021, crude oil inventory levels increased by approximately 12% as of the end of the third quarter of 2021, as compared to levels at the end of the fourth quarter 2020.

Based on the forecasted crude oil production increases in Canada and higher apportionment and crude oil inventory levels, we expect that throughput volumes at our Hardisty Terminal will trend upwards from the low levels that existed during 2020, with the potential of reaching pre-COVID levels in 2022. 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.

Another factor that may contribute to the use of rail to export crude oil from Canada to the U.S. is the significant regulatory and legal obstacles that pipeline projects and existing pipelines experience in the U.S. For example, in March 2020, the government of Alberta announced that it had reached an agreement to make a $1.5 billion 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 January 2021, the new U.S. President issued an executive action that revoked the permit for the Keystone XL pipeline and in June 2021, the Keystone XL pipeline project was officially cancelled by TC Energy. 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, although the pipeline can operate until a decision is made by federal courts. Enbridge’s Line 5 is also in jeopardy of being shut down as Michigan’s

Governor previously demanded that the pipeline be shut down by May 12, 2021 and revoked a 1953 Michigan easement that allowed Line 5 to pass through the bottom of the Straits of Mackinac. Line 5 has continued to operate despite the Michigan Governor’s demand. The Army Corps of Engineers has since added an additional environmental impact study on a submerged tunnel included in the project which is expected to delay the project’s in service date to 2025. Most recently, to escalate the Line 5 dispute to the US Federal government, the Canadian government has invoked a Transit Pipelines Treaty that was established between US and Canada in 1977. As environmental, regulatory and political challenges to increase pipeline export capacity remain, crude by rail exports will remain a valuable egress solution.

In the long-term, as stated above, we expect demand for rail capacity at our terminals to continue 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 to pipeline projects persist. Our Hardisty and Casper Terminals, with established capacity and scalable designs, are well-positioned as strategic outlets to meet takeaway needs as Western Canadian crude oil supplies continue to exceed available pipeline takeaway capacity. Also, as discussed in more detail in our Annual Report on Form 10-K for the fiscal year ended December 31, 2020, USD is pursuing long-term solutions to transport heavier grades of crude oil produced in Western Canada through the construction of the DRU at the Hardisty Terminal. 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 origin-to-destination capabilities, to continue to result in long-term contract extensions and expansion opportunities across our terminal network.

Commercial Developments

Hardisty and Stroud Terminal Services Agreements

As previously discussed, construction of USD’s DRU project was completed in July 2021. The DRU is now operating in the start-up phase and throughput volumes are consistent with contractual obligations and our customer’s expectations. As such, the following changes to the terminalling services agreements at our Hardisty and Stroud terminals were made effective as of August 2021, as discussed in detail in Item 1 Business — Business Segments — Terminalling Services — Hardisty Terminal in our Annual Report on Form 10-K for the fiscal year ended December 31, 2020.

Effective August 2021, the maturity date of three terminalling services agreements that are with the existing DRU customer at our Hardisty Terminal have been extended through mid-2031, with two-thirds of the volume commitment with respect to one of these agreements terminating at the end of June 2022. Effective with these changes, approximately 32% of the Hardisty Terminal’s capacity has been extended through mid-2031.

Additionally effective August 2021, the existing DRU customer has elected to reduce its volume commitments at the Stroud Terminal attributable to the Partnership by one-third of the current commitment through June 2022, at which point the agreement will terminate and there will be no renewal period. The existing DRU customer has also elected to fully terminate the volume commitments attributable to USDM at the Stroud Terminal. Management believes that the lower utilization at the Stroud Terminal as a result of successful commencement of the DRU project will be short-term in nature and will allow the Partnership the opportunity to offer terminalling services to other customers that may be in need of access to the numerous markets connected to the Cushing oil hub.

To facilitate this, USDM is currently working on an expansion of the downstream connectivity at our Stroud Terminal that when completed will add a pipeline connection to a second storage tank at a third-party facility at the Cushing, Oklahoma crude oil hub, or the Cushing Hub. The expanded connectivity is expected to facilitate incremental rail-to-pipeline shipments of crude oil to the Cushing Hub by giving the Stroud Terminal better capability to service multiple customers and/or grades of crude oil simultaneously. The expansion is expected to be completed in the first quarter of 2022.

