10-Q 1 usdp2019033110-q.htm 10-Q USD PARTNERS 3-31-2019 Document


 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2019
OR
¨
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
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    YES  x    NO  ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    YES  x    NO  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
       Large accelerated filer ¨
Accelerated filer x
       Non-accelerated filer ¨
Smaller reporting company x
 
Emerging growth company x
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. x
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   YES  ¨    NO  x
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
As of May 2, 2019 there were 24,410,226 common units, 2,092,709 subordinated units and 461,136 general partner units outstanding.
 




TABLE OF CONTENTS
Unless the context otherwise requires, all references in this Quarterly Report on Form 10-Q, or this “Report,” to “USD Partners,” “USDP,” “the Partnership,” “we,” “us,” “our,” or like terms refer to USD Partners LP and its subsidiaries.
Unless the context otherwise requires, all references in this Report to (i) “our general partner” refer to USD Partners GP LLC, a Delaware limited liability company; (ii) “USD” refers to US Development Group, LLC, a Delaware limited liability company, and where the context requires, its subsidiaries; (iii) “USDG” and “our sponsor” refer to USD Group LLC, a Delaware limited liability company and currently the sole direct subsidiary of USD; (iv) “Energy Capital Partners” refers to Energy Capital Partners III, LP and its parallel and co-investment funds and related investment vehicles; and (v) “Goldman Sachs” refers to The Goldman Sachs Group, Inc. and its affiliates.
Cautionary Note Regarding Forward-Looking Statements
This Report includes forward-looking statements, which are statements that frequently use words such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,” “position,” “projection,” “should,” “strategy,” “target,” “will” and similar words. Although we believe that such forward-looking statements are reasonable based on currently available information, such statements involve risks, uncertainties and assumptions and are not guarantees of performance. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Any forward-looking statement made by us in this Report speaks only as of the date on which it is made, and we undertake no obligation to publicly update any forward-looking statement. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include: (1) changes in general economic conditions; (2) the effects of competition, in particular, by pipelines and other terminalling facilities; (3) shut-downs or cutbacks at upstream production facilities, refineries or other related businesses; (4) the supply of, and demand for, terminalling services for crude oil and biofuels; (5) our limited history as a separate public partnership; (6) the price and availability of debt and equity financing; (7) hazards and operating risks that may not be covered fully by insurance; (8) disruptions due to equipment interruption or failure at our facilities or third-party facilities on which our business is dependent; (9) natural disasters, weather-related delays, casualty losses and other matters beyond our control; (10) changes in laws or regulations to which we are subject, including compliance with environmental and operational safety regulations, that may increase our costs; and (11) our ability to successfully identify and finance acquisitions and other growth opportunities. For additional factors that may affect our results, see “Item 1A. Risk Factors” included elsewhere in this Report and our Annual Report on Form 10-K for the fiscal year ended December 31, 2018, which is available to the public over the Internet at the website of the U.S. Securities and Exchange Commission, or SEC, (www.sec.gov) and at our website (www.usdpartners.com).



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PART I—FINANCIAL INFORMATION 
Item 1.     Financial Statements
USD PARTNERS LP
CONSOLIDATED STATEMENTS OF INCOME
 
Three Months Ended March 31,
 
2019
 
2018
 
(unaudited; in thousands of US dollars, except per unit amounts)
Revenues
 
 
 
Terminalling services
$
19,998

 
$
22,005

Terminalling services — related party
5,638

 
4,696

Fleet leases — related party
984

 
984

Fleet services
57

 
344

Fleet services — related party
227

 
227

Freight and other reimbursables
403

 
1,475

Freight and other reimbursables — related party
61

 
2

Total revenues
27,368

 
29,733

Operating costs
 
 
 
Subcontracted rail services
3,565

 
3,062

Pipeline fees
5,061

 
5,724

Freight and other reimbursables
464

 
1,477

Operating and maintenance
3,211

 
2,356

Selling, general and administrative
2,477

 
2,994

Selling, general and administrative — related party
2,450

 
1,830

Depreciation and amortization
4,734

 
5,276

Total operating costs
21,962

 
22,719

Operating income
5,406

 
7,014

Interest expense
3,187

 
2,485

Loss (gain) associated with derivative instruments
672

 
(1,024
)
Foreign currency transaction loss (gain)
182

 
(211
)
Other expense (income), net
(24
)
 
71

Income before income taxes
1,389

 
5,693

Provision for (benefit from) income taxes
70

 
(907
)
Net income
$
1,319

 
$
6,600

Net income attributable to limited partner interests
$
1,155

 
$
6,399

Net income per common unit (basic and diluted)
$
0.04

 
$
0.24

Weighted average common units outstanding
23,060

 
20,597

Net income per subordinated unit (basic and diluted)
$
0.03

 
$
0.24

Weighted average subordinated units outstanding
3,255

 
5,348



The accompanying notes are an integral part of these consolidated financial statements.
1




USD PARTNERS LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 
Three Months Ended March 31,
 
2019
 
2018
 
(unaudited; in thousands of US dollars)
Net income
$
1,319

 
$
6,600

Other comprehensive income (loss) — foreign currency translation
1,415

 
(1,790
)
Comprehensive income
$
2,734

 
$
4,810



The accompanying notes are an integral part of these consolidated financial statements.
2




USD PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
Three Months Ended March 31,
 
2019
 
2018
 
(unaudited; in thousands of US dollars)
Cash flows from operating activities:
 
 
 
Net income
$
1,319

 
$
6,600

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
4,734

 
5,276

Loss (gain) associated with derivative instruments
672

 
(1,024
)
Settlement of derivative contracts
1

 
(38
)
Unit based compensation expense
1,414

 
1,337

Deferred income taxes
(249
)
 
(1,290
)
Other
458

 
286

Changes in operating assets and liabilities:
 
 
 
Accounts receivable
691

 
(8,349
)
Accounts receivable — related party
(628
)
 
1,213

Prepaid expenses and other assets
753

 
(161
)
Other assets — related party
20

 
20

Accounts payable and accrued expenses
69

 
(887
)
Accounts payable and accrued expenses — related party
719

 
(378
)
Deferred revenue and other liabilities
198

 
5,499

Net cash provided by operating activities
10,171

 
8,104

Cash flows from investing activities:
 
 
 
Additions of property and equipment
(244
)
 
(78
)
Proceeds from the sale of assets

 
236

Net cash provided by (used in) investing activities
(244
)
 
158

Cash flows from financing activities:
 
 
 
Distributions
(10,133
)
 
(9,689
)
Payments for deferred financing costs
(7
)
 

Vested phantom units used for payment of participant taxes
(1,821
)
 
(1,346
)
Proceeds from long-term debt
9,000

 
9,000

Repayments of long-term debt
(11,000
)
 
(8,000
)
Other financing activities
(13
)
 

Net cash used in financing activities
(13,974
)
 
(10,035
)
Effect of exchange rates on cash
388

 
(678
)
Net change in cash, cash equivalents and restricted cash
(3,659
)
 
(2,451
)
Cash, cash equivalents and restricted cash  beginning of period
12,383

 
13,788

Cash, cash equivalents and restricted cash  end of period
$
8,724

 
$
11,337


The accompanying notes are an integral part of these consolidated financial statements.
3




USD PARTNERS LP
CONSOLIDATED BALANCE SHEETS

 
March 31, 2019
 
December 31, 2018
 
(unaudited; in thousands of US dollars, except unit amounts)
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
3,069

 
$
6,439

Restricted cash
5,655

 
5,944

Accounts receivable, net
4,462

 
5,132

Accounts receivable — related party
1,255

 
624

Prepaid expenses
1,681

 
2,115

Other current assets
477

 
634

Other current assets — related party
79

 
79

Total current assets
16,678

 
20,967

Property and equipment, net
146,635

 
145,308

Intangible assets, net
83,554

 
86,705

Goodwill
33,589

 
33,589

Operating lease right-of-use assets
15,581

 

Other non-current assets
255

 
631

Other non-current assets — related party
75

 
95

Total assets
$
296,367

 
$
287,295

 
 
 
 
LIABILITIES AND PARTNERS’ CAPITAL
 
 
 
Current liabilities
 
 
 
Accounts payable and accrued expenses
$
5,660

 
$
3,464

Accounts payable and accrued expenses — related party
1,179

 
460

Deferred revenue
2,980

 
2,921

Deferred revenue — related party
1,916

 
1,885

Operating lease liabilities, current
5,236

 

Other current liabilities
2,910

 
2,804

Total current liabilities
19,881

 
11,534

Long-term debt, net
204,028

 
205,581

Deferred income tax liabilities, net
119

 
360

Operating lease liabilities, non-current
10,682

 

Other non-current liabilities
120

 
356

Total liabilities
234,830

 
217,831

Commitments and contingencies

 

Partners’ capital
 
 
 
Common units (24,408,073 and 21,916,024 outstanding at March 31, 2019 and December 31, 2018, respectively)
80,539

 
107,903

Class A units (38,750 outstanding at December 31, 2018)

 
1,018

Subordinated units (2,092,709 and 4,185,418 outstanding at March 31, 2019 and December 31, 2018, respectively)
(20,555
)
 
(39,723
)
General partner units (461,136 outstanding at March 31, 2019 and
December 31, 2018)
3,147

 
3,275

Accumulated other comprehensive loss
(1,594
)
 
(3,009
)
Total partners’ capital
61,537

 
69,464

Total liabilities and partners’ capital
$
296,367

 
$
287,295


The accompanying notes are an integral part of these consolidated financial statements.
4




USD PARTNERS LP
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

 
Three Months Ended March 31,
 
2019
 
2018
 
Units
 
Amount
 
Units
 
Amount
 
(unaudited; in thousands of US dollars, except unit amounts)
Common units
 
 
 
 
 
 
 
Beginning balance
21,916,024

 
$
107,903

 
19,537,971

 
$
136,645

Conversion of units
2,131,459

 
(19,631
)
 
2,131,459

 
(18,245
)
Common units issued for vested phantom units
360,590

 
(1,821
)
 
244,794

 
(1,346
)
Net income

 
1,054

 

 
5,095

Unit based compensation expense

 
1,289

 

 
1,102

Distributions

 
(8,255
)
 

 
(7,126
)
Ending balance
24,408,073

 
80,539

 
21,914,224

 
116,125

Class A units
 
 
 
 
 
 
 
Beginning balance
38,750

 
1,018

 
82,500

 
1,468

Conversion of units
(38,750
)
 
(1,018
)
 
(38,750
)
 
(674
)
Net income

 

 

 
14

Unit based compensation expense

 
14

 

 
51

Forfeited units

 

 
(5,000
)
 
19

Distributions

 
(14
)
 

 
(28
)
Ending balance

 

 
38,750

 
850

Subordinated units
 
 
 
 
 
 
 
Beginning balance
4,185,418

 
(39,723
)
 
6,278,127

 
(55,237
)
Conversion of units
(2,092,709
)
 
20,637

 
(2,092,709
)
 
18,919

Net income

 
101

 

 
1,290

Unit based compensation expense

 
2

 

 
15

Distributions

 
(1,572
)
 

 
(2,291
)
Ending balance
2,092,709

 
(20,555
)
 
4,185,418

 
(37,304
)
General Partner units
 
 
 
 
 
 
 
Beginning balance
461,136

 
3,275

 
461,136

 
180

Net income

 
164

 

 
201

Unit based compensation expense

 

 

 
1

Distributions

 
(292
)
 

 
(244
)
Ending balance
461,136

 
3,147

 
461,136

 
138

Accumulated other comprehensive income (loss)
 
 
 
 
 
 
 
Beginning balance
 
 
(3,009
)
 
 
 
1,834

Cumulative translation adjustment
 
 
1,415

 
 
 
(1,790
)
Ending balance
 
 
(1,594
)
 
 
 
44

Total partners’ capital at March 31,
 
 
$
61,537

 
 
 
$
79,853



The accompanying notes are an integral part of these consolidated financial statements.
5




USD PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
1. ORGANIZATION AND BASIS OF PRESENTATION
USD Partners LP and its consolidated subsidiaries, collectively referred to herein as we, us, our, the Partnership and USDP, is a fee-based, growth-oriented master limited partnership formed in 2014 by US Development Group, LLC, or USD, through its wholly-owned subsidiary, USD Group LLC, or USDG. We were formed to acquire, develop and operate midstream infrastructure and complementary logistics solutions for crude oil, biofuels and other energy-related products. We generate substantially all of our operating cash flows from multi-year, take-or-pay contracts with primarily investment grade customers, including major integrated oil companies, refiners and marketers. Our network of crude oil terminals facilitate the transportation of heavy crude oil from Western Canada to key demand centers across North America. Our operations include railcar loading and unloading, storage and blending in onsite tanks, inbound and outbound pipeline connectivity, truck transloading, as well as other related logistics services. We also provide our customers with leased railcars and fleet services to facilitate the transportation of liquid hydrocarbons and biofuels by rail. We do not generally take ownership of the products that we handle, nor do we receive any payments from our customers based on the value of such products. We may on occasion enter into buy-sell arrangements in which we take temporary title to commodities while in our terminals. We expect such arrangements to be at fixed prices where we do not take commodity price exposure. Our common units are traded on the New York Stock Exchange, or NYSE, under the symbol USDP.
Basis of Presentation
Our accompanying unaudited interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States, or GAAP, for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all the information and disclosures required by GAAP for complete consolidated financial statements. In the opinion of our management, they contain all adjustments, consisting only of normal recurring adjustments, which our management considers necessary to present fairly our financial position as of March 31, 2019, our results of operations for three months ended March 31, 2019 and 2018, and our cash flows for the three months ended March 31, 2019 and 2018. We derived our consolidated balance sheet as of December 31, 2018 from the audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018. Our results of operations for three months ended March 31, 2019 and 2018 should not be taken as indicative of the results to be expected for the full year due to fluctuations in the supply of and demand for crude oil and biofuels, timing and completion of acquisitions, if any, and the impact of fluctuations in foreign currency exchange rates. These unaudited interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and accompanying notes thereto presented in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018.
Foreign Currency Translation
We conduct a substantial portion of our operations in Canada, which we account for in the local currency, the Canadian dollar. We translate most Canadian dollar denominated balance sheet accounts into our reporting currency, the U.S. dollar, at the end of period exchange rate, while most income statement accounts are translated into our reporting currency based on the average exchange rate for each monthly period. Fluctuations in the exchange rate between the Canadian dollar and the U.S. dollar can create variability in the amounts we translate and report in U.S. dollars.
Within these consolidated financial statements, we denote amounts denominated in Canadian dollars with “C$” immediately prior to the stated amount.
US Development Group, LLC
USD and its affiliates are engaged in designing, developing, owning and managing large-scale multi-modal logistics centers and energy-related infrastructure across North America. USD is the indirect owner of our general partner through its direct ownership of USDG and is currently owned by Energy Capital Partners, Goldman Sachs and certain of USD’s management team members.


