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12: R1 Cover Page HTML 85K
13: R2 Consolidated Statements of Operations HTML 121K
14: R3 Consolidated Statements of Comprehensive Income HTML 41K
(Loss)
15: R4 Consolidated Statements of Cash Flows HTML 107K
16: R5 Consolidated Balance Sheets HTML 126K
17: R6 Consolidated Balance Sheets (Parenthetical) HTML 32K
18: R7 Consolidated Statements of Partners Capital HTML 77K
19: R8 Organization and Basis of Presentation HTML 41K
20: R9 Recent Accounting Prounouncements HTML 41K
21: R10 Net Income (Loss) Per Limited Partner Interest HTML 218K
22: R11 Revenues HTML 141K
23: R12 Restricted Cash HTML 39K
24: R13 Property and Equipment HTML 51K
25: R14 Leases HTML 135K
26: R15 Goodwill and Intangible Assets HTML 56K
27: R16 Debt HTML 71K
28: R17 Collaborative Arrangement HTML 30K
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30: R19 Transactions With Related Parties HTML 96K
31: R20 Commitments and Contingencies HTML 29K
32: R21 Segment Reporting HTML 448K
33: R22 Income Taxes HTML 180K
34: R23 Derivative Financial Instruments HTML 108K
35: R24 Partners' Capital HTML 37K
36: R25 Unit Based Compensation HTML 138K
37: R26 Supplemental Cash Flow Information HTML 54K
38: R27 Subsequent Events HTML 30K
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40: R29 Net Income (Loss) Per Limited Partner Interest HTML 219K
(Tables)
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53: R42 Supplemental Cash Flow Information (Tables) HTML 52K
54: R43 Net Income (LOSS) PER LIMITED PARTNER INTEREST - HTML 58K
Schedule of Distribution Method to Limited and
General Partners (Details)
55: R44 Net Income (LOSS) PER LIMITED PARTNER INTEREST - HTML 100K
Schedule of Earnings Per Share, Basic and Diluted
(Details)
56: R45 Revenues (Details) HTML 40K
57: R46 Revenues - Schedule of Geographic Revenues HTML 42K
(Details)
58: R47 REVENUES - Schedule of Remaining Performance HTML 65K
Obligation (Details)
59: R48 REVENUES - Schedule of Contract Assets (Details) HTML 31K
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61: R50 REVENUES - Schedule of Change in Customer HTML 45K
Liability (Details)
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63: R52 PROPERTY AND EQUIPMENT - Schedule of Property and HTML 67K
Equipment (Details)
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65: R54 LEASES - Lease Cost (Details) HTML 43K
66: R55 LEASES - Future payments (Details) HTML 41K
67: R56 LEASES - Lease Income Information (Details) HTML 41K
68: R57 LEASES - Future Lease Income (Details) HTML 34K
69: R58 Goodwill and Intangible Assets (Details) HTML 64K
70: R59 Goodwill and Intangible Assets - Intangible Assets HTML 40K
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71: R60 DEBT - Narrative (Details) HTML 48K
72: R61 DEBT - Schedule of Long-term Debt (Details) HTML 39K
73: R62 DEBT - Schedule of Line of Credit Facilities HTML 42K
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77: R66 TRANSACTIONS WITH RELATED PARTIES - Narrative HTML 97K
(Details)
78: R67 TRANSACTIONS WITH RELATED PARTIES - Schedule of HTML 58K
Deferred Revenue, Current Portion - Related Party
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79: R68 TRANSACTIONS WITH RELATED PARTIES - Schedule of HTML 33K
Cash Distributions (Details)
80: R69 SEGMENT REPORTING - Narrative (Details) HTML 28K
81: R70 SEGMENT REPORTING - Summary of Reportable Segment HTML 156K
Data for Continuing Operations (Details)
82: R71 SEGMENT REPORTING - Reconciliation of Adjusted HTML 67K
EBITDA to Loss from Continuing Operations
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83: R72 INCOME TAXES - Narrative (Details) HTML 58K
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Liabilities (Details)
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Positions Included in the Consolidated Balance
Sheets at Fair Value (Details)
89: R78 DERIVATIVE FINANCIAL INSTRUMENTS - Gain (Loss) on HTML 28K
Derivative Instruments (Details)
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Values of Outstanding Foreign Currency Options
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91: R80 DERIVATIVE FINANCIAL INSTRUMENTS - Schedule of HTML 60K
Commodity Swaps (Details)
92: R81 Partners' Capital (Details) HTML 99K
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96: R85 UNIT BASED COMPENSATION - Long-term Incentive Plan HTML 66K
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98: R87 SUPPLEMENTAL CASH FLOW INFORMATION - Schedule of HTML 51K
Supplemental Cash Flow Disclosures (Details)
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(Exact Name of Registrant as Specified in Its Charter)
iDelaware
i30-0831007
(State
or Other Jurisdiction of Incorporation or Organization)
(I.R.S. Employer Identification No.)