West Colton Renewable Diesel Project

In June 2021, we entered into a new Terminalling Services Agreement with USD Clean Fuels LLC, or USDCF, a newly formed subsidiary of USD, that is supported by a minimum throughput commitment to USDCF from an investment-grade rated, refining customer as well as a performance guaranty from USD. The Terminal Services Agreement provides for the inbound shipment of renewable diesel on rail at our West Colton Terminal and the outbound shipment of the product on tank trucks to local consumers. The new terminalling services agreement has an initial term of five years with a target commencement date of December 1, 2021, and we are currently in the process of modifying our existing West Colton Terminal so that it will have the capability to transload renewable diesel in addition to the ethanol that it is currently transloading. Refer to Liquidity and Capital Resources — Cash Requirements — Capital Requirements for more detail on the capital expenditures associated with this project.

In exchange for the new terminalling agreement at our West Colton Terminal with USDCF discussed above, we also entered into a Marketing Services Agreement with USDCF in June 2021, or the West Colton MSA, pursuant to which we agreed to grant USDCF marketing and development rights pertaining to future renewable diesel opportunities associated with the West Colton Terminal in excess of the terminalling services agreement with USDCF discussed above. Refer to Part I. Item 1. Financial Statements, Note 12. Transactions with Related Parties for further information.

Right of First Offer

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 and renewable diesel 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 one of our customers with leased railcars and fleet services related to the transportation of liquid hydrocarbons by rail on multi-year, take-or-pay terms under a master fleet services agreement. We do not own any railcars. As of September 30, 2021, our railcar fleet consisted of 200 railcars, which we lease from a railcar manufacturer, all of which are coiled and insulated, or C&I, railcars. The weighted average remaining contract life on our railcar fleet is 1.25 years as of September 30, 2021.

Under the master fleet services agreement, 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 customer typically pays 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.”

Also, we have historically 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 to assist our customers in obtaining railcars for their use transporting crude oil to or from our terminals, we do not intend to continue to act as an intermediary between railcar lessors and our customers as our existing lease agreements expire, are otherwise terminated, or are assigned to our existing customers. Should market conditions change, we could potentially act as an intermediary with railcar lessors on behalf of our customers again in the future.

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,
	2021		2020		2021		2020
	(in thousands)
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA and Distributable cash flow:
Net cash provided by operating activities	$	10,985	$	16,634	$	37,684	$	33,760
Add (deduct):
Amortization of deferred financing costs	(208)		(208)		(622)		(622)
Deferred income taxes	135		722		225		1,263
Changes in accounts receivable and other assets	(313)		(69)		(460)		2,068
Changes in accounts payable and accrued expenses	(54)		(545)		(600)		687
Changes in deferred revenue and other liabilities	(166)		(2,365)		(812)		(5,187)

Interest expense, net	1,479		2,036		4,803		7,004
Provision for (benefit from) income taxes	49		(307)		439		(626)
Foreign currency transaction loss (gain) (1)	294		(246)		192		812


Non-cash deferred amounts (2)	118		(16)		2,344		1,540

Adjusted EBITDA	12,319		15,636		43,193		40,699
Add (deduct):
Cash received (paid) for income taxes (3)	(144)		260		(678)		(173)
Cash paid for interest	(1,309)		(1,880)		(4,296)		(6,837)
Maintenance capital expenditures	(158)		(16)		(596)		(130)
Distributable cash flow	$	10,708	$	14,000	$	37,623	$	33,559

(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.

(3) Includes the net effect of tax refunds of $480 thousand received in the third quarter of 2020 associated with carrying back U.S. net operating losses incurred during 2020 and prior periods allowed for by the provisions of the CARES Act.

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, 2020. 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 volatility in the oil and natural gas markets have created increased uncertainty with respect to future conditions and our ability to accurately predict future results.

Hardisty and Stroud Terminals Customer Contract Renewals

Prior to August 2021, we had renewed and extended 100% of the capacity at our Hardisty Terminal through mid-2022, with approximately 73% extended through mid-2023 with customers under multi-year take-or-pay agreements. As previously discussed, construction of USD’s DRU project was completed in July 2021. The DRU is now operating in the start-up phase and throughput volumes are consistent with contractual obligations and our customer’s expectations. Effective August 2021, the maturity date of three terminalling services agreements that are with the existing DRU customer at our Hardisty Terminal have been extended through mid-2031, with two-thirds of the volume commitment with respect to one of these agreements terminating at the end of June 2022. Effective with these changes, approximately 32% of the Hardisty Terminal’s capacity has been extended through mid-2031. Due to the significantly longer contract tenor of the terminalling services agreements associated with the DRU volumes, contracted rates on an annual basis will be lower as compared to historical, shorter-term, agreements, which will result in lower cash flows to the Partnership on an annual basis, but support a higher net present value to the Partnership and provide a more predictable cash flow profile.