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

2. RECENT ACCOUNTING PROUNOUNCEMENTS
Recently Adopted Accounting Pronouncements
Accounting for Nonemployee Unit based Compensation (ASU 2018-07)
In June 2018, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update No. 2018-07, or ASU 2018-07, which amends the Accounting Standards Codification, or ASC, Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees. The provisions of this standard specify that Topic 718 applies to all share-based payment transactions in which a grantor acquires goods or services to be used or consumed in a grantor’s own operations by issuing share-based payment awards. We adopted the provisions of ASU 2018-07 prospectively on January 1, 2019, which affected the method we used to value the phantom units we granted to our directors and consultants domiciled in the United States. In periods prior to our adoption of ASU 2018-07, we were required to revalue the outstanding phantom units granted to these individuals each reporting period. Pursuant to the requirements of ASU 2018-07 and under the provisions of ASC Topic 718, these phantom units are now valued at the grant date fair value, consistent with the method we use to value phantom units granted to employees that are domiciled in the United States.
Leases (ASC 842)
In February 2016, the FASB issued Accounting Standards Update No. 2016-02, or ASU 2016-02, which created ASC Topic 842 Leases, to require balance sheet recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. The standard also expanded the disclosure requirements for lessors with respect to their leasing activities. In July 2018, the FASB issued ASU 2018-11, to provide another transition method in addition to the existing transition method, allowing entities to initially apply the new standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Additionally, the FASB has issued other Accounting Standards Updates to clarify application of the guidance in the original standard and to provide practical expedients for applying the standard, all of which are effective upon adoption. The pronouncement is effective for years beginning after December 15, 2018, and early adoption is permitted.
We adopted the provisions of ASC 842 on January 1, 2019. This standard requires us to recognize right-of-use assets and lease liabilities on our consolidated balance sheet for identified property that is subject to operating lease agreements for which we are considered a lessee. We elected to adopt this standard by applying the additional transition method set forth in ASU 2018-11, whereby we implement the provisions of the new standard to our existing leases by recognizing and measuring lease assets and liabilities on our balance sheet as of January 1, 2019, as well as a cumulative-effect adjustment to the opening balances of Partners’ Capital. Consequently, our reporting of leases for the prior year continues to be provided in accordance with ASC Topic 840, which was effective during that period. We elected the package of practical expedients permitted under the transition guidance within ASC 842, which, among other things, allowed us to carry forward our historical lease classification without the need to re-evaluate such classification pursuant to the provisions of ASC 842. 
We determine the classification of our leases as operating, financing or sales-type leases based on the criteria set forth in ASC 842 that considers whether a lease is economically similar to the purchase of a nonfinancial asset. We have adopted as our accounting policy the definition of “substantially all” of the fair value of the underlying asset to mean 90% or greater and a “major part” of the remaining economic life to mean 75% or greater in performing our classification assessment. We exclude variable lease payments that are based on performance or use from our lease classification determination. We include the exercise price of a purchase option when reasonable certainty exists that we will exercise the option. We also include termination penalties unless it is reasonably certain that we will not exercise


7



any option to terminate the lease, and therefore will not incur the penalty. Lastly, we also include any residual value guarantees that we provided to lessors in our classification determination.
Our adoption of ASC 842 required us to recognize lease assets and lease liabilities for all leases where we are the lessee and present them on our balance sheet, which did not affect our consolidated statements of income, consolidated statement of cash flows or consolidated statements of partners' capital. Upon adoption we recognized a right-to-use lease asset and corresponding liability of $17.3 million on our consolidated balance sheet. Additionally, our adoption of ASC 842 did not affect our accounting for leases where we are the lessor.
Lessee Accounting
We effectively lease assets from third parties for use in our operations, which primarily include railcars, buildings, storage tanks, equipment, offices, railroad track and land. The general terms of our lease agreements require monthly payments in advance, in arrears or upon receipt, some of which include variable payments attributable to index-based rate escalations and freight associated with railcar returns. A majority of our leases do not include renewal options, or rights to early termination of the lease agreements. Additionally, our leases do not include residual value guarantees, nor do they impose any significant covenants or restrictions on us. As discussed below under Lessor Accounting, we effectively sublease all of our leased railcars to customers under terms similar to the terms of our lease agreements with the railcar manufacturing and finance companies from whom we lease the railcars. We also lease a storage tank from a third party provider of crude oil storage that we sublease to a customer of our Stroud terminal.
We have elected as an accounting policy not to apply the recognition requirements of ASC 842 to short-term leases for all classes of assets underlying our leases. As a result, we recognize the lease payments we make as expense in our consolidated statements of income over the lease term, regardless of the underlying class of asset being leased. We define a short-term lease as a lease that at the commencement date has a term of 12 months or less and does not include an option to purchase the underlying asset that we are reasonably certain to exercise.
We deem a contract to be a lease when the terms of the agreement indicate we have the right to control the use of an identified asset for a period of time in exchange for consideration. We establish our right to control the use of an identified asset when the contract terms set forth our right to obtain substantially all of the economic benefits from use of the identified asset, or to direct its use throughout the contract period. We consider substantially all of the economic benefits to mean 90% or more of the utility of the identified asset.
We have elected to apply the portfolio approach to account for our railcar leases due to our expectation that this method would not significantly differ from an individual lease approach. Additionally, we have elected to use the practical expedient that allows us not to separate amounts of contract consideration between lease and non-lease components. Non-lease components of our agreements include maintenance of property, common area costs such as cleaning and landscape services and reimbursement of the suppliers’ insurance, taxes or administrative costs.
We determine the discount rate for our leases by estimating a borrowing rate we would pay on a collateralized basis over the term of the underlying lease, based on our creditworthiness and the interest rate environment at the time we enter into the lease. We establish our credit quality by performing a synthetic credit analysis based on operational, liquidity and solvency metrics, which are weighted to produce an estimated rating. We then develop an interest rate curve for various periods of time by applying an adjustment factor to the risk free rates as established from yields on U.S. Treasury securities. We utilize this interest rate curve to establish an approximate discount rate based upon the term of the underlying lease.
We determine our right-of-use assets based on the initial measurement amount of the lease liability, as discussed below, increased by any prepayments that we make to the lessor at or before the lease commencement date and any initial direct costs we may incur, reduced by any incentive amounts we may receive.
We measure our lease liabilities based upon the discounted present value of the payment amounts we expect to make over the noncancellable terms of the underlying leases. We exclude variable lease payments that are based on performance or use in our measurement of the right of use assets and liabilities. We include in our measurement of the right of use assets and lease liabilities the exercise price of purchase options when reasonable certainty exists that we will exercise the option and any termination penalties when reasonable certainty exists that we will exercise an option


8



to terminate the lease. We also include any residual value guarantees provided to lessors to the extent that we consider the likelihood we will have to pay the lessor at the end of the lease term for a deficiency to be probable.
Over the lease term, we amortize the right-of-use asset and record interest expense on the lease liability recorded at commencement of the lease. Our income statement recognition of the expense is dependent on whether the lease is classified as an operating, direct financing, or sales-type lease. We recognize amortization expense and interest expense associated with operating leases as a single item of expense in our consolidated statements of income. We recognize amortization expense and interest expense associated with any direct financing and sales-type leases as separate items of expense within our consolidated statements of income.
We present all leases, where we are the lessee, on our balance sheet subject to the practical expedients we have elected and capitalization limitations we have established.
Lessor Accounting
We effectively lease railcars and storage tanks to customers of our terminalling facilities to meet their logistical needs for the movement of crude oil to refineries and market centers. The general terms of our lease agreements require monthly payments, some of which include variable payments attributable to index-based rate escalations and freight associated with railcar returns. Under the master service agreements for the railcars we lease, we also charge a fee for the various freight monitoring, scheduling, maintenance and related services we provide to customers that lease railcars from us, representing a non-lease component that we account for separately. Our storage tank leases contain standard renewal options for periods up to 12 months following the end of the initial lease term. Additionally, our storage tank leases include charges for blending and mixing services as well as pump over charges, representing non lease components that we account for separately. Our railcar master fleet services agreements and storage tank leases do not generally include rights to early termination of the agreements, nor do they include residual value guarantees. None of the customers on our railcar master fleet services agreements and storage tank leases have options to purchase the underlying assets. As discussed above under Lessee Accounting, we effectively sublease all of our leased railcars to customers under terms similar to the terms of our lease agreements with the railcar manufacturing and finance companies from whom we lease the railcars. We also lease a storage tank from a third party provider of crude oil storage that we sublease to a customer of our Stroud terminal.
We deem a contract to be a lease when the terms of the agreement indicate we have transferred to another party the right to control the use of an identified asset for a period of time in exchange for consideration. We determine that we have transferred the right to control the use an identified asset when the contract terms set forth the rights of another party to obtain substantially all of the economic benefits from use of the identified asset, or to direct its use throughout the contract period. We consider substantially all of the economic benefits to mean 90% or more of the utility of the identified asset during the contract term.
We allocate consideration in a contract between lease and non-lease components based upon the rates and terms that are specified in our agreements. We recognize revenue from fees we charge for freight services related to railcars and from fees we charge for blending, mixing and pump over charges related to our storage services pursuant to the requirements of ASC 606 as set forth in our Revenue Policy.
We continue to depreciate property that we own and lease to third party customers in accordance with our standard depreciation policies. We record lease income typically on a straight-line basis over the lease term.
Refer to Note 7. Leases for further discussion.
Recent Accounting Pronouncements Not Yet Adopted
Intangibles - Goodwill and Other
In January 2017, the FASB issued Accounting Standards Update No. 2017-04, or ASU 2017-04, which amends ASC Topic 350 to modify the concept of impairment from the condition that exists when the carrying amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of a reporting unit exceeds its fair value. Pursuant to the provisions of ASU 2017-04, an entity will no longer determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if


9



that reporting unit had been acquired in a business combination. Rather, an entity will recognize an impairment loss for the amount by which the carrying amount of a reporting unit exceeds the reporting unit’s fair value. However, the loss recognized cannot exceed the total amount of goodwill allocated to that reporting unit.
The pronouncement is effective for fiscal years beginning after December 15, 2019, or for any interim impairment testing within those fiscal years and is required to be applied prospectively, with early adoption permitted. We do not expect to early adopt the provisions of this standard. Any impairment assessment we perform subsequent to our adoption of the standard could produce an impairment of goodwill in a different amount than would result under current guidance to the extent the carrying amount of a reporting unit exceeds its fair value.

3. NET INCOME PER LIMITED PARTNER INTEREST
We allocate our net income among our general partner and limited partners using the two-class method in accordance with applicable authoritative accounting guidance. Under the two-class method, we allocate our net income and any net income in excess of distributions to our limited partners, our general partner and the holder of the incentive distribution rights, or IDRs, according to the distribution formula for available cash as set forth in our partnership agreement. We allocate any distributions in excess of earnings for the period to our limited partners and general partner based on their respective proportionate ownership interests in us, as set forth in our partnership agreement after taking into account distributions to be paid with respect to the IDRs. The formula for distributing available cash as set forth in our partnership agreement is as follows:
Distribution Targets
 
Portion of Quarterly
Distribution Per Unit
 
Percentage Distributed to Limited Partners
 
Percentage Distributed to
General Partner
(including IDRs) (1)
Minimum Quarterly Distribution
 
Up to $0.2875
 
98%
 
2%
First Target Distribution
 
> $0.2875 to $0.330625
 
98%
 
2%
Second Target Distribution
 
> $0.330625 to $0.359375
 
85%
 
15%
Third Target Distribution
 
> $0.359375 to $0.431250
 
75%
 
25%
Thereafter
 
Amounts above $0.431250
 
50%
 
50%
    
(1)    Assumes our general partner maintains a 2% general partner interest in us.


10



We determined basic and diluted net income per limited partner unit as set forth in the following tables:
 
 
For the Three Months Ended March 31, 2019
 
 
Common
Units
 
Subordinated
Units
 
Class A
Units
 (7) 
 
General
Partner
Units
 
Total
 
 
(in thousands, except per unit amounts)
Net income attributable to general and limited partner interests in USD Partners LP (1) 
 
$
1,054

 
$
101

 
$

 
$
164

 
$
1,319

Less: Distributable earnings (2)
 
9,273

 
795

 

 
317

 
10,385

Distributions in excess of earnings
 
$
(8,219
)
 
$
(694
)
 
$

 
$
(153
)
 
$
(9,066
)
Weighted average units outstanding (3)
 
23,060

 
3,255

 
22

 
461

 
26,798

Distributable earnings per unit (4)
 
$
0.40

 
$
0.24

 
$

 
 
 
 
Overdistributed earnings per unit (5)
 
(0.36
)
 
(0.21
)
 

 
 
 
 
Net income per limited partner unit (basic and diluted)(6)
 
$
0.04

 
$
0.03

 
$

 
 
 
 
    
(1) 
Represents net income allocated to each class of units based on the actual ownership of the Partnership during the period. The net income for each class of limited partner interest has been reduced by its proportionate amount of the approximate $141 thousand attributed to the general partner for its incentive distribution rights.
(2) 
Represents the distributions payable for the period based upon the quarterly distribution amount of $0.3625 per unit, or $1.45 per unit on an annualized basis. Amounts presented for each class of units include a proportionate amount of the $469 thousand distributable to holders of the Equity classified Phantom Units pursuant to the distribution equivalent rights granted under the USD Partners LP 2014 Amended and Restated Long-Term Incentive Plan.
(3) 
Represents the weighted average units outstanding for the period.
(4) 
Represents the total distributable earnings divided by the weighted average number of units outstanding for the period.
(5) 
Represents the distributions in excess of earnings divided by the weighted average number of units outstanding for the period.
(6) 
Our computation of net income per limited partner unit excludes the effects of 1,292,474 equity-classified phantom unit awards outstanding as they were anti-dilutive for the period presented.
(7) 
In February 2019, pursuant to the terms set forth in our partnership agreement, the fourth and final vesting tranche of 38,750 Class A units vested and were converted into Common units. Refer to Note 17. Partners Capital for more information.

 
 
For the Three Months Ended March 31, 2018
 
 
Common
Units
 
Subordinated
Units
 
Class A
Units
 
General
Partner
Units
 
Total
 
 
(in thousands, except per unit amounts)
Net income attributable to general and limited partner interests in USD Partners LP (1) 
 
$
5,095

 
$
1,290

 
$
14

 
$
201

 
$
6,600

Less: Distributable earnings (2)
 
8,089

 
1,544

 
14

 
257

 
9,904

Distributions in excess of earnings
 
$
(2,994
)
 
$
(254
)
 
$

 
$
(56
)
 
$
(3,304
)
Weighted average units outstanding (3)
 
20,597

 
5,348

 
61


461

 
26,467

Distributable earnings per unit (4)
 
$
0.39

 
$
0.29

 
$
0.23

 
 
 
 
Overdistributed earnings per unit (5)
 
(0.15
)
 
(0.05
)
 

 
 
 
 
Net income per limited partner unit (basic and diluted)(6)
 
$
0.24

 
$
0.24

 
$
0.23

 
 
 
 
    
(1) 
Represents net income allocated to each class of units based on the actual ownership of the Partnership during the period. The net income for each class of limited partner interest has been reduced by its proportionate amount of the approximate $87 thousand attributed to the general partner for its incentive distribution rights.
(2) 
Represents the distributions paid for the period based upon the quarterly distribution amount of $0.3525 per unit, or $1.41 per unit on an annualized basis. Amounts presented for each class of units include a proportionate amount of the $441 thousand distributed to holders of the Equity-classified Phantom Units pursuant to the distribution equivalent rights granted under the USD Partners Amended and Restated LP 2014 Long-Term Incentive Plan.
(3) 
Represents the weighted average units outstanding for the period.
(4) 
Represents the total distributable earnings divided by the weighted average number of units outstanding for the period.
(5) 
Represents the distributions in excess of earnings divided by the weighted average number of units outstanding for the period.