i811 Main Street, iiSuite
2800/
iHouston, iTexasi77002
(Address
of Principal Executive Offices) (Zip Code)
(Registrant’s Telephone Number, Including Area Code): (i281) i291-0510
Securities registered pursuant to Section 12(b) of the Act:
Title
of each class
Trading Symbol
Name of each exchange on which registered
iCommon Units Representing Limited Partner Interests
iUSDP
iNew
York Stock Exchange
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. iYes☒ 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). iYes☒ 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
☐
iAccelerated
Filer
☒
Non-accelerated filer
☐
Smaller reporting company
i☒
Emerging growth company
i☐
If
an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes i☐ No ☒
As
of August 3, 2020, there were i26,844,337 common units and i461,136
general partner units outstanding.
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.
This Report includes forward-looking statements, which are statements that frequently use words such as “anticipate,”“believe,”“continue,”“could,”“estimate,”“expect,”“forecast,”“intend,”“may,”“plan,”“position,”“projection,”“should,”“strategy,”“target,”“will” and similar words. Although we believe that such forward-looking statements are reasonable based on currently available information,
such statements involve risks, uncertainties and assumptions and are not guarantees of performance. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Any forward-looking statement made by us in this Report speaks only as of the date on which it is made, and we undertake no obligation to publicly update any forward-looking statement. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include: (1) the impact of the novel coronavirus (COVID-19) pandemic and related economic downturn and governmental regulations; (2) changes in general economic conditions and commodity prices; (3) the effects of competition, in particular, by pipelines and other terminalling facilities; (4) shut-downs or cutbacks at upstream production facilities,
refineries or other related businesses; (5) the supply of, and demand for, terminalling services for crude oil and biofuels; (6) the price and availability of debt and equity financing; (7) actions by third parties, including customers, lenders, construction-related services providers, and our sponsors; (8) hazards and operating risks that may not be covered fully by insurance; (9) disruptions due to equipment interruption or failure at our facilities or third-party facilities on which our business is dependent; (10) natural disasters, weather-related delays, casualty losses and other matters beyond our control; (11) changes in laws or regulations to which we are subject, including compliance with environmental and operational safety regulations, that may increase our costs or limit our operations; and (12) our ability to successfully identify and finance potential acquisitions and other growth opportunities. For additional factors that may affect our results, see “Risk
Factors” and the other information included elsewhere in this Report and our Annual Report on Form 10-K for the fiscal year ended December 31, 2019 and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, each of which is available to the public over the Internet at the website of the U.S. Securities and Exchange Commission, or SEC, (www.sec.gov) and at our website (www.usdpartners.com).
(unaudited;
in thousands of US dollars, except unit amounts)
Common units
Beginning balance at January 1,
i24,411,892
$
i61,013
i21,916,024
$
i107,903
Conversion
of units
i2,092,709
(i23,423)
i2,131,459
(i19,631)
Common
units issued for vested phantom units
i339,073
(i1,788)
i362,743
(i1,821)
Net
income (loss)
—
(i32,029)
—
i1,767
Unit
based compensation expense
—
i3,150
—
i2,733
Distributions
—
(i12,593)
—
(i17,527)
Ending
balance at June 30,
i26,843,674
(i5,670)
i24,410,226
i73,424
Class
A units
Beginning balance at January 1,
i—
i—
i38,750
i1,018
Conversion
of units
i—
i—
(i38,750)
(i1,018)
Unit
based compensation expense
—
i—
—
i14
Distributions
—
i—
—
(i14)
Ending
balance at June 30,
i—
i—
i—
i—
Subordinated
units
Beginning balance at January 1,
i2,092,709
(i22,597)
i4,185,418
(i39,723)
Conversion
of units
(i2,092,709)
i23,423
(i2,092,709)
i20,637
Net
income (loss)
—
(i15)
—
i162
Unit
based compensation expense
—
i—
—
i2
Distributions
—
(i811)
—
(i2,368)
Ending
balance at June 30,
i—
i—
i2,092,709
(i21,290)
General
Partner units
Beginning balance at January 1,
i461,136
i2,767
i461,136
i3,275
Net
income (loss)
—
(i551)
—
i341
Unit
based compensation expense
—
i1
—
i—
Distributions
—
(i433)
—
(i608)
Ending
balance at June 30,
i461,136
i1,784
i461,136
i3,008
Accumulated
other comprehensive income (loss)
Beginning balance at January 1,
(i127)
(i3,009)
Cumulative
translation adjustment
(i1,605)
i2,555
Ending
balance at June 30,
(i1,732)
(i454)
Total
partners’ capital at June 30,
$
(i5,618)
$
i54,688
The
accompanying notes are an integral part of these consolidated financial statements.