Additionally, certain of our terminalling services agreements at our Hardisty Terminal that expire in mid-2023 include a tiered rate structure that includes rate decreases that occur annually on July 1st of each year throughout the term of the agreement. We remain focused on renewing, extending or replacing our agreements at Hardisty that expire in mid-2022 and mid-2023 with new, multi-year take or pay commitments, including, if USD and Gibson are successful in securing additional customers at the DRU, on a long-term basis similar to the existing DRU customer.

Effective August 2021, the existing DRU customer has elected to reduce its volume commitments at the Stroud Terminal attributable to the Partnership by one-third of the current commitment through June 2022, at which point the agreement will terminate and there will be no renewal period. Management believes that the lower utilization at the Stroud Terminal as a result of successful commencement of the DRU project will be short-term in nature, and will allow the Partnership the opportunity to offer terminalling services to other customers that may be in need of access to the numerous markets connected to the Cushing oil hub.

Potential Impact of Hardisty and Stroud Deficiency Credit Usage by Our Customers

As previously discussed, customers of our Hardisty and Stroud Terminals are obligated to pay a minimum monthly commitment fee for the capacity to load an allotted number of unit trains, representing a specified number

of barrels per month. If a customer loads fewer unit trains than its allotted amount in any given month, that customer will receive a credit for up to 12 months, also referred to as a deficiency credit. This credit may be used to offset fees on throughput volumes in excess of the customer’s minimum monthly commitments in future periods to the extent capacity is available for the excess volume. Additionally, we could incur incremental costs associated with loading the additional trains for our customers if they have and use their accrued deficiency credits, but such costs are not expected to be material. As of March 31, 2021, we deferred revenues of $0.6 million that were associated with the expected usage of the deficiency credits during 2021. Based on current circumstances and conversations with our customers, as of September 30, 2021, we currently have no deferred revenues associated with the expected usage of deficiency credits.

Casper Terminal Customer Contract Renewals

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 believe that some of the additional volumes resulting from the increased capacity on the Express pipeline are currently being delivered to our Casper Terminal, as we have experienced a modest increase in throughput at the terminal during 2021.

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.

Impact of Hardisty and Stroud Terminals Contract Changes

As a result of the successful commencement of the DRU as previously discussed, effective August 1, 2021, the maturity date of three terminalling services agreements that are with the existing DRU customer at our Hardisty Terminal have been extended through mid-2031, with two-thirds of the volume commitment with respect to one of these agreements terminating at the end of June 2022. Effective with these changes, approximately 32% of the Hardisty Terminal’s capacity has been extended through mid-2031. Due to the significantly longer contract tenor of the terminalling services agreements associated with the DRU volumes, contracted rates on an annual basis will be lower as compared to historical, shorter-term, agreements, which will result in lower cash flows to the Partnership on an annual basis, but support a higher net present value to the Partnership and provide a more predictable cash flow profile. Additionally, effective August 1, 2021, the existing DRU customer has elected to reduce its volume commitments at the Stroud Terminal attributable to the Partnership by one-third of the previous commitment through June 2022, at which point the agreement will terminate and there will be no renewal period. We expect an approximate $2.0 million adverse impact to our “Net cash provided by operating activities” for the fourth quarter 2021 as a result of these changes.

Goodwill Impairment

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. We did not recognize a goodwill impairment loss for the nine months ended September 30, 2021.

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. 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 2020. We also recognized a one-time deferred tax expense of $46 thousand in the first nine months 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. The tax impacts of the CARES Act were computed with the best available information and any remaining refund is in the process of being claimed. We do not expect any material change to the tax provision in future periods associated with these refundable tax claims.

Segment Allocation of Certain Selling, General and Administrative Costs

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,
	2021		2020		2021		2020
	(in thousands)
Operating income (loss)
Terminalling services	$	8,346	$	11,590	$	29,870	$	(6,899)
Fleet services	155		39		445		(9)
Corporate and other	(2,977)		(2,733)		(9,507)		(8,695)
Total operating income (loss)	5,524		8,896		20,808		(15,603)
Interest expense	1,480		2,045		4,806		7,040
Loss (gain) associated with derivative instruments	(110)		1,200		(2,468)		4,405
Foreign currency transaction loss (gain)	294		(246)		192		812
Other expense (income), net	3		(33)		(13)		(876)
Provision for (benefit from) income taxes	49		(307)		439		(626)
Net income (loss)	$	3,808	$	6,237	$	17,852	$	(26,358)

Summary Analysis of Operating Results

Changes in our operating results for the three and nine months ended September 30, 2021, as compared with our operating results for the three and nine months ended September 30, 2020, were primarily driven by:

•activities associated with our Terminalling services business including:

–higher revenue at our Stroud Terminal due to higher rates during the year that are based on crude oil pricing index differentials, partially offset by lower revenues associated with a decrease in contracted volume commitments at the terminal that occurred during the third quarter of 2021 as discussed in more detail below;

–higher revenue at our Hardisty Terminal due to increased rates on certain of our Hardisty agreements when compared to the first nine months of 2020 and a favorable variance on the change in the Canadian exchange rate associated with our Canadian-dollar denominated contracts for 2021 as compared to 2020, partially offset by no recognition of previously deferred revenue during the first nine months of 2021 that had been deferred in a prior year associated with the make-up right options we granted to our customers as compared to the recognition of previously deferred revenue in the first nine months of 2020 associated with make-up rights;

–lower operating costs resulting primarily from a non-cash impairment of the goodwill that was recognized in the first quarter of 2020 associated with our Casper Terminal due to 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 with no comparable loss in 2021.

•a decrease in interest expense primarily due to lower interest rates coupled with a lower weighted average balance of debt outstanding;

•non-cash gains associated with increases in the fair value of our interest rate derivatives resulting from increases in the interest rate index upon which the derivative values are based in 2021 as compared to 2020; and

•an increase in the provision for income taxes associated with our Fleet services segment primarily resulting from a tax benefit that was recognized in 2020 associated with the net operating loss carrybacks that were made available and utilized by provisions in the CARES Act in 2020 with no similar tax benefits recognized in 2021.

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,
	2021		2020		2021		2020
	(in thousands)
Revenues
Terminalling services	$	28,383	$	29,946	$	89,694	$	84,378
Freight and other reimbursables	135		32		435		681
Total revenues	28,518		29,978		90,129		85,059
Operating costs
Subcontracted rail services	3,693		2,300		10,357		8,433
Pipeline fees	6,031		5,936		18,475		17,678
Freight and other reimbursables	135		32		435		681
Operating and maintenance	3,504		3,375		11,138		11,067
Selling, general and administrative	1,205		1,315		3,279		4,455
Goodwill impairment loss	—		—		—		33,589
Depreciation and amortization	5,604		5,430		16,575		16,055
Total operating costs	20,172		18,388		60,259		91,958
Operating income (loss)	8,346		11,590		29,870		(6,899)


Foreign currency transaction loss	59		46		249		53
Other expense (income), net	4		(25)		(11)		(864)
Provision for (benefit from) income taxes	31		(293)		373		(132)
Net income (loss)	$	8,252	$	11,862	$	29,259	$	(5,956)
Average daily terminal throughput (bpd)	99,654		19,635		101,537		72,150

Three months ended September 30, 2021 compared with the three months ended September 30, 2020

Terminalling Services Revenue

Revenue generated by our Terminalling services segment decreased $1.5 million to $28.5 million for the three months ended September 30, 2021, as compared with $30.0 million for the three months ended September 30, 2020. This decrease was primarily due to lower revenues at our Stroud Terminal during the quarter associated with the existing customer electing to reduce its contracted volume commitments by one-third of their previous commitment effective August 2021 as a result of the successful commencement of the DRU as discussed above in Factors Affecting the Comparability of our Financial Results. Partially offsetting this decrease was an increase in our Hardisty Terminal revenues that was primarily due to a favorable variance in the Canadian exchange rate on our Canadian-dollar denominated contracts during the third quarter of 2021 as compared to the third quarter of 2020, discussed in more detail below.

Our average daily terminal throughput increased 80,019 bpd to 99,654 bpd for the three months ended September 30, 2021, as compared with 19,635 bpd for the three months ended September 30, 2020. Our throughput volumes increased primarily due to an increase in demand for export capacity by customers of our Hardisty Terminal during the third quarter of 2021 that resulted from higher crude oil price levels and a wider average WCS to WTI pricing spread as compared to the decreased demand that existed in the third quarter of 2020 that resulted from the impacts of the COVID-19 pandemic. A portion of our Hardisty throughput volumes also drives the demand for deliveries to our Stroud Terminal and its connection to the Cushing oil hub, which also increased. Refer to Overview and Recent Developments — Market Update — COVID-19 and Crude Oil Pricing Environment Update for more information. 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, 2021, would have been $1.1 million less if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the three months ended September 30, 2021, was the same as the average exchange rate for the three months ended September 30, 2020. The average exchange rate for the Canadian dollar in relation to the U.S. dollar was 0.7942 for the three months ended September 30, 2021 as compared with 0.7506 for the three months ended September 30, 2020.