11



(6) 
Our computation of net income per limited partner unit excludes the effects of 1,263,161 equity-classified phantom unit awards outstanding as they were anti-dilutive for the period presented.
 
4. REVENUES
Disaggregated Revenues
We manage our business in two reportable segments: Terminalling services and Fleet services. Our segments offer different services and are managed accordingly. Our chief operating decision maker, or CODM, regularly reviews financial information about both segments in order to allocate resources and evaluate performance. As such, we have concluded that disaggregating revenue by reporting segments appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. Refer to Note 14. Segment Reporting for our disaggregated revenues by segment. Additionally, the below tables summarize the geographic data for our revenues:
 
Three Months Ended March 31, 2019
 
U.S.
 
Canada
 
Total
 
(in thousands)
Third party
$
8,720

 
$
11,738

 
$
20,458

Related party
$
2,374

 
$
4,536

 
$
6,910

 
Three Months Ended March 31, 2018
 
U.S.
 
Canada
 
Total
 
(in thousands)
Third party
$
11,697

 
$
12,127

 
$
23,824

Related party
$
1,211

 
$
4,698

 
$
5,909

Remaining Performance Obligations
The transaction price allocated to the remaining performance obligations associated with our terminalling and fleet services agreements as of March 31, 2019 are as follows for the periods indicated:
 
For the nine months ending December 31, 2019
 
2020
 
2021
 
Thereafter
 
Total
 
(in thousands)
Terminalling Services (1) (2)
$
67,671

 
$
65,720

 
$
51,047

 
$
60,242

 
$
244,680

Fleet Services
772

 
1,030

 
1,016

 
1,308

 
4,126

Total
$
68,443

 
$
66,750

 
$
52,063

 
$
61,550

 
$
248,806

    
(1) The majority of our terminalling services agreements are denominated in Canadian dollars. We have converted the remaining performance obligations provided herein using the year-to-date average exchange rate of 0.7522 U.S. dollars per one Canadian dollar at March 31, 2019.
(2) Includes fixed monthly minimum commitment fees per contracts and excludes constrained variable consideration for rate-escalations associated with an index, such as the consumer price index, as well as any incremental revenue associated with volume activity above the minimum volumes set forth within the contracts.
We have applied the practical expedient that allows us to exclude disclosure of performance obligations that are part of a contract that has an expected duration of one year or less. In addition, we have also applied the practical expedient that allows us not to disclose the amount of transaction price allocated to the remaining performance obligations for all reporting periods presented prior to our adoption of ASC 606.
Contract Assets
Our contract assets represent cumulative revenue that has been recognized in advance of billing the customer due to tiered billing provisions. In such arrangements, revenue is recognized using a blended rate based on the billing tiers of the agreement, as the services are consistently provided throughout the duration of the contractual arrangement.


12



We have included contract assets of $205 thousand and $68 thousand as of March 31, 2019 and December 31, 2018, respectively, in “Other current assets” and $86 thousand and $171 thousand as of March 31, 2019 and December 31, 2018, respectively, in “Other non-current assets” on our consolidated balance sheets.
Contract Liabilities
Our contract liabilities consist of amounts collected in advance from customers associated with their terminalling and fleet services agreements, which will be recognized as revenue when earned pursuant to the terms of our contractual arrangements. We have included contract liabilities with third-party customers of $3.0 million and $2.9 million as of March 31, 2019 and December 31, 2018, respectively, in “Deferred revenue.” We have included contract liabilities with related party customers of $1.5 million as of March 31, 2019 and December 31, 2018, in “Deferred revenue related party” on our consolidated balance sheets.
The following table presents the changes associated with the balance of our contract liabilities for the three months ended March 31, 2019:
 
 
December 31, 2018
 
Cash Additions for Customer Prepayments
 
Revenue Recognized
 
March 31, 2019
 
 
(in thousands)
Customer prepayments
 
$
2,921

 
$
2,980

 
$
(2,921
)
 
$
2,980

Customer prepayments — related party (1)
 
$
1,475

 
$
1,506

 
$
(1,475
)
 
$
1,506

    
(1) 
Includes contract liabilities associated with customer prepayments from related parties. Refer to Note 12. Transactions with Related Parties for additional discussion of deferred revenues associated with related parties.
Deferred Revenue Fleet Leases
Our deferred revenue also includes advance payments from customers of our Fleet services business, which will be recognized as Fleet leases revenue when earned pursuant to the terms of our contractual arrangements. We have likewise prepaid the rent on railcar leases that are associated with the deferred revenues of our fleet services business, which we will recognize as expense concurrently with our recognition of the associated revenue. We have included $0.4 million at March 31, 2019 and December 31, 2018, in “Deferred revenue related party” on our consolidated balance sheets associated with customer prepayments for our fleet lease agreements.
 
5. RESTRICTED CASH
We include in restricted cash on our consolidated balance sheets 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:
 
March 31,
 
2019
 
2018
 
(in thousands)
Cash and cash equivalents
$
3,069

 
$
6,359

Restricted Cash
5,655

 
4,978

Total cash, cash equivalents and restricted cash
$
8,724

 
$
11,337

 


13



6. PROPERTY AND EQUIPMENT
Our property and equipment is comprised of the following as of the dates indicated:
 
March 31, 2019
 
December 31, 2018
Estimated
Depreciable Lives
(Years)
 
(in thousands)
Land
$
10,063

 
$
10,004

N/A
Trackage and facilities
124,372

 
123,080

10-30
Pipeline
16,336

 
16,336

20-25
Equipment
16,580

 
16,455

3-20
Furniture
64

 
64

5-10
Total property and equipment
167,415

 
165,939

 
Accumulated depreciation
(31,949
)
 
(29,479
)
 
Construction in progress (1)
11,169

 
8,848

 
Property and equipment, net
$
146,635

 
$
145,308

 
        
(1) 
The amounts classified as “Construction in progress” are excluded from amounts being depreciated. These amounts represent property that is not yet ready to be placed into productive service as of the respective consolidated balance sheet date. We had $138 thousand of capitalized interest costs for the three months ended March 31, 2019.
Depreciation expense associated with Property and equipment totaled $1.6 million and $2.1 million for the three months ended March 31, 2019 and 2018, respectively.
Our depreciation expense for the three months ended March 31, 2019 reflects a reduction of $560 thousand to our asset retirement obligations, or ARO, due to refinement of our estimates. The ARO is associated with restoration of the property at our San Antonio facility. The ending balance of our ARO at March 31, 2019 is $200 thousand.
 
7. LEASES
We have noncancellable operating leases for railcars, buildings, storage tanks, offices, railroad tracks, and land.
 
 
Three Months Ended March 31, 2019
Weighted-average discount rate
 
6.3
%
Weighted average remaining lease term
 
3.3 years

Our total lease cost consisted of the following items for the dates indicated:
 
 
Three Months Ended March 31, 2019
 
(in thousands)
Operating lease cost
 
1,484

Short term lease cost
 
47

Sublease income
 
(1,333
)
Total
 
$
198



14



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 March 31, 2019, (in thousands): 
2019
$
4,558

2020
5,269

2021
4,074

2022
3,787

2023
20

Total lease payments
$
17,708

Less: imputed interest
(1,790
)
Present value of lease liabilities
$
15,918

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 March 31, 2019
 
(in thousands, except weighted average term)
Lease income
$
2,295

Weighted average remaining lease term
3.3 years

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 March 31, 2019 (in thousands): 
2019
$
6,307

2020
6,900

2021
5,753

2022
4,459

Total
$
23,419

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

8. INTANGIBLE ASSETS
The composition, gross carrying amount and accumulated amortization of our identifiable intangible assets are as follows as of the dates indicated:
 
March 31, 2019
 
December 31, 2018
 
(in thousands)
Carrying amount:
 
 
 
Customer service agreements
$
125,960

 
$
125,960

Other
106

 
106

Total carrying amount
126,066

 
126,066

Accumulated amortization:
 
 
 
Customer service agreements
(42,476
)
 
(39,328
)
Other
(36
)
 
(33
)
Total accumulated amortization
(42,512
)
 
(39,361
)
Total intangible assets, net
$
83,554

 
$
86,705

Amortization expense associated with intangible assets totaled $3.2 million for each of the three months ended March 31, 2019 and 2018.


15



 
9. DEBT
In November 2018, we amended and restated our senior secured credit agreement, which we originally established at the time of our initial public offering in October 2014. We refer to the amended and restated senior secured credit agreement executed in November 2018 as the Credit Agreement and the original senior secured credit agreement as the Previous Credit Agreement. Our Credit Agreement is a $385 million revolving credit facility (subject to limits set forth therein) with Citibank, N.A., as administrative agent, and a syndicate of lenders. Our Credit Agreement amends and restates in its entirety our Previous Credit Agreement.
Our Credit Agreement is a four year committed facility that initially matures on November 2, 2022. Our Credit Agreement provides us with the ability to request two one-year maturity date extensions, subject to the satisfaction of certain conditions, and allows us the option to increase the maximum amount of credit available up to a total facility size of $500 million, subject to receiving increased commitments from lenders and satisfaction of certain conditions.
Our Previous Credit Agreement included a $300 million Revolving Credit Facility and a $100 million term loan (borrowed in Canadian dollars), the Term Loan Facility, which we repaid in March 2017. As we repaid amounts outstanding on the Term Loan Facility, the availability on our Revolving Credit Facility was automatically increased to the full $400 million of credit available under the Previous Credit Agreement.
Our Credit Agreement and any issuances of letters of credit are available for working capital, capital expenditures, general partnership purposes and continue the indebtedness outstanding under the Previous Credit Agreement. The Credit Agreement includes an aggregate $20 million sublimit for standby letters of credit and a $20 million sublimit for swingline loans. Obligations under the Credit Agreement are guaranteed by our restricted subsidiaries (as such term is defined therein) and are secured by a first priority lien on our assets and those of our restricted subsidiaries, other than certain excluded assets.
Our long-term debt balances included the following components as of the specified dates:
 
March 31, 2019
 
December 31, 2018
 
(in thousands)
Revolving Credit Facility
207,000

 
209,000

Less: Deferred financing costs, net
(2,972
)
 
(3,419
)
Total long-term debt, net
$
204,028

 
$
205,581

We determined the capacity available to us under the terms of our Credit Agreement was as follows as of the specified dates:
 
March 31, 2019
 
December 31, 2018
 
(in millions)
Aggregate borrowing capacity under Credit Agreement
$
385.0

 
$
385.0

Less: Revolving Credit Facility amounts outstanding
207.0

 
209.0

Letters of credit outstanding
0.6

 
0.6

Available under Credit Agreement (1)
$
177.4

 
$
175.4

    
(1) 
Pursuant to the terms of our Credit Agreement, our borrowing capacity, currently, is limited to 4.5 times our trailing 12-month consolidated EBITDA.
The average interest rate on our outstanding indebtedness was 5.00% and 4.86% at March 31, 2019 and December 31, 2018, respectively, without consideration to the effect of our derivative contracts. In addition to the interest we incur on our outstanding indebtedness, we pay commitment fees of 0.50% on unused commitments, which rate will vary based on our consolidated net leverage ratio, as defined in our Credit Agreement. At March 31, 2019, we were in compliance with the covenants set forth in our Credit Agreement.


16



Interest expense associated with our outstanding indebtedness was as follows for the specified periods:
 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands)
Interest expense on the Credit Agreement
$
2,875

 
$
2,270

Capitalized interest on construction in progress
(138
)
 

Amortization of deferred financing costs
450

 
215

Total interest expense
$
3,187

 
$
2,485

 
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 $5.1 million and $5.7 million for the three months ended March 31, 2019 and 2018, respectively which are presented as “Pipeline fees” in our consolidated statements of income.
 
11. NONCONSOLIDATED VARIABLE INTEREST ENTITIES
We have entered into purchase, assignment and assumption agreements to assign payment and performance obligations for certain operating lease agreements with lessors, as well as customer fleet service payments related to these operating leases, with unconsolidated entities in which we have variable interests. These variable interest entities, or VIEs, include LRT Logistics Funding LLC, USD Fleet Funding LLC, USD Fleet Funding Canada Inc., and USD Logistics Funding Canada Inc. We treat these entities as variable interests under the applicable accounting guidance due to their having an insufficient amount of equity invested at risk to finance their activities without additional subordinated financial support. We are not the primary beneficiary of the VIEs, as we do not have the power to direct the activities that most significantly affect the economic performance of the VIEs, nor do we have the power to remove the managing member under the terms of the VIEs’ limited liability company agreements. Accordingly, we do not consolidate the results of the VIEs in our consolidated financial statements.
The following table summarizes the total assets and liabilities between us and the VIEs as reflected in our consolidated balance sheets at March 31, 2019 and December 31, 2018, as well as our maximum exposure to losses from entities in which we have a variable interest, but are not the primary beneficiary. Generally, our maximum exposure to losses is limited to amounts receivable for services we provided, reduced by any deferred revenue.
 
March 31, 2019
 
Total assets
 
Total liabilities
 
Maximum exposure to loss
 
(in thousands)
Accounts receivable
$
11

 
$

 
$
1

Deferred revenue

 
10

 

 
$
11

 
$
10

 
$
1



17



 
December 31, 2018
 
Total assets
 
Total liabilities
 
Maximum exposure to loss
 
(in thousands)
Accounts receivable
$
17

 
$

 
$
7

Deferred revenue

 
10

 

 
$
17

 
$
10

 
$
7

We have assigned certain payment and performance obligations under the leases and master fleet service agreements for 1,483 railcars to the VIEs, but we have retained certain rights and obligations with respect to the servicing of these railcars.
During the quarter ended March 31, 2019, we provided no explicit or implicit financial or other support to these VIEs that were not previously contractually required.
 