6
USD PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
1. iORGANIZATION
AND BASIS OF PRESENTATION
USD Partners LP and its consolidated subsidiaries, collectively referred to herein as we, us, our, the Partnership and USDP, is a fee-based, growth-oriented master limited partnership formed in 2014 by US Development Group, LLC, or USD, through its wholly-owned subsidiary, USD Group LLC, or USDG. We were formed to acquire, develop and operate midstream infrastructure and complementary logistics solutions for crude oil, biofuels and other energy-related products. We generate substantially all of our operating cash flows from multi-year, take-or-pay contracts with primarily investment grade customers, including major integrated oil companies, refiners and marketers. Our network of crude oil terminals facilitate the
transportation of heavy crude oil from Western Canada to key demand centers across North America. Our operations include railcar loading and unloading, storage and blending in onsite tanks, inbound and outbound pipeline connectivity, truck transloading, as well as other related logistics services. We also provide our customers with leased railcars and fleet services to facilitate the transportation of liquid hydrocarbons and biofuels by rail. We do not generally take ownership of the products that we handle, nor do we receive any payments from our customers based on the value of such products. We may, on occasion, enter into buy-sell arrangements in which we take temporary title to commodities while in our terminals. These arrangements are typically at fixed prices where we do not take commodity price exposure.
A substantial amount of the operating cash flows related to the terminalling services that we provide are generated
from take-or-pay contracts with minimum monthly commitment fees and, as a result, are not directly related to actual throughput volumes at our crude oil terminals. Throughput volumes at our terminals are primarily influenced by the difference in price between Western Canadian Select, or WCS, and other grades of crude oil, commonly referred to as spreads, rather than absolute price levels. WCS spreads are influenced by several market factors, including the availability of supplies relative to the level of demand from refiners and other end users, the price and availability of alternative grades of crude oil, the availability of takeaway capacity, as well as transportation costs from supply areas to demand centers.
Recent Events
In December 2019, a novel coronavirus disease (“COVID-19”)
was reported and in March 2020, the World Health Organization declared that the spread of COVID-19 qualified as a global pandemic. The COVID-19 pandemic has adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the pandemic has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement worldwide. In addition, in March 2020, members of the Organization of the Petroleum Exporting Countries (“OPEC”) and other oil producing countries (“OPEC+”) failed to agree on oil production levels, which led to a substantial decline in oil prices and an increasingly volatile market. In April 2020, even though OPEC+ announced that it had reached an agreement to cut production by 9.7 million barrels per day, or Mmbpd, oil prices did not meaningfully increase. Governments in the United States and Canada limited movement of
people and functioning of businesses in an effort to contain the spread of COVID-19. Mandatory and voluntary closures continue and their duration and impact remains unknown. As a result of these factors, there has been a significant reduction in demand for and prices of crude oil and natural gas liquids. Even when commodity prices have increased, they have remained highly volatile and at relatively low levels that have caused many oil and gas producers to suspend or reduce development programs. In July 2020, OPEC+ agreed to taper oil production cuts, which will scale back production cuts from 9.7 Mmbpd to 7.7 Mmbpd between August 2020 and January 2021.
As a result of the overall downturn in the crude market and the decline in the demand for petroleum products, we tested the goodwill associated with our Casper terminal for impairment as of March 31, 2020, which resulted in an
impairment loss recognized for the six months ended June 30, 2020. Refer to Note 8. Goodwill and intangible assets for further discussion of the impairment loss at the Casper terminal.
7
If the current depressed pricing environment continues for an extended period, it may lead to a potential additional impairment of long-lived assets and customer demand for our services may also be negatively impacted. Any material non-payment or nonperformance by any of our key customers resulting from the current market conditions could have a material adverse
effect on our business, financial condition, and results of operations in future periods.