Operating Costs

The operating costs of our Terminalling services segment increased $1.8 million to $20.2 million for the three months ended September 30, 2021, as compared with $18.4 million for the three months ended September 30, 2020. The increase was primarily attributable to an increase in subcontracted rail services costs accompanied by an increase in our provision for income taxes.

Our terminalling services operating costs for the three months ended September 30, 2021, would have been $0.6 million less if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the three months ended September 30, 2021, was the same as the average exchange rate for the three months ended September 30, 2020.

Subcontracted rail services. Our costs for subcontracted rail services increased $1.4 million to $3.7 million for the three months ended September 30, 2021, as compared with $2.3 million for the three months ended September 30, 2020, primarily due to increased throughput at our terminals discussed above.

Selling, general and administrative. Selling, general and administrative expense decreased $0.1 million to $1.2 million for the three months ended September 30, 2021, as compared with $1.3 million for the three months ended September 30, 2020. The decrease is due to a change in the allocation of certain selling, general and administrative expenses from the Terminalling services segment to corporate that are not directly related to operating our Terminalling services segment that began in the first quarter of 2021. As such, there is a corresponding increase in corporate selling, general and administrative costs during the three months ended September 30, 2021, discussed below. Refer to Part I. Item 1. Financial Statements, Note 14. Segment reporting for further discussion on the change in segment cost allocation.

Other Expenses (Income)

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 Canadian corporate income taxes at the corporate income tax rates enacted by the Canadian federal and provincial governments which totals 23% on a combined basis as of September 30, 2021.

Our income taxes for the Terminalling services segment increased $0.3 million to a provision for income taxes compared with a benefit of $0.3 million for the three months ended September 30, 2020. This increase resulted primarily due to a benefit recognized in the Canadian tax filings for an adjustment to the appropriate economic return from the Hardisty Terminal in 2020, with no similar occurrence in 2021.

Nine months ended September 30, 2021 compared with nine months ended September 30, 2020

Terminalling Services Revenue

Revenue generated by our Terminalling services segment increased $5.1 million to $90.1 million for the nine months ended September 30, 2021, as compared with the nine months ended September 30, 2020. This increase was primarily due to higher revenues at our Stroud Terminal in the nine months ended September 30, 2021 due to higher rates that are based on crude oil pricing index differentials, partially offset by the decrease in contracted volume commitments that occurred during the third quarter of 2021, as discussed above in Factors Affecting the Comparability of our Financial Results. Additionally, we had increased rates on certain of our Hardisty agreements when compared to the first nine months of 2020. Our Hardisty Terminal also had an increase in revenues due to a favorable variance resulting from the Canadian exchange rate on our Canadian-dollar denominated contracts to date in 2021 as compared to the same period in 2020, discussed in more detail below. Partially offsetting these increases were revenues that were recognized in the first nine months of 2020 at our Hardisty Terminal that were previously deferred in prior periods associated with the make-up right options we granted to customers as these rights were deemed unlikely to be used in future periods, with no similar recognition of revenue occurring during the first nine months of 2021.

Our average daily terminal throughput increased 29,387 bpd to 101,537 bpd for the nine months ended September 30, 2021, as compared with 72,150 bpd for the nine months ended September 30, 2020. Throughput volumes at our Hardisty Terminal increased in 2021 on a year to date basis primarily due to an increase in throughput that occurred at the Hardisty Terminal during the second and third quarters of 2021 when compared to the prior period, resulting from higher crude oil price levels and a wider average WCS to WTI pricing spread as compared to the decreased demand that existed in the second and third quarters of 2020 that resulted from the impacts of the COVID-19 pandemic. In addition, a portion of our Hardisty throughput volumes also drives the demand for deliveries to our Stroud Terminal and its connection to the Cushing oil hub. Throughput at our Stroud Terminal increased during the first nine months of 2021 as compared to the first nine months of 2020. Partially offsetting the increase at Hardisty was a decrease in demand for export capacity by customers of our Hardisty Terminal that occurred during the first quarter of 2021 as compared to the relatively high level of demand that existed in the first quarter of 2020 prior to the impacts of the COVID-19 pandemic. Refer to Overview and Recent Developments — Market Update — COVID-19 and Crude Oil Pricing Environment Update for more information. In addition, extreme cold temperatures experienced in the first quarter of 2021 at our Stroud Terminal led to a decrease in throughput at our Hardisty and Stroud Terminals during the first quarter. 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, 2021, would have been $4.7 million less if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the nine months ended September 30, 2021, was the same as the average exchange rate for the nine months ended September 30, 2020. The average exchange rate for the Canadian dollar in relation to the U.S. dollar was 0.7994 for the nine months ended September 30, 2021 as compared with 0.7392 for the nine months ended September 30, 2020.