12. TRANSACTIONS WITH RELATED PARTIES
Nature of Relationship with Related Parties
USD is engaged in designing, developing, owning and managing large-scale multi-modal logistics centers and other energy-related infrastructure across North America. USD is also the sole owner of USDG and the ultimate parent of our general partner. USD is owned by Energy Capital Partners, Goldman Sachs and certain members of its management.
USDG is the sole owner of our general partner and at March 31, 2019, owns 9,464,381 of our common units and all 2,092,709 of our subordinated units representing a combined 42.9% limited partner interest in us. As of March 31, 2019, a value of up to $10.0 million of these common units were pledged as collateral under USDG’s letter of credit facility. USDG also provides us with general and administrative support services necessary for the operation and management of our business.
USD Partners GP LLC, our general partner, currently owns all 461,136 of our general partner units representing a 1.7% general partner interest in us, as well as all of our incentive distribution rights. Pursuant to our partnership agreement, our general partner is responsible for our overall governance and operations.
USD Marketing LLC, or USDM, is a wholly-owned subsidiary of USDG organized to promote contracting for services provided by our terminals and to facilitate the marketing of customer products.
Omnibus Agreement
We are party to an omnibus agreement with USD, USDG and certain of their subsidiaries, including our general partner, pursuant to which we obtain and make payments for specified services provided to us and for out-of-pocket costs incurred on our behalf. We pay USDG, in equal monthly installments, the annual amount USDG estimates will be payable by us during the calendar year for providing services for our benefit. The omnibus agreement provides that this amount may be adjusted annually to reflect, among other things, changes in the scope of the general and administrative services provided to us due to a contribution, acquisition or disposition of assets by us or our subsidiaries, or for changes in any law, rule or regulation applicable to us, which affects the cost of providing the general and administrative services. We also reimburse USDG for any out-of-pocket costs and expenses incurred on our behalf in providing general and administrative services to us. This reimbursement is in addition to the amounts we pay to reimburse our general partner and its affiliates for certain costs and expenses incurred on our behalf for managing our business and operations, as required by our partnership agreement.
The total amounts charged to us under the omnibus agreement for the three months ended March 31, 2019 and 2018 were $2.5 million and $1.8 million, respectively, which amounts are included in “Selling, general and administrative — related party” in our consolidated statements of income. At March 31, 2019 and December 31, 2018, we had balances payable related to these costs of $1.1 million and $0.4 million respectively, recorded as “Accounts payable and accrued expenses related party” in our consolidated balance sheets.


18



Marketing Services Agreement
In connection with our purchase of the Stroud terminal, we entered into a Marketing Services Agreement with USDM effective as of May 31, 2017, whereby we granted USDM the right to market the capacity at the Stroud terminal in excess of the original capacity of our initial customer in exchange for a nominal per barrel fee. USDM is obligated to fund any related capital costs associated with increasing the throughput or efficiency of the terminal to handle additional throughput. Upon expiration of our contract with the initial Stroud customer in June 2020, the same marketing rights will apply to all throughput at the Stroud terminal in excess of the throughput necessary for the Stroud terminal to generate Adjusted EBITDA that is at least equal to the average monthly Adjusted EBITDA derived from the initial Stroud customer during the 12 months prior to expiration. We also granted USDG the right to develop other projects at the Stroud terminal in exchange for the payment to us of market-based compensation for the use of our property for such development projects. Any such development projects would be wholly-owned by USDG and would be subject to our existing right of first offer with respect to midstream projects developed by USDG. Payments made under the Marketing Services Agreement during the periods presented in this report are discussed below under the heading “Related Party Revenue and Deferred Revenue.”  
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.
In connection with our acquisition of the Stroud terminal, USDM assumed the rights and obligations for additional terminalling capacity at our Hardisty terminal from another customer, effective as of June 1, 2017, to facilitate the origination of crude oil barrels by the Stroud customer from our Hardisty terminal for delivery to the Stroud terminal. As a result of the assumption of these rights and obligations by USDM, and in order to accommodate the needs of the Stroud customer, the contracted term for the capacity held by USDM was extended to June 30, 2020. USDM controls approximately 25% of the available monthly capacity of the Hardisty terminal at March 31, 2019. The terms and conditions of these agreements are similar to the terms and conditions of agreements we have with other parties at the Hardisty terminal that are not related to us.
We also entered into a Marketing Services Agreement with USDM effective as of May 31, 2017, as discussed above, in connection with our acquisition of the Stroud terminal. Pursuant to the terms of the agreement, we receive a fixed amount per barrel from USDM in exchange for marketing the additional capacity available at the Stroud terminal. We also received revenue for providing additional terminalling services at our Hardisty terminal to USDM pursuant to the terms of its existing agreements with us. Additionally, effective January 2019, we entered into a six month terminalling services agreement with USDM at our Casper terminal to maximize utilization of available terminalling and storage capacity by offering these services to customers on an uncommitted basis at current market rates. This agreement will automatically renew for successive periods of six months on an evergreen basis unless otherwise canceled by either party. We include amounts received pursuant to these arrangements as revenue in the table below under “Terminalling services — related party.” Additionally, we received revenue from USDM for the lease of 200 railcars pursuant to the terms of an existing agreement with us, which is included in the table below under “Fleet leases — related party.”
Our related party revenues from USD and affiliates are presented in the following table for the indicated periods:
 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands)
Terminalling services — related party
$
5,638

 
$
4,696

Fleet leases — related party
984

 
984

Fleet services — related party
227

 
227

Freight and other reimbursables — related party
61

 
2

 
$
6,910

 
$
5,909



19



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:
 
March 31, 2019
 
December 31, 2018
 
(in thousands)
Accounts receivable — related party 
$
1,255

 
$
624

Accounts payable — related party
$
85

 
$
67

Other current and non-current assets — related party (1)
$
154

 
$
174

Deferred revenue— related party (2)
$
1,916

 
$
1,885

        
(1) 
Represents a contract asset associated with our lease agreement with USDM.
(2) 
Represents deferred revenues associated with our terminalling and fleet services agreements with USD and affiliates for amounts we have collected from them for their prepaid leases and prepaid minimum volume commitment fees.
Cash Distributions
During the three months ended March 31, 2019, we paid the following aggregate cash distributions to USDG as a holder of our common units and the sole owner of our subordinated units and to USD Partners GP LLC for their general partner interest and as the holder of our IDRs.
Distribution Declaration Date
 
Record Date
 
Distribution
Payment Date
 
Amount Paid to
 USDG
 
Amount Paid to
USD Partners GP LLC
 
 
 
 
 
 
(in thousands)
January 31, 2019
 
February 11, 2019
 
February 19, 2019
 
$
4,161

 
$
285

 
13. COMMITMENTS AND CONTINGENCIES
From time to time, we may be involved in legal, tax, regulatory and other proceedings in the ordinary course of business. We do not believe that we are currently a party to any such proceedings that will have a material adverse impact on our financial condition or results of operations.
 
14. SEGMENT REPORTING
We manage our business in two reportable segments: Terminalling services and Fleet services. The Terminalling services segment charges minimum monthly commitment fees under multi-year take-or-pay contracts to load and unload various grades of crude oil into and from railcars, as well as fixed fees per gallon to transload ethanol from railcars, including related logistics services. We also facilitate rail-to-pipeline shipments of crude oil. Our Terminalling services segment also charges minimum monthly fees to store crude oil in tanks that are leased to our customers. The Fleet services segment provides customers with railcars and fleet services related to the transportation of liquid hydrocarbons and biofuels under multi-year, take-or-pay contracts. Corporate activities are not considered a reportable segment, but are included to present shared services and financing activities which are not allocated to our established reporting segment.
Our segments offer different services and are managed accordingly. Our chief operating decision maker, or CODM, regularly reviews financial information about both segments in order to allocate resources and evaluate performance. Our CODM assesses segment performance based on the cash flows produced by our established reporting segments using Segment Adjusted EBITDA. Segmented 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, 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.


20



 
Three Months Ended March 31, 2019
 
Terminalling
services
 
Fleet
services
 
Corporate
 
Total
 
(in thousands)
Revenues
 
 
 
 
 
 
 
Terminalling services
$
19,998

 
$

 
$

 
$
19,998

Terminalling services — related party
5,638

 

 

 
5,638

Fleet leases — related party

 
984

 

 
984

Fleet services

 
57

 

 
57

Fleet services related party

 
227

 

 
227

Freight and other reimbursables
298

 
105

 

 
403

Freight and other reimbursables related party
7

 
54

 

 
61

Total revenues
25,941

 
1,427

 

 
27,368

Operating costs
 
 
 
 
 
 
 
Subcontracted rail services
3,565

 

 

 
3,565

Pipeline fees
5,061

 

 

 
5,061

Freight and other reimbursables
305

 
159

 

 
464

Operating and maintenance
2,163

 
1,048

 

 
3,211

Selling, general and administrative
1,663

 
289

 
2,975

 
4,927

Depreciation and amortization
4,734

 

 

 
4,734

Total operating costs
17,491

 
1,496

 
2,975

 
21,962

Operating income (loss)
8,450

 
(69
)
 
(2,975
)
 
5,406

Interest expense

 

 
3,187

 
3,187

Loss associated with derivative instruments

 

 
672

 
672

Foreign currency transaction loss (gain)
(41
)
 
4

 
219

 
182

Other income, net
(24
)
 

 

 
(24
)
Provision for income taxes
67

 
3

 

 
70

Net income (loss)
$
8,448

 
$
(76
)
 
$
(7,053
)
 
$
1,319

Goodwill
$
33,589

 
$

 
$

 
$
33,589



21



 
Three Months Ended March 31, 2018
 
Terminalling
services
 
Fleet
services
 
Corporate
 
Total
 
(in thousands)
Revenues
 
 
 
 
 
 
 
Terminalling services
$
22,005

 
$

 
$

 
22,005

Terminalling services — related party
4,696

 

 

 
4,696

Fleet leases — related party

 
984

 

 
984

Fleet services

 
344

 

 
344

Fleet services related party

 
227

 

 
227

Freight and other reimbursables
213

 
1,262

 

 
1,475

Freight and other reimbursables related party
2

 

 

 
2

Total revenues
26,916

 
2,817

 

 
29,733

Operating costs
 
 
 
 
 
 
 
Subcontracted rail services
3,062

 

 

 
3,062

Pipeline fees
5,724

 

 

 
5,724

Freight and other reimbursables
215

 
1,262

 

 
1,477

Operating and maintenance
1,291

 
1,065

 

 
2,356

Selling, general and administrative
1,562

 
325

 
2,937

 
4,824

Depreciation and amortization
5,276

 

 

 
5,276

Total operating costs
17,130

 
2,652

 
2,937

 
22,719

Operating income (loss)
9,786

 
165

 
(2,937
)
 
7,014

Interest expense

 

 
2,485

 
2,485

Gain associated with derivative instruments

 

 
(1,024
)
 
(1,024
)
Foreign currency transaction loss (gain)
31

 
(4
)
 
(238
)
 
(211
)
Other expense, net
71

 

 

 
71

Provision for (benefit from) income taxes
(935
)
 
28

 

 
(907
)
Net income (loss)
$
10,619

 
$
141

 
$
(4,160
)
 
$
6,600

Goodwill
$
33,589

 
$

 
$

 
$
33,589



22



Segment Adjusted EBITDA
The following tables present the computation of Segment Adjusted EBITDA for each of our segments for the periods indicated:
 
Three Months Ended March 31,
Terminalling Services Segment
2019
 
2018
 
(in thousands)
Net income
$
8,448

 
$
10,619

Interest income
(7
)
 

Depreciation and amortization
4,734

 
5,276

Provision for (benefit from) income taxes
67

 
(935
)
Foreign currency transaction loss (gain) (1)
(41
)
 
31

Loss associated with disposal of assets
8

 
71

Other income
(17
)
 

Non-cash contract asset (2)
(51
)
 
(51
)
Segment Adjusted EBITDA
$
13,141

 
$
15,011

    
(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 associated with revenue recognized in advance at blended rates based on the escalation clauses in certain of our customer contracts. Refer to Note 4. Revenues — Contract Assets for more information.

 
Three Months Ended March 31,
Fleet Services Segment
2019
 
2018
 
(in thousands)
Net income (loss)
$
(76
)
 
$
141

Provision for income taxes
3

 
28

Foreign currency transaction loss (gain) (1)
4

 
(4
)
Segment Adjusted EBITDA
(69
)
 
165

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

15. INCOME TAXES
U.S. Federal and State Income Taxes
We are treated as a partnership for U.S. federal and most state income tax purposes, with each partner being separately taxed on their share of our taxable income. We have elected to classify one of our subsidiaries, USD Rail LP, as an entity taxable as a corporation for U.S. federal income tax purposes due to treasury regulations that do not permit the income of this subsidiary to meet the definition of “qualifying income” as set forth in Internal Revenue Code §7704(d). We are also subject to state franchise tax in the state of Texas, which is treated as an income tax under the applicable accounting guidance. Our U.S. federal income tax expense is based on the statutory federal income tax rate of 21%, as applied to USD Rail LP’s taxable loss of $0.1 million and $0.3 million for the three months ended March 31, 2019 and 2018, respectively.
Foreign Income Taxes
Our Canadian operations are conducted through entities that are subject to Canadian federal and Alberta provincial income taxes of 15% and 12%, respectively, for a combined federal and provincial income tax rate of 27% applicable


23



to the taxable income of our Canadian operations for the three months ended March 31, 2019 and 2018. The combined rate of 27% was also used to compute deferred income tax expense, which is the result of temporary differences that are expected to reverse in the future.
Estimated Annual Effective Income Tax Rate
The following table presents a reconciliation of our income tax based on the U.S. federal statutory income tax rate and our effective income tax rate:
 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands)
Income tax expense at the U.S. federal statutory rate
$
292

 
21
 %
 
$
1,195

 
21
 %
Amount attributable to partnership not subject to income tax
(265
)
 
(19
)%
 
(1,992
)
 
(35
)%
Foreign income tax rate differential
23

 
2
 %
 
(198
)
 
(3
)%
Other

 
 %
 
8

 
 %
State income tax expense
3

 
 %
 
10

 
 %
Change in valuation allowance
17

 
1
 %
 
70

 
1
 %
Provision for (benefit from) income taxes
$
70

 
5
 %
 
$
(907
)
 
(16
)%
We determined our year-to-date 2019 provision for income taxes using an estimated annual effective income tax rate of 5% on a consolidated basis for fiscal year 2019. This rate incorporates the income tax applicable rates of the various domestic and foreign tax jurisdictions to which we are subject.
 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands)
Current income tax expense:
 
 
 
State income tax expense
$
3

 
$
10

Canadian federal and provincial income taxes expense
316

 
373

Total current income tax expense
319

 
383

Deferred income tax expense (benefit):
 
 
 
U.S. federal income tax expense

 
16

Canadian federal and provincial income taxes benefit
(249
)
 
(1,306
)
Total change in deferred income taxes
(249
)
 
(1,290
)
Provision for (benefit from) income taxes
$
70

 
$
(907
)


24



Our deferred income tax assets and liabilities reflect the income tax effect of differences between the carrying amounts of our assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Major components of deferred income tax assets and liabilities associated with our operations were as follows as of the dates indicated:
 
March 31, 2019
 
U.S.
 
Foreign
 
Total
 
(in thousands)
Deferred income tax assets
 
 
 
 
 
Property and equipment
$

 
$
160

 
$
160

Capital loss carryforwards

 
432

 
432

Operating loss carryforwards
194

 

 
194

Deferred income tax liabilities
 
 
 
 
 
Unbilled revenue

 
(279
)
 
(279
)
Prepaid expenses
(10
)
 

 
(10
)
Property and equipment

 

 

Valuation allowance
(184
)
 
(432
)
 
(616
)
Deferred income tax liability, net
$

 
$
(119
)
 
$
(119
)
 
December 31, 2018
 
U.S.
 