In addition, in March 2020, United States legislation referred to as the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”), was signed into law. The CARES Act is an emergency economic stimulus package enacted in response to the coronavirus outbreak which, among other measures, contains numerous income tax provisions. Refer to Note 15. Income Taxes for further discussion of the impact of the CARES Act to our income taxes.
iBasis
of Presentation
Our accompanying unaudited interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States, or GAAP, for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all the information and disclosures required by GAAP for complete consolidated financial statements. In the opinion of our management, they contain all adjustments, including adjustments made associated with the provisions of the CARES Act discussed above, and consisting only of normal recurring adjustments, which our management considers necessary to present fairly our financial position as of June 30, 2020, our results of operations for the three and six months ended June 30, 2020
and 2019, and our cash flows for the six months ended June 30, 2020 and 2019. We derived our consolidated balance sheet as of December 31, 2019 from the audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019. Our results of operations for the three and six months ended June 30, 2020 and 2019 should not be taken as indicative of the results to be expected for the full year due to fluctuations in the supply of and demand for crude oil and biofuels, timing and completion of acquisitions, if any, changes in the fair market value of our derivative instruments
and the impact of fluctuations in foreign currency exchange rates. These unaudited interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and accompanying notes thereto presented in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019.
i
Foreign Currency Translation
We conduct a substantial portion of our
operations in Canada, which we account for in the local currency, the Canadian dollar. We translate most Canadian dollar denominated balance sheet accounts into our reporting currency, the U.S. dollar, at the end of period exchange rate, while most accounts in our statement of operations are translated into our reporting currency based on the average exchange rate for each monthly period. Fluctuations in the exchange rate between the Canadian dollar and the U.S. dollar can create variability in the amounts we translate and report in U.S. dollars.
Within these consolidated financial statements, we denote amounts denominated in Canadian dollars with “C$” immediately prior to the stated amount.
US Development Group, LLC
USD and its affiliates are engaged in designing, developing, owning and managing large-scale multi-modal
logistics centers and energy-related infrastructure across North America. USD is the indirect owner of our general partner through its direct ownership of USDG and is currently owned by Energy Capital Partners, Goldman Sachs and certain of USD’s management team members.
8
2. iRECENT
ACCOUNTING PROUNOUNCEMENTS
i
Recently Adopted Accounting Pronouncements
Intangibles - Goodwill and Other
In January 2017, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update No. 2017-04, or ASU 2017-04, which amends ASC Topic 350 to modify the concept of impairment from the condition that exists when the carrying
amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of a reporting unit exceeds its fair value. Pursuant to the provisions of ASU 2017-04, an entity will no longer determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Rather, an entity will recognize an impairment loss for the amount by which the carrying amount of a reporting unit exceeds the reporting unit’s fair value. However, the loss recognized cannot exceed the total amount of goodwill allocated to that reporting unit. The pronouncement is effective for fiscal years beginning after December 15, 2019, or for any interim impairment testing within those fiscal years and is required to be applied prospectively, with early adoption permitted.
We adopted the provisions of ASU 2017-04 on January 1, 2020. In March 2020, we tested the goodwill associated with our Casper terminal for impairment due to there being circumstances that suggested the fair value of the Casper reporting unit was less than its carrying amount. The circumstances identified related to the overall downturn in the crude market and the decline in the demand for petroleum products, which could lead to delays or reductions of expected throughput levels and changes in expectations for current and future contracts at the Casper terminal. Refer to Note 1. Organization and Basis of Presentation— Current
Events for more information. This standard requires us to recognize an impairment loss for the amount by which the carrying amount of our Casper terminal exceeds the fair value of the terminal. Accordingly, we have recognized an impairment loss in our goodwill asset for the six months ended June 30, 2020. Refer to Note 8. Goodwill and Intangible assets for more information.
Recent Accounting Pronouncements Not Yet Adopted
Income Taxes (ASU 2019-12)
In December 2019, the FASB issued Accounting Standards Update No. 2019-12, or ASU 2019-12, which amends ASC Topic 740 by removing certain exceptions related to the approach for intraperiod
tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. It also simplifies aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill. In addition, under the provisions of ASU 2019-12, single-member limited liability companies and similar disregarded entities that are not subject to income tax are not required to recognize an allocation of consolidated income tax expense in their separate financial statements, but they could elect to do so.
The pronouncement is effective for fiscal years beginning after December 15, 2020, or for any interim periods within those fiscal years, with early adoption permitted. We do not expect to early adopt the
provisions of this standard, nor do we anticipate that our adoption of this standard will have a material impact on our financial statements.