Operating Costs

The operating costs of our Terminalling services segment decreased $31.7 million to $60.3 million for the nine months ended September 30, 2021, as compared with $92.0 million for the nine months ended September 30, 2020. The decrease is primarily attributable to an impairment of our goodwill recognized in the first nine months of 2020 at our Casper Terminal due to economic conditions in 2020, coupled with lower selling, general and administrative costs for the nine months ended September 30, 2021. Partially offsetting these decreases in operating costs were increases in subcontracted rail services costs, pipeline fees and our provision for income taxes.

Our terminalling services operating costs for the nine months ended September 30, 2021, would have been $2.6 million less if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the nine

months ended September 30, 2021, was the same as the average exchange rate for the nine months ended September 30, 2020.

Subcontracted rail services. Our costs for subcontracted rail services increased $1.9 million to $10.4 million for the nine months ended September 30, 2021, as compared with the nine months ended September 30, 2020, primarily due to the increased throughput at our terminals that occurred during the current year, 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 $0.8 million to $18.5 million for the nine months ended September 30, 2021, as compared with $17.7 million for the nine months ended September 30, 2020, primarily due to higher revenues at our Hardisty Terminal. Partially offsetting this increase, during the first nine months of 2020 we recognized previously deferred pipeline fees associated with the make-up right options we granted to customers of our Hardisty Terminal, with no similar occurrence in 2021.

Selling, general and administrative. Selling, general and administrative expense decreased $1.2 million to $3.3 million for the nine months ended September 30, 2021, as compared with $4.5 million for the nine months ended September 30, 2020. The decrease is primarily due to a change in the allocation of certain selling, general and administrative expenses from the Terminalling services segment to corporate that are not directly related to operating our Terminalling services segment that began in the first quarter of 2021. As such, there is a corresponding increase in corporate selling, general and administrative costs during the first nine months of 2021, discussed below. Refer to Part I. Item 1. Financial Statements, Note 14. Segment reporting for further discussion on the change in segment cost allocation. Additionally, our Terminalling services segment selling, general and administrative costs decreased during the first nine months of the year as compared to the first nine months of 2020 due to lower costs allocated to us associated with the management and operations of our terminals.

Goodwill impairment loss. In the first nine months of 2021, we had no goodwill impairment loss compared to the $33.6 million impairment loss that was recognized in the first nine months of 2020. 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.

Other Expenses (Income)

Other income, net. Other income, net decreased $0.9 million for the nine months ended September 30, 2021, as compared with the nine months ended September 30, 2020. This decrease is primarily associated with a decrease in income earned as an incentive for railcar movements of a customer at our Hardisty Terminal.

Our income taxes for the Terminalling services segment increased $0.5 million to a provision of $0.4 million for the nine months ended September 30, 2021 as compared with a benefit of $0.1 million for the nine months ended September 30, 2020. This increase resulted primarily due to a benefit recognized in the Canadian tax filings for an adjustment to the appropriate economic return from the Hardisty Terminal in 2020, with no similar occurrence in 2021.

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,
	2021		2020		2021		2020
	(in thousands)
Revenues
Fleet leases	$	984	$	984	$	2,951	$	2,951
Fleet services	227		278		706		834
Freight and other reimbursables	35		97		98		135
Total revenues	1,246		1,359		3,755		3,920
Operating costs
Freight and other reimbursables	35		97		98		135
Operating and maintenance	993		1,026		2,984		3,071
Selling, general and administrative	63		197		228		723
Total operating costs	1,091		1,320		3,310		3,929
Operating income (loss)	155		39		445		(9)
Foreign currency transaction loss (gain)	(1)		1		—		(2)
Other income, net	—		(8)		—		(8)
Provision for (benefit from) income taxes	18		(14)		66		(494)
Net income	$	138	$	60	$	379	$	495

Three months ended September 30, 2021 compared with the three months ended September 30, 2020

The underlying business activities associated with our Fleet services segment have remained relatively constant for the three months ended September 30, 2021, as compared with three months ended September 30, 2020. As a result, we have experienced only modest changes in the operating revenues associated with this business. We expect only modest changes in the revenue results of our fleet services business for the near future.

Our selling, general and administrative expenses decreased $134 thousand to $63 thousand for the three months ended September 30, 2021 as compared with $197 thousand for the three months ended September 30, 2020. The decrease is due to a change in the allocation of certain selling, general and administrative expenses from the Fleet services segment to corporate that are not directly related to operating our Fleet services segment that began in the first quarter of 2021. As such, there is a corresponding increase in corporate selling, general and administrative costs during the current quarter as compared to the third quarter of 2020, discussed below. Refer to Part I. Item 1. Financial Statements, Note 14. Segment reporting for further discussion on the change in segment cost allocation.