Foreign
 
Total
 
(in thousands)
Deferred income tax assets
 
 
 
 
 
Capital loss carryforwards
$

 
$
432

 
$
432

Operating loss carryforwards
183

 

 
$
183

Deferred income tax liabilities
 
 
 
 
 
Unbilled revenue

 
(336
)
 
(336
)
Prepaid expenses
(10
)
 

 
(10
)
Property and equipment

 
(24
)
 
(24
)
Valuation allowance
(173
)
 
(432
)
 
(605
)
Deferred income tax liability, net
$

 
$
(360
)
 
$
(360
)
We had a $0.9 million U.S. federal loss carryforward remaining as of March 31, 2019 and December 31, 2018. Our U.S. federal loss carryforward was generated in 2018 and 2019 and does not expire under currently enacted tax law. Our Canadian loss carryforward was $4.3 million and $4.2 million as of March 31, 2019 and December 31, 2018, respectively. A portion of our Canadian loss carryforward is for capital items that do not expire under currently enacted Canadian tax law, the remaining Canadian operating loss of $1.1 million will expire in 2034.
We are subject to examination by the taxing authorities for the years ended December 31, 2017, 2016 and 2015. We did not have any unrecognized income tax benefits or any income tax reserves for uncertain tax positions as of March 31, 2019 and December 31, 2018.
Refer to Note 19. Supplemental Cash Flow Information for information regarding amounts paid for income taxes.
 
16. DERIVATIVE FINANCIAL INSTRUMENTS
Our net income and cash flows are subject to fluctuations resulting from changes in interest rates on our variable rate debt obligations and from changes in foreign currency exchange rates, particularly with respect to the U.S. dollar and the Canadian dollar. In limited circumstances, we may also hold long positions in the commodities we handle on behalf of our customers, which exposes us to commodity price risk. We use derivative financial instruments, including futures, forwards, swaps, options and other financial instruments with similar characteristics, to manage the risks associated with market fluctuations in interest rates, foreign currency exchange rates and commodity prices, as well as to reduce volatility in our cash flows. We have not historically designated, nor do we expect to designate, our derivative financial instruments as hedges of the underlying risk exposure. All of our derivative financial instruments are employed


25



in connection with an underlying asset, liability and/or forecasted transaction and are not entered into for speculative purposes.
Interest Rate Derivatives
We use interest rate derivative financial instruments to partially mitigate our exposure to interest rate fluctuations on our variable rate debt. Under our Credit Agreement, one-month LIBOR is used as the index rate for the interest we are charged on amounts borrowed under our Revolving Credit Facility. Effective November 2017, we entered into a five-year interest rate collar contract with a $100 million notional amount. The collar establishes a range where we will pay the counterparty if the one-month Overnight Index Swap, or OIS, rate falls below the established floor rate of 1.7%, and the counterparty will pay us if the one-month OIS rate exceeds the established ceiling rate of 2.5%. The collar settles monthly through the termination date in October 2022. No payments or receipts are exchanged on the interest rate collar contracts unless interest rates rise above or fall below the pre-determined ceiling or floor rates. Prior to February 2019, our interest rate collar contract discussed above was based on one-month LIBOR, which is being phased out by financial institutions in the United States.
Derivative Positions
We record all of our derivative financial instruments at their fair values in the line items specified below within our consolidated balance sheets, the amounts of which were as follows at the dates indicated:
 
March 31, 2019
 
December 31, 2018
 
(in thousands)
Other current assets
$
42

 
$
260

Other non-current assets

 
335

Other non-current liabilities
(120
)
 

 
$
(78
)
 
$
595

We have not designated our derivative financial instruments as hedges of our interest rate or foreign currency exposures. As a result, changes in the fair value of these derivatives are recorded as “Loss (gain) associated with derivative instruments” in our consolidated statements of income. The gains or losses associated with changes in the fair value of our derivative contracts do not affect our cash flows until the underlying contract is settled by making or receiving a payment to or from the counterparty. In connection with our derivative activities, we recognized the following amounts during the periods presented:
 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands)
Loss (gain) associated with derivative instruments
$
672

 
$
(1,024
)
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.


26



The following table presents summarized information about the fair values of our outstanding interest rate contracts for the periods indicated:
 
At March 31, 2019
 
At December 31, 2018
 
 
Notional
 
Interest Rate Parameters
 
Fair Value
 
Fair Value
 
 
 
 
 
 
(in thousands)
Collar Agreements Maturing in 2022
 
 
 
 
 
 
 
 
Ceiling
 
$
100,000,000

 
2.5
%
 
$
533

 
$
1,238

Floor
 
$
100,000,000

 
1.7
%
 
(611
)
 
(643
)
Total
 
 
 
 
 
$
(78
)
 
$
595

We record the fair market value of our derivative financial instruments in our consolidated balance sheets as current and non-current assets or liabilities on a net basis by counterparty. The terms of the International Swaps and Derivatives Association, or ISDA, Master Agreement governs our financial contracts and include master netting agreements that allow the parties to our derivative contracts to elect net settlement in respect of all transactions under the agreements. The effect of the rights of offset are presented in the tables below as of the dates indicated.
 
 
March 31, 2019
 
 
Current assets
 
Non-current assets
 
Current liabilities
 
Non-current liabilities
 
Total
 
 
(in thousands)
Fair value of derivatives — gross presentation
 
$
53

 
$

 
$

 
$
480

 
$
533

Effects of netting arrangements
 
(11
)
 

 

 
(600
)
 
$
(611
)
Fair value of derivatives — net presentation
 
$
42

 
$

 
$

 
$
(120
)
 
$
(78
)
 
 
December 31, 2018
 
 
Current assets
 
Non-current assets
 
Current liabilities
 
Non-current liabilities
 
Total
 
 
(in thousands)
Fair value of derivatives — gross presentation
 
$
260

 
$
978

 
$

 
$

 
$
1,238

Effects of netting arrangements
 

 

 

 
(643
)
 
$
(643
)
Fair value of derivatives — net presentation
 
$
260

 
$
978

 
$

 
$
(643
)
 
$
595

 
17. PARTNERS’ CAPITAL
Our common units and subordinated units represent limited partner interests in us. The holders of common units and subordinated units are entitled to participate in partnership distributions and to exercise the rights and privileges available to limited partners under our partnership agreement.
In February 2019, pursuant to the terms set forth in our partnership agreement, the fourth and final vesting tranche of 38,750 Class A units vested and was converted into our common units. We determined that each vested Class A unit would receive one common unit at conversion based upon our distributions paid for the four preceding quarters. As a result, the final tranche of 38,750 Class A units were converted into 38,750 common units and no Class A units remain outstanding at March 31, 2019. Our Class A units were limited partner interests in us that entitled the holders to nonforfeitable distributions that were equivalent to the distributions paid with respect to our common units (excluding any arrearages of unpaid minimum quarterly distributions from prior quarters) and, as a result, were considered participating securities. Our Class A units did not have voting rights and vested in four equal annual installments over the four years following the consummation of our initial public offering, or IPO, only if we grew our annualized distributions each year. If we did not achieve positive distribution growth in any of those years, the Class A units that would otherwise vest for that year would be forfeited. The Class A units contained a conversion feature, which, upon


27



vesting, provided for the conversion of the Class A units into common units based on a conversion factor that was tied to the level of our distribution growth for the applicable year. The conversion factor was 1.00 for the first vesting tranche, 1.50 for the second vesting tranche, 1.00 for the third vesting tranche and 1.00 for the fourth vesting tranche.
Our partnership agreement provides that, while any subordinated units remain outstanding, holders of our common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to our minimum quarterly distribution per unit, plus (with respect to the common units) any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units.
Subordinated units convert into common units on a one-for-one basis in separate sequential tranches. Each tranche is comprised of 20.0% of the subordinated units issued in conjunction with our IPO. Each separate tranche is eligible to convert on or after December 31, 2015 (but no more frequently than once in any twelve-month period), provided on such date: (i) distributions of available cash from operating surplus on each of the outstanding common units, Class A units, subordinated units and general partner units equaled or exceeded $1.15 per unit (the annualized minimum quarterly distribution) for the four quarter period immediately preceding that date; (ii) the adjusted operating surplus generated during the four quarter period immediately preceding that date equaled or exceeded the sum of $1.15 per unit (the annualized minimum quarterly distribution) on all of the common units, Class A units, subordinated units and general partner units outstanding during that period on a fully diluted basis; and (iii) there are no arrearages in the payment of the minimum quarterly distribution on our common units. For each successive tranche, the four quarter period specified in clauses (i) and (ii) above must commence after the four quarter period applicable to any prior tranche of subordinated units. In February 2019, pursuant to the terms set forth in our partnership agreement, we converted the fourth tranche of 2,092,709 of our subordinated units into common units upon satisfaction of the conditions established for conversion.
Pursuant to the terms of the USD Partners LP Amended and Restated 2014 Long-Term Incentive Plan, which we refer to as the A/R LTIP, our phantom unit awards, or Phantom Units, granted to directors and employees of our general partner and its affiliates, which are classified as equity, are converted into our common units upon vesting. Equity-classified Phantom Units totaling 451,959 vested during the first three months of 2019, of which 360,590 were converted into our common units after 162,533 Phantom Units were withheld from participants for the payment of applicable employment-related withholding taxes. The conversion of these Phantom Units did not have any economic impact on Partners’ Capital, since the economic impact is recognized over the vesting period. Additional information and discussion regarding our unit based compensation plans is included below in Note 18. Unit Based Compensation.
The board of directors of our general partner has adopted a cash distribution policy pursuant to which we intend to distribute at least the minimum quarterly distribution of $0.2875 per unit ($1.15 per unit on an annualized basis) on all of our units to the extent we have sufficient available cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. The board of directors of our general partner may change our distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis. The amount of distributions we pay under our cash distribution policy and the decision to make any distribution are determined by our general partner.
 


28



18. UNIT BASED COMPENSATION
Class A units
Our Class A units vested annually over a four year period if established distribution growth target thresholds were met during each year of the four year vesting period. In February 2019, pursuant to the terms set forth in our partnership agreement, the fourth and final vesting tranche of 38,750 Class A units vested based upon our distributions paid for the four preceding quarters and were converted on a basis of one common unit for each Class A unit. As a result, we converted 38,750 Class A units into 38,750 common units and no Class A units remain outstanding at March 31, 2019.
The following table presents the activity associated with our Class A units for the specified periods:
 
 
Three Months Ended March 31,
 
 
2019
 
2018
Class A units outstanding at beginning of period
 
38,750

 
82,500

Vested
 
(38,750
)
 
(38,750
)
Forfeited
 

 
(5,000
)
Class A units outstanding at end of period
 

 
38,750

We recognized compensation expense in “Selling, general and administrative” with regard to our Class A units for the following amounts during the periods presented:
 
Three months ended March 31,
 
2019
 
2018
 
(in thousands)
Selling, general and administrative
$
14

 
$
70

For the three months ended March 31, 2019, we had no forfeitures of Class A units and forfeitures of 5,000 Class A units during the three months ended March 31, 2018. We elected to account for actual forfeitures as they occurred rather than applying an estimated forfeiture rate when determining compensation expense.
Each holder of a Class A unit was entitled to nonforfeitable cash distributions equal to the product of the number of Class A units outstanding for the participant and the cash distribution per unit paid to our common unitholders. These distributions are included in “Distributions” as presented in our consolidated statements of cash flows and our consolidated statement of partners’ capital. However, any distributions paid on Class A units that are forfeited are reclassified to unit based compensation expense when we determine that the Class A units are not expected to vest. We recognized no compensation expense for the three months ended March 31, 2019, for distributions paid on Class A units that were forfeited. For the three months ended March 31, 2018, we recognized compensation expense of $15 thousand for distributions paid on forfeited Class A units.
Long-term Incentive Plan
In 2019 and 2018, the board of directors of our general partner, acting in its capacity as our general partner, approved the grant of 633,637 and 553,940 Phantom Units, respectively, to directors and employees of our general partner and its affiliates under our A/R LTIP. At March 31, 2019, we had 1,381,649 Phantom Units remaining available for grant pursuant to the terms of our A/R LTIP. The Phantom Units are subject to all of the terms and conditions of the A/R LTIP and the Phantom Unit award agreements, which are collectively referred to as the Award Agreements. Award amounts for each of the grants are generally determined by reference to a specified dollar amount based on an allocation formula which included a percentage multiplier of the grantee’s base salary, among other factors, converted to a number of units based on a closing price of one of our common units preceding the grant date, as determined by the board of directors of our general partner and quoted on the NYSE.