3. iNET INCOME (LOSS) PER LIMITED PARTNER INTEREST
We allocate our net income or loss among our general partner and limited partners using the two-class method in accordance with applicable authoritative accounting
guidance. Under the two-class method, we allocate our net income or loss and any net income or loss in excess of distributions to our limited partners, our general partner and the holder of the incentive distribution rights, or IDRs, according to the distribution formula for available cash as set forth in our partnership agreement. We allocate any distributions in excess of earnings for the period to our limited partners and general partner based on their respective proportionate ownership interests in us, as set forth in our
9
partnership agreement after taking into account distributions to be paid with respect to the IDRs. iThe
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
i98%
i2%
First
Target Distribution
> $0.2875 to $0.330625
i98%
i2%
Second
Target Distribution
> $0.330625 to $0.359375
i85%
i15%
Third
Target Distribution
> $0.359375 to $0.431250
i75%
i25%
Thereafter
Amounts
above $0.431250
i50%
i50%
(1)Calculated
as if our general partner holds the original i2% general partner interest in us, which is currently at i1.7%.
i
We
determined basic and diluted net income (loss) per limited partner unit as set forth in the following tables:
Net income attributable to general and limited partner interests in USD Partners LP (1)
$
i1,166
$
i—
$
i—
$
i20
$
i1,186
Less:
Distributable earnings (2)
i3,129
i—
i—
i54
i3,183
Distributions
in excess of earnings
$
(i1,963)
$
i—
$
i—
$
(i34)
$
(i1,997)
Weighted
average units outstanding (3)
i26,844
i—
i—
i461
i27,305
Distributable
earnings per unit (4)
$
i0.12
$
i—
$
i—
Overdistributed
earnings per unit (5)
(i0.07)
i—
i—
Net
income per limited partner unit (basic and diluted) (6)
$
i0.05
$
i—
$
i—
(1)Represents
net income allocated to each class of units based on the actual ownership of the Partnership during the period. There were ino amounts attributed to the general partner for its incentive distribution rights.
(2)Represents the distributions payable for the period based upon the quarterly distribution amounts of $i0.111
per unit or $i0.444 on an annualized basis. Amounts presented for each class of units include a proportionate amount of the $i152
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 i1,367,230
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 i38,750 Class A units vested and were converted into Common units. Additionally, in February 2020, the final tranche of i2,092,709
subordinated units were converted into common units. Refer to Note 17. Partners Capital for more information.
Net income attributable to general and limited partner interests in USD Partners LP (1)
$
i713
$
i61
$
i—
$
i177
$
i951
Less:
Distributable earnings (2)
i9,336
i801
i—
i338
i10,475
Distributions
in excess of earnings
$
(i8,623)
$
(i740)
$
i—
$
(i161)
$
(i9,524)
Weighted
average units outstanding (3)
i24,410
i2,093
i—
i461
i26,964
Distributable
earnings per unit (4)
$
i0.38
$
i0.38
$
i—
Overdistributed
earnings per unit (5)
(i0.35)
(i0.35)
i—
Net
income per limited partner unit (basic and diluted) (6)
$
i0.03
$
i0.03
$
i—
(1)Represents
net income allocated to each class of units based on the actual ownership of the Partnership during the period. The net income for each class of limited partner has been reduced by its proportionate amount of the $i161 thousand attributed to the general partner for its incentive distribution rights.
(2)Represents the distributions paid for the period based upon the quarterly distribution amounts of $i0.365
per unit or $i1.46 per unit on an annualized basis. Amounts presented for each class of units include a proportionate amount of the $i471
thousand distributable to holders of the Equity classified Phantom Units pursuant to the distribution equivalent rights granted under the USD Partners Amended and Restated LP 2014 Long-Term Incentive Plan.
(3)Represents the weighted average units outstanding for the period.
(4)Represents the total distributable earnings divided by the weighted average number of units outstanding for the period.
(5)Represents the distributions in excess of earnings divided by the weighted average number of units outstanding for the period.
(6)Our computation of net income per limited partner unit excludes the effects of i1,292,474
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 i38,750 Class A units vested and were converted into Common units. Refer to Note 17. Partners Capital for more information.
Net loss attributable to general and limited partner interests in USD Partners LP (1)
$
(i32,029)
$
(i15)
$
i—
$
(i551)
$
(i32,595)
Less:
Distributable earnings (2)
i6,258
i—
i—
i107
i6,365
Distributions
in excess of earnings
$
(i38,287)
$
(i15)
$
i—
$
(i658)
$
(i38,960)
Weighted
average units outstanding (3)
i26,180
i575
i—
i461
i27,216
Distributable
earnings per unit (4)
$
i0.24
$
i—
$
i—
Overdistributed
earnings per unit (5)
(i1.46)
(i0.03)
i—
Net
loss per limited partner unit (basic and diluted) (6)
$
(i1.22)
$
(i0.03)
$
i—
(1)Represents
net loss allocated to each class of units based on the actual ownership of the Partnership during the period. There were ino amounts attributed to the general partner for its incentive distribution rights.