Nine months ended September 30, 2021 compared with nine months ended September 30, 2020

The results for our Fleet services segment operating income for the nine months ended September 30, 2021, compared to the same period in 2020, changed for the same reasons as noted in the three month analysis above. In addition, our provision for income taxes in the Fleet services segment increased $0.6 million to a provision of $66 thousand for the nine months ended September 30, 2021 as compared with a benefit of $0.5 million for the nine months ended September 30, 2020. This increase in the provision is due to a benefit in 2020 that was associated with a provision in the CARES Act that allowed 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 for 2020. 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,
	2021		2020		2021		2020
	(in thousands)
Operating costs
Selling, general and administrative	$	2,977	$	2,733	$	9,507	$	8,695
Operating loss	(2,977)		(2,733)		(9,507)		(8,695)
Interest expense	1,480		2,045		4,806		7,040
Loss (gain) associated with derivative instruments	(110)		1,200		(2,468)		4,405
Foreign currency transaction loss (gain)	236		(293)		(57)		761
Other income, net	(1)		—		(2)		(4)

Net loss	$	(4,582)	$	(5,685)	$	(11,786)	$	(20,897)

Three months ended September 30, 2021 compared with the three months ended September 30, 2020

Costs associated with our corporate activities decreased $1.1 million to $4.6 million for the three months ended September 30, 2021, as compared to $5.7 million for the three months ended September 30, 2020.

Our corporate selling, general and administrative expenses increased $0.2 million to $3.0 million for the three months ended September 30, 2021 as compared with the three months ended September 30, 2021. The increase is due to a change in the allocation of certain selling, general and administrative expenses from the Terminalling services and Fleet services segments to corporate activities that are not directly related to operating our Terminalling services and Fleet services segments that began in the first quarter of 2021. As such, there is a corresponding decrease in both the Terminalling services and Fleet services segments selling, general and administrative costs during the three months ended September 30, 2021, as discussed above. Refer to Part I. Item 1. Financial Statements, Note 14. Segment reporting for further discussion on the change in segment cost allocation.

Our costs for interest expense decreased $0.6 million to $1.5 million for the three months ended September 30, 2021, as compared with the same period in 2020, primarily due to a decrease in interest rates we were charged under our Credit Agreement during the three months ended September 30, 2021 coupled with a lower weighted average balance of debt outstanding, as compared to the same period in 2020. In addition, we had a non-cash gain of $0.1 million recognized on our interest rate derivatives for the three months ended September 30, 2021, as compared to a non-cash loss of $1.2 million for the same period in 2020.

Nine months ended September 30, 2021 compared with nine months ended September 30, 2020

Costs associated with our corporate activities decreased $9.1 million to $11.8 million for the nine months ended September 30, 2021 as compared with $20.9 million for the same period in 2020 and changed for the same reasons as noted in the three month analysis above. In addition, we recognized a non-cash gain in our interest rate derivatives of $2.5 million for the nine months ended September 30, 2021 as compared to a non-cash loss of $4.4 million for the same period in 2020. Additionally, for the nine months ended September 30, 2020, we had a foreign currency transaction loss of $0.8 million primarily due to repayments and anticipated repayments to us related to an intercompany loan with one of our consolidated subsidiaries, with no similar occurrence in the first nine months of 2021.

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 following the filing of this Report.

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, 2020 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, 2021		December 31, 2020
	(in millions)
Cash and cash equivalents (1)	$	4.4	$	3.0
Aggregate borrowing capacity under Credit Agreement	385.0		385.0

Less: Revolving Credit Facility amounts outstanding	174.0		197.0

Available liquidity based on Credit Agreement capacity	$	215.4	$	191.0
Available liquidity based on Credit Agreement covenants (2)	$	91.8	$	56.2

(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 is limited to 4.5 times our trailing 12-month consolidated EBITDA, which equates to $87.4 million and $53.2 million of borrowing capacity available at September 30, 2021 and December 31, 2020, respectively.