29



Phantom Unit awards generally represent rights to receive our common units upon vesting. However, with respect to the awards granted to directors and employees of our general partner and its affiliates domiciled in Canada, for each Phantom Unit that vests, a participant is entitled to receive cash for an amount equivalent to the closing market price of one of our common units on the vesting date. Each Phantom Unit granted under the Award Agreements includes an accompanying distribution equivalent right, or DER, which entitles each participant to receive payments at a per unit rate equal in amount to the per unit rate for any distributions we make with respect to our common units. The Award Agreements granted to employees of our general partner and its affiliates generally contemplate that the individual grants of Phantom Units will vest in four equal annual installments based on the grantee’s continued employment through the vesting dates specified in the Award Agreements, subject to acceleration upon the grantee’s death or disability, or involuntary termination in connection with a change in control of the Partnership or our general partner. Awards to independent directors of the board of our general partner and an independent consultant typically vest over a one year period following the grant date.
The following tables present the award activity for our Equity-classified Phantom Units:
 
Director and Independent Consultant Phantom Units
 
Employee Phantom Units
 
Weighted-Average Grant Date Fair Value Per Phantom Unit
Phantom Unit awards at December 31, 2018
34,611

 
1,130,685

 
$
11.19

Granted
37,139

 
544,857

 
$
11.37

Vested
(34,611
)
 
(417,348
)
 
$
11.00

Forfeited

 
(2,859
)
 
$
10.94

Phantom Unit awards at March 31, 2019
37,139

 
1,255,335

 
$
11.34

 
Director and Independent Consultant Phantom Units
 
Employee Phantom Units
 
Weighted-Average Grant Date Fair Value Per Phantom Unit
Phantom Unit awards at December 31, 2017
24,999

 
1,111,849

 
$
10.90

Granted
34,611

 
480,839

 
$
11.55

Vested
(24,999
)
 
(336,571
)
 
$
10.86

Forfeited

 
(27,567
)
 
$
11.22

Phantom Unit awards at March 31, 2018
34,611

 
1,228,550

 
$
11.17

The following tables present the award activity for our Liability-classified Phantom Units:
 
Director and Independent Consultant Phantom Units
 
Employee Phantom Units
 
Weighted-Average Grant Date Fair Value Per Phantom Unit
Phantom Unit awards at December 31, 2018
11,348

 
29,265

 
$
11.31

Granted
12,177

 
39,464

 
$
11.37

Vested
(11,348
)
 

 
$
11.55

Phantom Unit awards at March 31, 2019
12,177

 
68,729

 
$
11.32



30



 
Director and Independent Consultant Phantom Units
 
Employee Phantom Units
 
Weighted-Average Grant Date Fair Value Per Phantom Unit
Phantom Unit awards at December 31, 2017
8,333

 
27,794

 
$
11.29

Granted
11,348

 
20,142

 
$
11.55

Vested
(8,333
)
 

 
$
12.80

Phantom Unit awards at March 31, 2018
11,348

 
47,936

 
$
12.13

The fair value of each Phantom Unit on the grant date is equal to the closing market price of our common units on the grant date. We account for the Phantom Unit grants to independent directors and employees of our general partner and its affiliates domiciled in Canada that are paid out in cash upon vesting, throughout the requisite vesting period, by revaluing the unvested Phantom Units outstanding at the end of each reporting period and recording a charge to compensation expense in “Selling, general and administrative” in our consolidated statements of income and recognizing a liability in “Other current liabilities” in our consolidated balance sheets. With respect to the Phantom Units granted to consultants, independent directors and employees of our general partner and its affiliates domiciled in the United States, we amortize the initial grant date fair value over the requisite service period using the straight-line method with a charge to compensation expense in “Selling, general and administrative” in our consolidated statements of income, with an offset to common units within the Partners’ Capital section of our consolidated balance sheet.
For the three months ended March 31, 2019 and 2018, we recognized $1.4 million and $1.3 million, respectively, of compensation expense associated with outstanding Phantom Units. As of March 31, 2019, we have unrecognized compensation expense associated with our outstanding Phantom Units totaling $14.8 million, which we expect to recognize over a weighted average period of 3.02 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 March 31,
 
2019
 
2018
 
(in thousands)
Equity-classified Phantom Units (1)
$
418

 
$
388

Liability-classified Phantom Units
15

 
13

Total
$
433

 
$
401

    
(1) 
For the three months ended March 31, 2019 and 2018, we reclassified $7 thousand and $45 thousand, respectively, to unit based compensation expense for DERs paid in relation to Phantom Units that have been forfeited.
 
19. SUPPLEMENTAL CASH FLOW INFORMATION
The following table provides supplemental cash flow information for the periods indicated:
 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands)
Cash paid for income taxes
$
278

 
$
182

Cash paid for interest
$
2,820

 
$
2,291

Cash paid for operating leases (1)
$
1,538

 
$

    
(1) Our adoption of ASC 842 was as of January 1, 2019. There is no comparable disclosure for the prior year under ASC 840.



31



The following table provides supplemental information for the item labeled “Other” in the “Net cash provided by operating activities” section of our consolidated statements of cash flows:
 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands)
Loss associated with disposal of assets
$
8

 
$
71

Amortization of deferred financing costs
450

 
215

 
$
458

 
$
286

Non-cash activities
During the three months ended March 31, 2019, we had capital expenditures of $2.1 million for which payment had not been made included in accounts payable and accrued expenses.
We recorded $17.3 million of right-of-use lease assets and the associated liabilities on our consolidated balance sheet as of January 1, 2019, representing non-cash activities resulting from our adoption and implementation of ASC 842, Leases. See Note 2. Recent Accounting Pronouncements and Note 7. Leases for further discussion.

20. SUBSEQUENT EVENTS
Distribution to Partners
On April 26, 2019, the board of directors of USD Partners GP LLC, acting in its capacity as our general partner, declared a quarterly cash distribution payable of $0.3625 per unit, or $1.45 per unit on an annualized basis, for the three months ended March 31, 2019. The distribution represents an increase of $0.0025 per unit, or 0.7% over the prior quarter distribution per unit, and is 26.1% over our minimum quarterly distribution per unit. The distribution will be paid on May 15, 2019, to unitholders of record at the close of business on May 7, 2019. The distribution will include payment of $5.4 million to our public common unitholders, an aggregate of $4.2 million to USDG as a holder of our common units and the sole owner of our subordinated units and $308 thousand to USD Partners GP LLC for its general partner interest and as holder of the IDR.


32



Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with the unaudited consolidated financial statements and accompanying notes in “Item 1. Financial Statements” contained herein and our audited consolidated financial statements and accompanying notes included in Item 8. Financial Statements and Supplementary Data in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018. Among other things, those consolidated financial statements include more detailed information regarding the basis of presentation for the following discussion and analysis. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those discussed below. Factors that could cause or contribute to such differences include, but are not limited to, those identified below and those discussed in Item 1A. Risk Factors included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018 and subsequent Quarterly Reports on Form 10-Q. Please also read the Cautionary Note Regarding Forward-Looking Statements following the table of contents in this Report.
We denote amounts denominated in Canadian dollars with C$ immediately prior to the stated amount.

Overview
We are a fee-based, growth-oriented master limited partnership formed by our sponsor, USD, to acquire, develop and operate midstream infrastructure and complementary logistics solutions for crude oil, biofuels and other energy-related products. We generate substantially all of our operating cash flows from multi-year, take-or-pay contracts with primarily investment grade customers, including major integrated oil companies, refiners and marketers. Our network of crude oil terminals facilitates the transportation of heavy crude oil from Western Canada to key demand centers across North America. Our operations include railcar loading and unloading, storage and blending in on-site tanks, inbound and outbound pipeline connectivity, truck transloading, as well as other related logistics services. We also provide our customers with leased railcars and fleet services to facilitate the transportation of liquid hydrocarbons and biofuels by rail.
We generally do not take ownership of the products that we handle, nor do we receive any payments from our customers based on the value of such products. On occasion we enter into buy-sell arrangements in which we take temporary title to commodities while in our terminals. We expect any such arrangements to be at fixed prices where we do not take commodity price exposure.
We believe rail will continue as an important transportation option for energy producers, refiners and marketers due to its unique advantages relative to other transportation means. Specifically, rail transportation of energy-related products provides flexible access to key demand centers on a relatively low fixed-cost basis with faster physical delivery, while preserving the specific quality of customer products over long distances.
USDG, a wholly-owned subsidiary of USD and the sole owner of our general partner, is engaged in designing, developing, owning, and managing large-scale multi-modal logistics centers and energy-related infrastructure across North America. USDG’s solutions create flexible market access for customers in significant growth areas and key demand centers, including Western Canada, the U.S. Gulf Coast and Mexico. Among other projects, USDG is currently pursuing the development of a premier energy logistics terminal on the Houston Ship Channel with capacity for substantial tank storage, multiple docks (including barge and deepwater), inbound and outbound pipeline connectivity, as well as a rail terminal with unit train capabilities. USDG completed an expansion project in January 2019 at the Partnership's Hardisty terminal, which we refer to as Hardisty South, which added one 120-railcar unit train of transloading capacity per day, or approximately 75,000 barrels per day, or bpd.
Recent Developments
Market Update
Substantially all of our operating cash flows are generated from take-or-pay contracts and, as a result, are not directly related to actual throughput volumes at our crude oil terminals. Throughput volumes at our terminals are primarily influenced by the difference in price between Western Canadian Select, or WCS, and other grades of crude oil, commonly referred to as spreads, rather than absolute price levels. WCS spreads are influenced by several market


33



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.
According to Natural Resources Canada, effectively all of Canada’s crude oil exports are transported to the United States. During 2018, oil sands production facilities returned to normal operating levels from supply outages that occurred in prior years and new production capacity has continued to be brought online. Pipeline export capacity from Western Canada remained constrained during 2018 and projects to increase export capacity have continued to experience significant regulatory delays. For example, the anticipated in-service date of the Line 3 Replacement project was changed from late 2019 to the second half of 2020, due to a revised construction schedule. As a result, apportionment levels in 2018 on the primary heavy crude oil pipelines of the largest export pipeline system from Western Canada to the U.S. averaged above 40%, and apportionment on the light crude oil pipelines on the system averaged approximately 40% in the fourth quarter of 2018 (representing the percentage of barrels nominated that were not shipped due to pipeline capacity constraints). Higher apportionment levels led to the following:
Western Canadian crude oil supplies exceeded available pipeline takeaway capacity;
inventory levels grew to historic highs, as barrels not shipped were placed in storage;
WCS pricing spreads in 2018 in relation to key benchmarks widened to levels that were more than double the 2017 average; and
demand for crude-by-rail export capacity increased in 2018, which increased customer activity at our Hardisty origination terminal, as strategically-located rail capacity provided an export outlet for growing oil sands production.
In December 2018, the Alberta Government announced that it would curtail crude oil and bitumen production by 325,000 bpd beginning January 1, 2019. The Alberta Government’s objective was to reduce inventory levels to a targeted level to ensure more economical prices for WCS. Once the targeted inventory and netback levels are achieved, the curtailment is expected to be reduced to approximately 95,000 bpd. During 2019 to date, the Alberta Government has announced reductions to the curtailment level as depicted in the following chart:
Production Month
 
Curtailment Level
(Barrels per day)
February 2019
 
250,000
April 2019
 
225,000
May 2019
 
200,000
June 2019
 
175,000
To address the current pipeline capacity constraints from Western Canada and to increase Alberta’s overall export capacity, the Alberta Government also announced that it plans to invest $3.7 billion to increase rail capacity in order to export WCS to markets with a more economical netback. This initiative includes leasing approximately 4,400 new rail cars to move up to 120,000 bpd of crude oil by 2020, with shipments expected to start as early as mid-2019.
In response to the Alberta Government’s efforts discussed above, the WCS to West Texas Intermediate, or WTI, crude oil spread narrowed to between $7-$14 per barrel to date in 2019 from $11-$50 per barrel during the fourth quarter of 2018. Despite the Alberta Government’s efforts, to date in 2019 apportionment levels on the primary heavy and light crude oil pipelines of the largest export pipeline system from Western Canada to the U.S. have averaged approximately 40% and inventory levels have remained high.
We expect the WCS to WTI spread to widen to levels that will require increasing takeaway capacity from crude by rail as Western Canadian production continues to grow and pipeline takeaway capacity out of the region remains constrained. Future WCS versus WTI spreads published by Bloomberg through 2023 average approximately $21 per barrel and are indicative of the continued expected imbalance between supply and takeaway capacity. The latest data available as published by the U.S. Energy Information Administration, or EIA, indicates Canadian crude-by-rail imports into the United States increased to approximately 409,000 bpd in January 2019. This represents an approximate


34



72% increase in crude-by-rail imports from Canada into the United States over the 2018 yearly average. As such, based on current customer indications, we expect higher demand for and utilization of our terminals going forward in 2019.
Western Canadian crude oil production is projected to continue to increase throughout the next decade, driven primarily by developments in Alberta’s oil sands region. In June 2018, the Canadian Association of Petroleum Producers, or CAPP, projected that the supply of crude oil from Western Canada will grow by approximately 750,000 bpd by 2020 and 1.1 million bpd by 2025 relative to 2017 levels. The forecasted supply of crude oil from Western Canada remains well in excess of existing pipeline takeaway capacity out of the region.
In prior years, the industry has experienced a consolidation of Western Canadian oil sands producing assets among active Canadian producers. We expect this will continue to drive further expansions of crude oil production capacity, particularly at existing projects, as cost savings and technological advancements made during the recent commodity price downturn are incorporated into future development plans.
We expect demand for rail capacity at our terminals to increase over the next several years and potentially longer if proposed pipeline developments do not meet currently planned timelines and regulatory or other challenges persist. Our Hardisty and Casper terminals, with established capacity and scalable designs, are well-positioned as strategic outlets to meet growing takeaway needs as Western Canadian crude oil supplies continue to exceed available pipeline takeaway capacity. Additionally, we believe our Stroud terminal provides an advantageous rail destination for Western Canadian crude oil given the optionality provided by its connectivity to the Cushing hub and multiple refining centers across the United States. Rail also generally provides a greater ability to preserve the specific quality of a customer’s product relative to pipelines, providing value to a producer or refiner. We expect these advantages, including our recently established origin-to-destination capabilities, to continue to result in long-term contract extensions and expansion opportunities across our terminal network.
Commercial Developments
In the first quarter of 2019, USDG executed a new multi-year, take-or-pay terminalling services agreement with the Alberta Petroleum Marketing Commission, or APMC, an agent of the Government of Alberta. The agreement is for transloading capacity at the Hardisty rail terminal starting in January 2020 and contains take-or-pay terms with minimum monthly payments. The agreement will support further expansion at USDG’s Hardisty South and will provide additional capacity beyond the APMC commitment. This expansion will be funded by USDG, pursuant to its development rights at the Hardisty terminal.

How We Generate Revenue
We conduct our business through two distinct reporting segments: Terminalling services and Fleet services. We have established these reporting segments as strategic business units to facilitate the achievement of our long-term objectives, to assist in resource allocation decisions and to assess operational performance.
Terminalling Services
The terminalling services segment includes a network of strategically-located terminals that provide customers with railcar loading and/or unloading capacity, as well as related logistics services, for crude oil and biofuels. Substantially all of our cash flows are generated under multi-year, take-or-pay terminal services agreements that include minimum monthly commitment fees.
Our Hardisty terminal, which commenced operations in late June 2014, is an origination terminal where we load into railcars various grades of Canadian crude oil received from Gibson’s Hardisty storage terminal. Our Hardisty terminal can load up to two 120-railcar unit trains per day and consists of a fixed loading rack with approximately 30 railcar loading positions, a unit train staging area and loop tracks capable of holding five unit trains simultaneously.
Our 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


35



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, which we acquired in November 2015, is a crude oil storage, blending and railcar loading terminal. The terminal currently offers six storage tanks with 900,000 bbls of total capacity, unit train-capable railcar loading capacity in excess of 100,000 bpd, as well as truck transloading capacity. Our Casper terminal is supplied with multiple grades of Canadian crude oil through a direct connection with the Express Pipeline. Additionally, the Casper terminal has a connection from the Platte terminal, where it has access to other pipelines and can receive other grades of crude oil, including locally sourced Wyoming sour crude oil. The Casper terminal can also receive volumes through one truck unloading station and is also equipped with one truck loading station. Additionally, in connection with an agreement that was executed in 2018, we are currently constructing an outbound pipeline connection from the Casper terminal to complement the current inbound pipeline connection and we may construct an additional storage tank to facilitate blending and staging operations for the customer, if needed. However, if the outbound pipeline is not completed by the end of 2019, then pursuant to the agreement, the customer may gain the right to terminate all or portions of the agreement. Currently, we expect to complete the construction of the pipeline by the end of November 2019.
Our West Colton terminal, completed in November 2009, is a unit train-capable destination terminal that can transload up to 13,000 bpd of ethanol received from producers by rail onto trucks to meet local demand in the San Bernardino and Riverside County-Inland Empire region of Southern California. The West Colton terminal has 20 railcar offloading positions and three truck loading positions.
Fleet Services
We provide our customers with leased railcars and fleet services related to the transportation of liquid hydrocarbons and biofuels by rail on multi-year, take-or-pay terms under master fleet services agreements for initial periods ranging from five to nine years. We do not own any railcars. As of March 31, 2019, our railcar fleet consisted of 1,683 railcars, which we leased from various railcar manufacturers and financial entities, including 1,308 coiled and insulated, or C&I, railcars. We have assigned certain payment and performance obligations under the leases and master fleet service agreements for 1,483 of the railcars to other parties, but we have retained certain rights and obligations with respect to the servicing of these railcars. The weighted average remaining contract life on our railcar fleet is 3 years as of March 31, 2019.
Under the master fleet services agreements, we provide customers with railcar-specific fleet services, which may include, among other things, the provision of relevant administrative and billing services, the repair and maintenance of railcars in accordance with standard industry practice and applicable law, the management and tracking of the movement of railcars, the regulatory and administrative reporting and compliance as required in connection with the movement of railcars, and the negotiation for and sourcing of railcars. Our customers typically pay us and our assignees monthly fees per railcar for these services, which include a component for railcar use and a component for fleet services.
 