(2)Represents the per unit distribution paid of $i0.111
per unit for the three months ended March 31, 2020 and $i0.111 per unit distributable for the three months ended June 30, 2020, representing a year-to-date distribution of $i0.222
per unit. Amounts presented for each class of units include a proportionate amount of the $i152 thousand distributed and $i152
thousand distributable to holders of the Equity classified Phantom Units pursuant to the distribution equivalent rights granted under the USD Partners Amended and Restated LP 2014 Long-Term Incentive Plan.
(3)Represents the weighted average units outstanding for the period.
(4)Represents the total distributable earnings divided by the weighted average number of units outstanding for the period.
(5)Represents the distributions in excess of earnings divided by the weighted average number of units outstanding for the period.
(6)Our computation of net loss per limited partner unit excludes the effects of i1,367,230
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 i38,750 Class A units vested and were converted into Common units. Additionally, in February 2020, the final tranche of i2,092,709
subordinated units were converted into common units. Refer to Note 17. Partners Capital for more information.
Net income attributable to general and limited partner interests in USD Partners LP (1)
$
i1,767
$
i162
$
i—
$
i341
$
i2,270
Less:
Distributable earnings (2)
i18,609
i1,595
i—
i654
i20,858
Distributions
in excess of earnings
$
(i16,842)
$
(i1,433)
$
i—
$
(i313)
$
(i18,588)
Weighted
average units outstanding (3)
i23,739
i2,671
i11
i461
i26,882
Distributable
earnings per unit (4)
$
i0.78
$
i0.60
$
i—
Overdistributed
earnings per unit (5)
(i0.71)
(i0.54)
i—
Net
income per limited partner unit (basic and diluted)(6)
$
i0.07
$
i0.06
$
i—
(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 $i302 thousand attributed to the general partner for its incentive distribution rights.
(2)Represents the per unit distributions paid of $i0.3625
per unit for the three months ended March 31, 2019, and $i0.365 per unit for the three months ended June 30, 2019, representing a year-to-date distribution amount of $i0.7275
per unit. Amounts presented for each class of units include a proportionate amount of the $i940 thousand distributed to holders of the Equity-classified Phantom Units pursuant to the distribution equivalent rights granted under the USD Partners Amended and Restated LP 2014 Long-Term Incentive Plan.
(3)Represents the weighted average units outstanding for the period.
(4)Represents the total distributable earnings
divided by the weighted average number of units outstanding for the period.
(5)Represents the distributions in excess of earnings divided by the weighted average number of units outstanding for the period.
(6)Our computation of net income per limited partner unit excludes the effects of i1,292,474 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 i38,750 Class A units vested and were converted into Common units. Refer to Note 17. Partners Capital for more information.
4. iREVENUES
Disaggregated Revenues
We manage our business in itwo
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 toNote 14. Segment Reporting for our disaggregated revenues by segment. iAdditionally,
the below tables summarize the geographic data for our revenues:
The transaction price allocated to the remaining performance obligations associated with our terminalling and fleet services agreements as of June 30, 2020 are as follows for the periods indicated:
(1)A
significant portion of our terminalling services agreements are denominated in Canadian dollars. We have converted the remaining performance obligations associated with these Canadian dollar-denominated contracts using the year-to-date average exchange rate of i0.7335 U.S. dollars per each Canadian dollar at June 30, 2020.
(2)Includes fixed monthly minimum commitment fees
per contracts and excludes constrained estimates of variable consideration for rate-escalations associated with an index, such as the consumer price index, as well as any incremental revenue associated with volume activity above the minimum volumes set forth within the contracts. Also excludes estimated constrained variable consideration included in certain of our terminalling services agreements that is based on crude oil pricing index differentials.
(3)Assumes USD’s Diluent Recovery Unit project goes into service in the second half of 2021, which will result in certain terminalling services agreements of our Hardisty terminal being automatically extended through mid-2031 and certain agreements at our Stroud terminal having
a termination right in June 2022.
/
We have applied the practical expedient that allows us to exclude disclosure of performance obligations that are part of a contract that has an expected duration of ione year or less.
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.
i
We had
the following amounts outstanding associated with our contract assets on our consolidated balance sheets in the financial statement line items presented below in the following table for the indicated periods:
Our deferred revenue is a form of a contract liability and consists of amounts collected in advance from customers associated with their terminalling and fleet services agreements and deferred revenues associated with make-up rights, which will be recognized as revenue when earned pursuant to the terms of our contractual arrangements. We currently recognize substantially all of the amounts we receive for minimum volume commitments as revenue when collected, since breakage associated with these make-up rights is currently i100%
based on our experience and expectations around usage of these options. Accordingly, we had ino deferred revenues at June 30, 2020 for estimated breakage associated with the make-up rights options we granted to our customers. There were $i1.1 million
deferred revenues associated with make-up rights at December 31, 2019.