On October 29, 2021, we entered into an amendment to our Credit Agreement, referred to as the Credit Agreement, as amended, with a syndicate of lenders. The Credit Agreement, as amended extends the maturity date of the agreement by one year to November 2, 2023 and decreases the aggregate borrowing capacity of the facility from $385 million to $275 million. Pursuant to the terms of our Credit Agreement, our borrowing capacity continues to be limited to 4.5 times our trailing 12-month consolidated EBITDA, which equates to $87.4 million of borrowing capacity available at September 30, 2021. The Credit Agreement, as amended, also reflects the resignation of Citibank, N.A. as administrative agent and swing line lender under the facility and the appointment of Bank of Montreal as the successor administrative agent and swing line lender under the facility. The Credit Agreement, as amended, also includes an option to increase the maximum amount of credit available on the facility to $390 million, subject to receiving increased commitments from lenders and satisfaction of certain conditions. The terms and conditions of the Credit Agreement, as amended, are substantially similar to the terms and conditions in the Credit Agreement prior to the amendment, except that the Credit Agreement, as amended, sets forth provisions for replacing LIBOR with an alternative benchmark rate. After giving effect to the amendment, the Partnership has the

ability to request one additional one-year maturity date extension, subject to the satisfaction of certain conditions, including consent of the lenders.

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,
	2021		2020
	(in thousands)
Net cash provided by (used in):
Operating activities	$	37,684	$	33,760
Investing activities	(2,345)		(395)
Financing activities	(33,720)		(29,809)
Effect of exchange rates on cash	(135)		293
Net change in cash, cash equivalents and restricted cash	$	1,484	$	3,849

Operating Activities

Net cash provided by operating activities increased $3.9 million to $37.7 million for the nine months ended September 30, 2021, as compared with $33.8 million for the nine months ended September 30, 2020. The increase in net cash provided by operating activities is primarily attributable to the changes in cash flow derived from our operating results as discussed above in Results of Operations. While our net income for the nine months ended September 30, 2021 was $44.2 million more than our net loss for the same period in 2020, the net loss from 2020 included a significant amount of non-cash expenses that increase our net loss but did not decrease cash flow, such as our goodwill impairment loss recognized in 2020 and the loss associated with derivative instruments in 2020 as compared to the non-cash derivative gain we recognized in 2021. The net change in net cash provided by operating activities was also impacted by the timing of receipts and payments on accounts receivable, accounts payable and deferred revenue balances.

Investing Activities

Net cash used in investing activities increased to $2.3 million for the nine months ended September 30, 2021 compared to $0.4 million for the nine months ended September 30, 2020 primarily due to project costs incurred in the first nine months of 2021 associated with the renewable diesel project at our West Colton Terminal. Refer to Overview and Recent Developments — Commercial Developments for more information.

Financing Activities

Net cash used in financing activities increased to $33.7 million for the nine months ended September 30, 2021 from $29.8 million for the nine months ended September 30, 2020. Our net payments on our long-term debt during the nine months ended September 30, 2021 were $12.0 million higher than the net payments during the nine months ended September 30, 2020, partially offset with a decrease in cash paid for distributions and participant withholding taxes associated with vested Phantom Units during the nine months ended September 30, 2021, as compared to the same period in 2020.

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. In association with our West Colton renewable diesel project, as previously discussed, we expect to incur a total of approximately $1.8 million in total capital expenditures, which we are funding from cash flows from operations. As of September 30, 2021 we have spent $1.7 million related to this project.

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 $0.6 million for maintenance capital expenditures during the nine months ended September 30, 2021. Our total expansion capital expenditures for the nine months ended September 30, 2021 were $1.7 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, 2021, we received no proceeds from borrowings on our Revolving Credit Facility and made repayments of $23.0 million on our Revolving Credit Facility from cash flow in excess of our operating and investing needs. 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, 2021, 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 $0.1185 per unit on all of our units. Our current quarterly distribution of $0.1185 per unit equates to $3.3 million per quarter, or $13.1 million per year, based on the number of common and general partner units outstanding as of November 3, 2021. This distribution represents an increase of 6.8% from the distribution with respect to the fourth quarter of 2020 and is the result of an improved outlook for our business and enhanced liquidity position, primarily resulting from net repayments totaling $50 million that reduced the outstanding balance on our Revolving Credit Facility since the end of the first quarter of 2020. Given the uncertainty in the energy industry that existed during 2020, the board of directors made a proactive decision to strengthen our financial position by reducing our quarterly distribution in 2020 from previous levels and redeploying certain free cash flow to de-lever. During the first nine months of 2021, we made a net repayment of $23.0 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 19. Subsequent events of our consolidated financial statements included in Part I — Financial Information, Item 1. Financial Statements of this Report for a discussion regarding subsequent events.

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, 2021. 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, 2021, 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, 2021 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, 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, 2021, 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 3, 2021	By:	/s/ Dan Borgen
			Dan Borgen Chief Executive Officer and President (Principal Executive Officer)

Date:	November 3, 2021	By:	/s/ Adam Altsuler
			Adam Altsuler Executive Vice President and Chief Financial Officer (Principal Financial Officer)