How We Evaluate Our Operations
Our management uses a variety of financial and operating metrics to evaluate our operations. We consider these metrics to be significant factors in assessing our ability to generate cash and pay distributions and include: (i) Adjusted EBITDA and DCF; (ii) operating costs; and (iii) volumes. We define Adjusted EBITDA and DCF below.  
Adjusted EBITDA and Distributable Cash Flow
We define Adjusted EBITDA as “Net cash provided by operating activities” adjusted for changes in working capital items, interest, income taxes, foreign currency transaction gains and losses, and other items which do not affect the underlying cash flows produced by our businesses. Adjusted EBITDA is a non-GAAP, supplemental financial measure used by management and external users of our financial statements, such as investors and commercial banks, to assess:
our liquidity and the ability of our business to produce sufficient cash flow to make distributions to our unitholders; and
our ability to incur and service debt and fund capital expenditures.


36



We define Distributable Cash Flow, or DCF, as Adjusted EBITDA less net cash paid for interest, income taxes and maintenance capital expenditures. DCF does not reflect changes in working capital balances. DCF is a non-GAAP, supplemental financial measure used by management and by external users of our financial statements, such as investors and commercial banks, to assess:
the amount of cash available for making distributions to our unitholders;
the excess cash flow being retained for use in enhancing our existing business; and
the sustainability of our current distribution rate per unit.
We believe that the presentation of Adjusted EBITDA and DCF in this report provides information that enhances an investor’s understanding of our ability to generate cash for payment of distributions and other purposes. The GAAP measure most directly comparable to Adjusted EBITDA and DCF is “Net cash provided by operating activities.” Adjusted EBITDA and DCF should not be considered as alternatives to “Net cash provided by operating activities” or any other measure of liquidity presented in accordance with GAAP. Adjusted EBITDA and DCF exclude some, but not all, items that affect “Net cash provided by operating activities,” and these measures may vary among other companies. As a result, Adjusted EBITDA and DCF may not be comparable to similarly titled measures of other companies. 
The following table sets forth a reconciliation of Net cash provided by operating activities, the most directly comparable financial measure calculated and presented in accordance with GAAP, to Adjusted EBITDA and DCF:
 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands)
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA and Distributable cash flow:
 
 
 
Net cash provided by operating activities
$
10,171

 
$
8,104

Add (deduct):
 
 
 
Amortization of deferred financing costs
(450
)
 
(215
)
Deferred income taxes
249

 
1,290

Changes in accounts receivable and other assets
(836
)
 
7,277

Changes in accounts payable and accrued expenses
(788
)
 
1,265

Changes in deferred revenue and other liabilities
(198
)
 
(5,499
)
Interest expense, net
3,180

 
2,485

Provision for (benefit from) income taxes
70

 
(907
)
Foreign currency transaction loss (gain) (1)
182

 
(211
)
Other income
(17
)
 

Non-cash contract asset (2)
(51
)
 
(51
)
Adjusted EBITDA
11,512

 
13,538

Add (deduct):
 
 
 
Cash paid for income taxes
(278
)
 
(182
)
Cash paid for interest
(2,820
)
 
(2,291
)
Maintenance capital expenditures

 
(49
)
Distributable cash flow
$
8,414

 
$
11,016

    
(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 associated with revenue recognized in advance at blended rates based on the escalation clauses in certain of our customer contracts. Refer to Note 4. Revenues — Contract Assets of our consolidated financial statements included in Part I — Financial Information, Item 1. Financial Statements of this Report for more information.







37



Operating Costs
Our operating costs are comprised primarily of subcontracted rail expenses, pipeline fees, repairs and maintenance expenses, materials and supplies, utility costs, insurance premiums and lease costs for facilities and equipment. In addition, our operating expenses include the cost of leasing railcars from third-party railcar suppliers and the shipping fees charged by railroads, which costs are generally passed through to our customers. We expect our expenses to remain relatively stable, but they may fluctuate from period to period depending on the mix of activities performed during a period and the timing of these expenditures. With additional throughput volumes handled at our terminals, we expect to incur additional operating costs, including subcontracted rail services and pipeline fees.
Our management seeks to maximize the profitability of our operations by effectively managing both our operating and maintenance expenses. As our terminal facilities and related equipment age, we expect to incur regular maintenance expenditures to maintain the operating capabilities of our facilities and equipment in compliance with sound business practices, our contractual relationships and regulatory requirements for operating these assets. We record these maintenance and other expenses associated with operating our assets in “Operating and maintenance” costs in our consolidated statements of income.
Volumes
The amount of Terminalling services revenue we generate depends on minimum customer commitment fees and the throughput volume that we handle at our terminals in excess of those minimum commitments. These volumes are primarily affected by the supply of and demand for crude oil, refined products and biofuels in the markets served directly or indirectly by our assets. Additionally, these volumes are affected by the spreads between the benchmark prices for these products, which are influenced by, among other things, the available takeaway capacity in those markets. Although customers at our terminals have committed to minimum monthly fees under their terminal services agreements with us, which will generate the majority of our Terminalling services revenue, our results of operations will also be affected by:
our customers’ utilization of our terminals in excess of their minimum monthly volume commitments;
our ability to identify and execute accretive acquisitions and commercialize organic expansion projects to capture incremental volumes; and
our ability to renew contracts with existing customers, enter into contracts with new customers, increase customer commitments and throughput volumes at our terminals, and provide additional ancillary services at those terminals.
 
General Trends and Outlook
We expect our business to continue to be affected by the key trends discussed in “Item 7. Managements Discussion and Analysis of Financial Condition Factors that May Impact Future Results of Operations” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.
Customer Contract Renewals and Expirations
One of the existing terminalling services agreements at our Casper Terminal will expire in August 2019 if not otherwise renewed or extended. If we cannot replace or extend the agreement expiring in August 2019, it would have an adverse effect on our cash flows. We are actively engaged in discussions with this customer as well as other companies that are interested in utilizing the services available at our Casper terminal. For example, in late 2018, we executed a three-year agreement with an investment-grade rated customer at the Casper Terminal. Additionally, we have entered into a one-year terminalling service agreement, effective January 1, 2019, which contains take-or-pay terms for storage services and variable fees associated with actual throughput volumes and other services. However, we cannot make any assurances regarding the outcome of these discussions.
 


38



Factors Affecting the Comparability of Our Financial Results
The comparability of our current financial results in relation to prior periods are affected by the factors described below.
Income Taxes
In conjunction with our adoption of ASC 606 in the prior year, we recognized a deferred tax liability associated with the previously deferred revenues net of previously deferred pipeline fees. We recovered a portion of that deferred tax liability during the three months ended March 31, 2018. For Canadian tax purposes, the previously deferred revenue, net of previously deferred expenses associated with our adoption of ASC 606 was fully recognized ratably during 2018. The deferred tax recovery of $0.9 million (representing C$1.2 million) for the three months ended March 31, 2018 was partially offset by the Canadian tax liability attributable to our current earnings for the three months ended March 31, 2018. Our financial results for the three months ended March 31, 2019 were not affected by similar activities.


39



RESULTS OF OPERATIONS
We conduct our business through two distinct reporting segments: Terminalling services and Fleet services. We have established these reporting segments as strategic business units to facilitate the achievement of our long-term objectives, to aid in resource allocation decisions and to assess operational performance.
The following table summarizes our operating results by business segment and corporate charges for the periods indicated:
 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands)
Operating income (loss)
 
 
 
Terminalling services
$
8,450

 
$
9,786

Fleet services
(69
)
 
165

Corporate and other
(2,975
)
 
(2,937
)
Total operating income
5,406

 
7,014

Interest expense
3,187

 
2,485

Loss (gain) associated with derivative instruments
672

 
(1,024
)
Foreign currency transaction loss (gain)
182

 
(211
)
Other expense (income), net
(24
)
 
71

Provision for (benefit from) income taxes
70

 
(907
)
Net income
$
1,319

 
$
6,600

Summary Analysis of Operating Results
Changes in our operating results for the three months ended March 31, 2019, as compared with our operating results for the three months ended March 31, 2018, were primarily driven by:
a decrease in operating income of our terminalling services business due to the conclusion of a contract at our Casper terminal, increased subcontracted rail services at our Hardisty terminal and increased maintenance costs at our Stroud terminal related to our steaming equipment. The decrease in operating income was partially offset by additional revenues from two new contracts at our Stroud terminal and lower depreciation resulting from a revised estimate of the asset retirement obligation associated with our San Antonio terminal.
a decrease in the operating income of our fleet services business resulting from the conclusion of contracts for approximately 800 railcars;
an increase in interest expense due to a rising interest rate environment;
a derivative instrument loss from our interest rate collar; and
an increase in our provision for income taxes for the current year due to a partial recovery of a deferred tax liability we recognized in 2018 in conjunction with our adoption of ASC 606 that we did not have in 2019.
A comprehensive discussion of our operating results by segment is presented below.



40



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 March 31,
 
2019
 
2018
 
(in thousands)
Revenues
 
 
 
Terminalling services
$
25,636

 
$
26,701

Freight and other reimbursables
305

 
215

Total revenues
25,941


26,916

Operating costs
 
 
 
Subcontracted rail services
3,565

 
3,062

Pipeline fees
5,061

 
5,724

Freight and other reimbursables
305

 
215

Operating and maintenance
2,163

 
1,291

Selling, general and administrative
1,663

 
1,562

Depreciation and amortization
4,734

 
5,276

Total operating costs
17,491


17,130

Operating income
8,450

 
9,786

Foreign currency transaction loss (gain)
(41
)
 
31

Other expense (income), net
(24
)
 
71

Provision for (benefit from) income taxes
67

 
(935
)
Net income
$
8,448

 
$
10,619

Average daily terminal throughput (bpd)
83,303

 
82,284

Three months ended March 31, 2019 compared with three months ended March 31, 2018
Terminalling Services Revenue
Revenue generated by our Terminalling services segment decreased $1.0 million to $25.9 million for the three months ended March 31, 2019, as compared with $26.9 million for the three months ended March 31, 2018. This decrease was primarily due to lower revenue at our Casper terminal resulting from the conclusion of a customer agreement at the end of 2018. This decrease was partially offset by higher revenues at our Stroud terminal associated with additional contracts that were executed in March and April of 2018.
Our average daily terminal throughput of 83,303 bpd for the three months ended March 31, 2019 was relatively consistent with the throughput for the same period in 2018. Higher throughput volumes at our Stroud terminal were partially offset by lower throughput volumes at our Hardisty and Casper terminals. Although our Hardisty terminal did not experience a significant decrease in throughput volume for the three months ended March 31, 2019 as compared with the same period in 2018, expected increases in throughput did not materialize during the first quarter of 2019 due to the effect of the crude oil and bitumen production curtailment mandated by the Government of Alberta that was effective January 1, 2019, as discussed in the Market Update section of this Quarterly Report. Our terminalling services revenues are recognized based upon the contractual terms set forth in our agreements that contain “take-or-pay” provisions, where we are entitled to the payment of minimum monthly commitment fees from our customers, which are recognized as revenue as we provide terminalling services. Increases in the average daily terminal throughput


41



activity only affect revenue to the extent such amounts are in excess of the minimum monthly committed volumes. However, increases in throughput activity, or expected throughput activity, do increase the variable operating costs associated with our terminals, as discussed below.
Our terminalling services revenue for the three months ended March 31, 2019, would have been $0.8 million more if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the three months ended March 31, 2019, was the same as the average exchange rate for the three months ended March 31, 2018. The average exchange rates for the Canadian dollar in relation to the U.S. dollar were 0.7522 and 0.7911 for the three month periods ended March 31, 2019 and 2018, respectively.
Operating Costs
The operating costs of our Terminalling services segment increased $0.4 million to $17.5 million for the three months ended March 31, 2019, as compared with the $17.1 million for the three months ended March 31, 2018. The increase is attributable to additional variable operating costs at our Hardisty and Stroud terminals associated with subcontracted rail service costs, which we incurred with anticipation of higher volumes. We also incurred increased operating costs at our Stroud terminal in connection with operating the steaming equipment we installed for alleviating unloading issues due to cold weather. These costs were partially offset by a reduction in pipeline fees and a decrease in depreciation expense.
Our terminalling services operating costs for the three months ended March 31, 2019, would have been $0.4 million more if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the three months ended March 31, 2019, was the same as the average exchange rate for the three months ended March 31, 2018.
Subcontracted rail services. Our subcontracted rail services costs increased $0.5 million to $3.6 million for the three months ended March 31, 2019 as compared with $3.1 million for the three months ended March 31, 2018. This increase was primarily due to the increased throughput at our Stroud terminal associated with the additional contracts that were executed in March and April of 2018. We also incurred higher subcontracted rail services costs at our Hardisty terminal, in anticipation of expected increases in throughput volumes that did not materialize due to the effect of the crude oil and bitumen production curtailment mandated by the Government of Alberta that was effective throughout the first quarter of 2019.
Pipeline fees. We incur pipeline fees related to a facilities connection agreement with Gibson for the delivery of crude oil from Gibson’s Hardisty storage terminal to our Hardisty terminal via pipeline. The pipeline fees we pay to Gibson are based on a predetermined formula, which includes amounts collected from customers at our Hardisty terminal less direct operating costs. Our pipeline fees decreased $0.7 million to $5.1 million for the three months ended March 31, 2019 as compared with the three months ended March 31, 2018, primarily due to lower revenue and higher direct operating costs at our Hardisty terminal, which reduce the amounts we pay to Gibson.
Operating and maintenance. Operating and maintenance expense increased $0.9 million to $2.2 million for the three months ended March 31, 2019 from the three months ended March 31, 2018. The increased operating and maintenance expenses are primarily due to costs incurred for operating the steaming equipment at our Stroud terminal, which was placed into service in July 2018 to alleviate unloading issues related to cold weather at the terminal. Additionally, we incurred higher repairs and maintenance expenses at our Hardisty and Stroud terminals.
Depreciation and amortization. Depreciation and amortization expense decreased $0.5 million to $4.7 million for the three months ended March 31, 2019 from the three months ended March 31, 2018. The decrease is due to a revised estimate of our asset retirement obligations, or ARO, associated with our San Antonio facility that we recorded during the first quarter of 2019.
Other Expenses
Provision for (benefit from) income taxes. A significant amount of our operating income is generated by our Hardisty terminal located in the Canadian province of Alberta. As a Canadian business, operating income derived from our Hardisty terminal is subject to corporate income taxes assessed at rates enacted by the Canadian federal and provincial governments which currently total 27% on a combined basis.