We also have deferred revenue that represents cumulative revenue that has been deferred due to tiered billing provisions. In such arrangements, revenue is recognized using a blended rate based on the billing tiers of the agreement, as the services are consistently provided throughout the duration of the contractual arrangement, which we included in “Other non-current liabilities” on our consolidated balance sheets.
We have the following amounts outstanding associated with our deferred revenue on our consolidated balance sheets in the financial statement line items presented below in the following table for the indicated periods:
(1)
Includes deferred revenue associated with customer prepayments from related parties. Refer toNote 12. Transactions with Related Parties for additional discussion of deferred revenues associated with related parties. Excludes deferred revenue from related parties associated with our fleet leases discussed below.
The following table presents the changes associated with the balance of our deferred revenue for the six months ended June 30, 2020:
(1) Includes
deferred revenue associated with customer prepayments from related parties. Refer to Note 12. Transactions with Related Parties for additional discussion of deferred revenues associated with related parties. Excludes deferred revenue from related parties associated with our fleet leases discussed below.
(2) Includes cumulative revenue that has been deferred due to tiered billing provisions included in certain of our Canadian dollar-denominated contracts, as discussed above. As such, the change in Other contract liabilities presented has been reduced by approximately $i155
thousand due to the impact of the change in the end of period exchange rate between December 31, 2019 and June 30, 2020.
Deferred Revenue — Fleet Leases
Our deferred revenue also includes advance payments from customers of our Fleet services business, which will be recognized as Fleet leases revenue when earned pursuant to the terms of our contractual arrangements. We have included $ii0.4/
million at June 30, 2020 and December 31, 2019, in “Deferred revenue — related party” on our
14
consolidated balance sheets associated with customer prepayments for our fleet lease agreements. Refer to Note 7. Leases for additional discussion of our lease revenues.
5. iRESTRICTED
CASH
We include in restricted cash amounts representing a cash account for which the use of funds is restricted by a facilities connection agreement among us and Gibson Energy Inc., or Gibson, that we entered into during 2014 in connection with the development of our Hardisty terminal. The collaborative arrangement is further discussed in Note 10. Collaborative Arrangement.
ii
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:
(1)The
amounts classified as “Construction in progress” are excluded from amounts being depreciated. These amounts represent property that has not been placed into productive service as of the respective consolidated balance sheet date. We had iino/
capitalized interest costs for the three and six months ended June 30, 2020, and $i131 thousand and $i269 thousand
for the three and six months ended June 30, 2019, respectively
/
Depreciation expense associated with property and equipment totaled $ii2.1/
million for the three months ended June 30, 2020 and 2019, and $i4.3 million and $i3.7 million for the six months ended June 30, 2020
and 2019, respectively.
Our depreciation expense reflects a reduction to our asset retirement obligation, or ARO, of $ii0.2/ million
for the three and six months ended June 30, 2020 and $i0.6 million for the six months ended June 30, 2019 due to refinement of our estimates. We had no change in our estimates for the three months ended June 30, 2019. The ARO was associated with restoration of the property at our San Antonio facility. All remediation activities associated with the ARO are now deemed complete and
this position has not been disputed by the property owner. There is ino remaining balance related to ARO on our consolidated balance sheet at June 30, 2020.
15
7. iiLEASES/
i
We
have noncancellable operating leases for railcars, buildings, storage tanks, offices, railroad tracks, and land.
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 June 30, 2020 (in thousands):
2020
$
i2,929
2021
i5,509
2022
i4,507
2023
i22
Total
lease payments
$
i12,967
Less: imputed interest
(i876)
Present
value of lease liabilities
$
i12,091
/
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.
(1)Lease income associated with crude oil storage tanks we lease to customers of our terminals totaling $i1.4 million
and $i1.6 million for the three months ended June 30, 2020 and 2019, and $i2.5 million
and $i3.2 million for the six months ended June 30, 2020 and 2019, respectively, is included in “Terminalling services” revenues on our consolidated statements of operations.
/
16
i
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 June 30, 2020 (in thousands):
2020
$
i4,732
2021
i8,290
2022
i5,354
Total
$
i18,376
/
8. iGOODWILL
AND INTANGIBLE ASSETS
Goodwill
Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed. Our goodwill originated from our acquisition of the Casper terminal, which is included in our Terminalling services segment.