42



Our income taxes for the Terminalling services segment increased $1.0 million to a provision of $0.1 million for the three months ended March 31, 2019, from a $0.9 million benefit from income taxes for the three months ended March 31, 2018. In connection with our adoption of ASC 606, in 2018, we recovered a deferred tax liability associated with previously deferred revenues net of previously deferred pipeline fees. During the three months ended March 31, 2018, we recovered $0.9 million (C$1.2 million), representing a portion of that deferred tax liability, which produced a benefit from income taxes. We did not have a similar recovery of a deferred tax liability during the three months ended March 31, 2019.
 
FLEET SERVICES
The following table sets forth the operating results of our Fleet services segment for the periods indicated:
 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands)
Revenues
 
 
 
Fleet leases
$
984

 
$
984

Fleet services
284

 
571

Freight and other reimbursables
159

 
1,262

Total revenues
1,427

 
2,817

Operating costs
 
 
 
Freight and other reimbursables
159

 
1,262

Operating and maintenance
1,048

 
1,065

Selling, general and administrative
289

 
325

Total operating costs
1,496

 
2,652

Operating income (loss)
(69
)
 
165

Foreign currency transaction loss (gain)
4

 
(4
)
Provision for income taxes
3

 
28

Net income (loss)
$
(76
)
 
$
141

Three months ended March 31, 2019 compared with three months ended March 31, 2018
Revenues from our Fleet services segment decreased to $1.4 million for the three months ended March 31, 2019, as compared with the $2.8 million for the three months ended March 31, 2018. The decrease in revenue was primarily attributable to a decrease in Freight and other reimbursables revenue, which represents customer reimbursements to us for freight and other charges that we have incurred on behalf of our customers. The decrease in Freight and other reimbursables revenue was exactly offset by a corresponding decrease in Freight and other reimbursables operating costs that primarily arose from railcar repairs and returns, which occurred during the first quarter of 2018, whereas we did not incur such costs during the first quarter of 2019. For example, we had no returns of railcars during the first quarter of 2019. Additionally, fleet services revenues decreased over the prior year associated with approximately 800 fewer railcars outstanding for which we provided fleet services as compared with the same period in 2018.
Historically we have assisted our customers with procuring railcars to facilitate their use of our terminalling services. Our wholly-owned subsidiary USD Rail LP has historically entered into leases with third-party manufacturers of railcars and financial firms, which it has then leased to customers. Although we expect to continue assisting our customers with obtaining railcars for their use transporting crude oil from our terminals, as our existing lease agreements expire, or are otherwise terminated, we do not expect to enter into similar leasing arrangements in the future. Should market conditions change, we would potentially assist with the procurement and management of railcars on behalf of our customers again in the future.


43



 
CORPORATE ACTIVITIES
The following table sets forth our corporate charges for the periods indicated:
 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands)
Operating costs
 
 
 
Selling, general and administrative
$
2,975

 
$
2,937

Operating loss
(2,975
)

(2,937
)
Interest expense
3,187

 
2,485

Loss (gain) associated with derivative instruments
672

 
(1,024
)
Foreign currency transaction loss (gain)
219

 
(238
)
Net loss
$
(7,053
)

$
(4,160
)
Three months ended March 31, 2019 compared with three months ended March 31, 2018
Costs associated with our corporate activities increased by $2.9 million to $7.1 million for the three months ended March 31, 2019. Our “Interest expense” increased $0.7 million to $3.2 million, due to an increase in the interest rates we were charged under our Credit Agreement during the three months ended March 31, 2019, as compared with the same period of 2018. Another factor contributing to the increase during the three months ended March 31, 2019 was a non-cash loss of $0.7 million associated with the interest rate derivatives we entered into in November 2017, as compared to a $1.0 million gain recognized for the corresponding period in 2018.


44



LIQUIDITY AND CAPITAL RESOURCES
Our principal liquidity requirements include:
financing current operations;
servicing our debt;
funding capital expenditures, including acquisitions and the costs to construct new assets; and
making distributions to our unitholders.
We have historically financed our operations with cash generated from our operating activities, borrowings under our Revolving Credit Facility, issuances of partnership interests and loans from our sponsor.
Liquidity Sources
We expect our ongoing sources of liquidity to include borrowings under our $385 million senior secured credit agreement, issuances of debt and additional partnership interests, either privately or pursuant to our effective shelf registration statement, as well as cash generated from our operating activities. We believe that cash generated from these sources will be sufficient to meet our ongoing working capital and capital expenditure requirements and to make quarterly cash distributions.
For information regarding our Credit Agreement, please see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Agreement in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018 and Part I. Item 1. Financial Statements, Note 9. Debt of this Quarterly Report.
The following table presents our available liquidity as of the dates indicated:
 
March 31, 2019
 
December 31, 2018
 
(in millions)
Cash and cash equivalents (1)
$
3.1

 
$
6.4

Aggregate borrowing capacity under Credit Agreement
385.0

 
385.0

Less: Revolving Credit Facility amounts outstanding
207.0

 
209.0

Less: Letters of credit outstanding
0.6

 
0.6

Total available liquidity (2)
$
180.5

 
$
181.8

    
(1) 
Excludes amounts that are restricted pursuant to our collaborative agreement with Gibson.
(2) 
Pursuant to the terms of our Credit Agreement, our borrowing capacity currently is limited to 4.5 times our trailing 12-month consolidated EBITDA.
Energy Capital Partners must approve any additional issuances of equity by us, and such determinations may be made free of any duty to us or our unitholders. Members of our general partner’s board of directors appointed by Energy Capital Partners must also approve the incurrence by us of additional indebtedness or refinancing outside of our existing indebtedness that are not in the ordinary course of business.


45



Cash Flows
The following table and discussion presents a summary of cash flows associated with our operating, investing and financing activities for the periods indicated:
 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands)
Net cash provided by (used in):
 
 
 
Operating activities
$
10,171

 
$
8,104

Investing activities
(244
)
 
158

Financing activities
(13,974
)
 
(10,035
)
Effect of exchange rates on cash
388

 
(678
)
Net change in cash, cash equivalents and restricted cash
$
(3,659
)
 
$
(2,451
)
Operating Activities
Net cash provided by operating activities increased by $2.1 million to $10.2 million for the three months ended March 31, 2019, from $8.1 million for the three months ended March 31, 2018. The increase in Net cash provided by operating activities, was primarily due to the timing of receipts and payments on accounts receivable, accounts payable and deferred revenue balances.
Investing Activities
Net cash used in investing activities increased to $0.2 million for the three months ended March 31, 2019, which primarily related to the pipeline construction at the Casper terminal, as compared with $0.2 million of cash we received from the sale of assets during the three months ended March 31, 2018.
Financing Activities
Net cash used in financing activities increased to $14.0 million for the three months ended March 31, 2019 from $10.0 million for the three months ended March 31, 2018. We repaid $3.0 million more of our long-term debt during the three months ended March 31, 2019, as compared with the amount we repaid during the three months ended March 31, 2018. During the three months ended March 31, 2019, we paid cash distributions of $10.1 million and participant withholding taxes associated with vested Phantom Units of $1.8 million, both of which exceeded amounts paid during the three months ended March 31, 2018, for similar items.
Segment Adjusted EBITDA
The cash generated by our reporting segments represents one of our ongoing sources of liquidity. Our segments offer different services and are managed accordingly. Our chief operating decision maker, or CODM, regularly reviews financial information about both segments in order to allocate resources and evaluate performance. Our CODM assesses segment performance based on the cash flows produced by our established reporting segments using Segment Adjusted EBITDA. 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, foreign currency transaction gains and losses and other items which do not affect the underlying cash flows produced by our businesses.
Segment Adjusted EBITDA is presented in the following table for the periods indicated:


46



 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands)
Segment Adjusted EBITDA
 
 
 
Terminalling services
$
13,141

 
$
15,011

Fleet services
(69
)
 
165

Terminalling Services Segment
Segment Adjusted EBITDA from our Terminalling services segment decreased $1.9 million to $13.1 million for the three months ended March 31, 2019 from $15.0 million for the three months ended March 31, 2018. Refer to Results of Operations — By Segment — Terminalling Services for a discussion of the changes in terminalling services revenues and operating costs for the three months ended March 31, 2019, compared with the three months ended March 31, 2018, that contributed to the changes in Segment Adjusted EBITDA for the respective periods.
Fleet Services Segment
Segment Adjusted EBITDA from our Fleet services business decreased $0.2 million to a loss of $69 thousand for the three months ended March 31, 2019 from the three months ended March 31, 2018. The decrease is primarily the result of approximately 800 fewer railcars outstanding for which we previously provided fleet services, which reduces the Segment Adjusted EBITDA we derive from this segment. Refer to Results of Operations — By Segment — Fleet Services for additional discussion of the changes in fleet services revenues and operating costs for the three months ended March 31, 2019 compared with the three months ended March 31, 2018 that contributed to the changes in Segment Adjusted EBITDA for the respective periods.
Cash Requirements
Our primary requirements for cash are: (1) financing current operations, (2) servicing our debt, (3) funding capital expenditures, including acquisitions and the costs to construct new assets, and (4) making distributions to our unitholders.
Capital Requirements
Our historical capital expenditures have primarily consisted of the costs to construct and acquire energy-related logistics assets. Our operations are expected to require investments to expand, upgrade or enhance existing facilities and to meet environmental and operational regulations.
Our partnership agreement requires that we categorize our capital expenditures as either expansion capital expenditures, maintenance capital expenditures, or investment capital expenditures. Although we have not experienced significant maintenance capital expenditures in prior years as the age of our assets increase, we expect that costs we incur to maintain our assets 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 no maintenance capital expenditures or investment capital expenditures during the three months ended March 31, 2019.
Our total expansion capital expenditures for the three months ended March 31, 2019 amounted to $0.2 million. We expect to fund future capital expenditures from cash on our balance sheet, cash flow generated by our operations, borrowings under our Credit Agreement and the issuance of additional partnership interests or long-term debt.


47



Debt Service
We anticipate reducing our outstanding indebtedness to the extent we generate cash flows in excess of our operating and investing needs. During the three months ended March 31, 2019, we received proceeds from borrowings of $9.0 million on our Revolving Credit Facility which we used for general partnership purposes and made repayments of $11.0 million on our Revolving Credit Facility from cash flow in excess of our operating and investing needs.
Distributions
We intend to pay a minimum quarterly distribution of at least $0.2875 per unit per quarter. Our current quarterly distribution of $0.3625 per unit that we expect to pay, equates to $9.9 million per quarter, or $39.7 million per year, based on the number of common, subordinated, and general partner units outstanding as of May 7, 2019. We do not have a legal obligation to distribute any particular amount per common unit. Additionally, members of our general partner’s board of directors appointed by Energy Capital Partners, if any, must approve any distributions made by us.
Other Items Affecting Liquidity
Credit Risk
Our exposure to credit risk may be affected by the concentration of our customers within the energy industry, as well as changes in economic or other conditions. Our customers’ businesses react differently to changing conditions. We believe that our credit-review procedures, customer deposits and collection procedures have adequately provided for amounts that may become uncollectible in the future.
Foreign Currency Exchange Risk
We currently derive a significant portion of our cash flow from our Canadian operations, particularly our Hardisty terminal. As a result, portions of our cash and cash equivalents are denominated in Canadian dollars and are held by foreign subsidiaries, which amounts are subject to fluctuations resulting from changes in the exchange rate between the U.S. dollar and the Canadian dollar. We routinely employ derivative financial instruments to minimize our exposure to the effect of foreign currency fluctuations, as we deem necessary based upon anticipated economic conditions.
 
SUBSEQUENT EVENTS
Refer to Note 20. Subsequent events of our consolidated financial statements included in Part I Financial Information, Item 1. Financial Statements of this Report for a discussion regarding subsequent events.
 
RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
Refer to Note 2. Recent Accounting Pronouncements of our consolidated financial statements included in Part I Financial Information, Item 1. Financial Statements of this report for a discussion regarding recent accounting pronouncements that we have not yet adopted.
 
OFF BALANCE SHEET ARRANGEMENTS
In the normal course of business, we are a party to off-balance sheet arrangements relating to various master fleet services agreements, whereby we have agreed to assign certain payment and other obligations to third party special purpose entities that are not consolidated with us. We have also entered into agreements to provide fleet services to these special purpose entities for fixed servicing fees and reimbursement of out-of-pocket expenses. The purpose of these transactions is to remove the risk to us of non-payment by our customers, which would otherwise negatively impact our financial condition and results of operations. For more information on these special purpose entities, see the discussion of our relationship with the variable interest entities described in Note 11. Nonconsolidated Variable Interest Entities to our consolidated financial statements included in Part I Financial Information, Item 1. Financial Statements of this Report. Liabilities related to these arrangements are generally not reflected in our consolidated balance sheets, and we do not expect any material impact on our cash flows, results of operations or financial condition as a result of these off-balance sheet arrangements.
 
Item 3. Quantitative and Qualitative Disclosures about Market Risk.
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 March 31, 2019. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow for timely decisions regarding required disclosure and to ensure information is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of March 31, 2019, at the reasonable assurance level.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
We did not make any changes in our internal control over financial reporting during the three months ended March 31, 2019, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


48



PART II — OTHER INFORMATION
Item 1. Legal Proceedings
Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. We do not believe that we are currently a party to any litigation that will have a material adverse impact on our financial condition, results of operations or statements of cash flows. We are not aware of any material legal or governmental proceedings against us, or any proceedings known to be contemplated by governmental authorities.
 
Item 1A. Risk Factors
We are subject to various risks and uncertainties in the ordinary course of our business. Risk factors relating to us are set forth under “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018. No material changes to such risk factors have occurred during the three months ended March 31, 2019.
 
Item 6. Exhibits
The following “Index of Exhibits” is hereby incorporated into this Item.
 


49



 
 
Index of Exhibits
Exhibit
Number
 
Description
 
 
 
3.1
 
 
 
 
3.2
 
 
 
 
31.1*
 
 
 
 
31.2*
 
 
 
 
32.1**
 
 
 
 
32.2**
 
 
 
 
101.INS*
 
XBRL Instance Document
 
 
 
101.SCH*
 
XBRL Schema Document
 
 
 
101.CAL*
 
XBRL Calculation Linkbase Document
 
 
 
101.LAB*
 
XBRL Labels Linkbase Document
 
 
 
101.PRE*
 
XBRL Presentation Linkbase Document
 
 
 
101.DEF*
 
XBRL Definition Linkbase Document
 
*
Filed herewith.
**
Furnished herewith.





50



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



51