We test goodwill for impairment annually based on the carrying amounts of our reporting units on the first day of the third quarter of each year or more frequently if events or changes in circumstances suggest that the fair value of a reporting unit is less than its carrying amount. In March 2020, we tested the goodwill associated with our Casper terminal for impairment due to the overall downturn in the crude market and the decline in the demand for petroleum products, which could lead to delays or reductions of expected throughput
levels and changes in expectations for current and future contracts at the Casper terminal. Refer to Note 1. Organization and Basis of Presentation— Current Events for more information.
The critical assumptions used in our analysis include the following:
1)a weighted average cost of capital of i12%;
2)a
capital structure consisting of approximately i65% debt and i35% equity based on the capital structure of market participants;
3)a
range of EBITDA multiples derived from equity prices of public companies with similar operating and investment characteristics, from i7.25x to i8.25x;
4)a
range of EBITDA multiples for transactions based on actual sales and purchases of comparable businesses, from i8.0x to i9.0x;
and
5)a range of incremental volumes expected at our Casper terminal of approximately i4,000 to i25,000
bpd for terminalling and storage services resulting from the anticipated successful completion of the Enbridge DRA project in the second half of 2020.
We measured the fair value of our Casper terminal reporting unit by using an income analysis, market analysis and transaction analysis with weightings of i50%, i25%
and i25%, respectively. Our estimate of fair value required us to use significant unobservable inputs representative of a Level 3 fair value measurement, including assumptions related to the future performance of our Casper terminal.
We determined that the carrying amount of our Casper terminal reporting unit exceeded its fair value at March 31, 2020. Accordingly, we recognized an impairment loss of $i33.6
million in our goodwill asset and included this charge in “Goodwill impairment loss” within our consolidated statement of operations for the six months ended June 30, 2020. For additional information see Note 2. Recent Accounting Pronouncements. At June 30, 2020, we had ino goodwill balance in our consolidated balance sheet.
17
Intangible
Assets
i
The composition, gross carrying amount and accumulated amortization of our identifiable intangible assets are as follows as of the dates indicated:
Amortization
expense associated with intangible assets totaled $ii3.2/
million for each of the three months ended June 30, 2020 and 2019, and $ii6.3/
million for each of the six months ended June 30, 2020 and 2019.
We determined the overall downturn in the crude market and the decline in the demand for petroleum products, which could lead to delays or reduction of expected throughput levels and changes in expectations for current and future contracts in our terminalling services at the Casper terminal was an event that required us to evaluate our Casper terminal asset group for impairment. We measured the fair value of our Casper terminal assets at March 31, 2020, by using projections of the undiscounted cash flows expected to be derived from the operation and disposition of the Casper terminal asset.
The
critical assumptions underlying our projections included the following:
1)a range of incremental volumes expected at our Casper terminal of approximately i4,000 to i25,000
bpd for terminalling and storage services resulting from the anticipated successful completion of the Enbridge DRA project in the second half of 2020;
2)expected volumes for our blended services business for distribution to local refiners;
3)a i15 year remaining useful life of the primary asset, represented by our property and equipment of the Casper terminal asset group; and
4)a residual value of i8.0x
projected cash flows for the Casper terminal at the end of the i15 year remaining life of the primary asset.
Our projections of the undiscounted cash flows expected to be derived from the operation and disposition of the Casper terminal asset group exceeded the carrying amount of the asset group as of March 31, 2020, the date of our evaluation, indicating cash flows were expected to be sufficient to recover the carrying amount of the Casper terminal asset group. Accordingly, we did not recognize any impairment of our
asset. We have not observed any events or circumstances subsequent to our analysis that would suggest the fair value of our Casper terminal is below its carrying amount as of June 30, 2020.
9. iDEBT
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 $i385 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.
18
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 itwoone-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 $i500
million, subject to receiving increased commitments from lenders and satisfaction of certain conditions.
Our Credit Agreement and any issuances of letters of credit are available for working capital, capital expenditures, general partnership purposes and continue the indebtedness outstanding under the Previous Credit Agreement. The Credit Agreement includes an aggregate $i20 million sublimit for standby letters of credit and a $i20
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.
i
Our long-term debt balances included the following components as of the specified dates:
Available
under the Credit Agreement based on capacity
$
i167.0
$
i165.0
Available
under the Credit Agreement based on covenants (1)
$
i26.2
$
i28.8
(1) Pursuant
to the terms of our Credit Agreement, our borrowing capacity, currently, is limited to i4.5 times our trailing 12-month consolidated EBITDA, which equates to $i26.2 million
and $i28.8 million of borrowing capacity available at June 30, 2020 and December 31, 2019, respectively.
/
The weighted average interest rate on our outstanding indebtedness was i2.94%
and i4.24% at June 30, 2020 and December 31, 2019, respectively, without consideration to the effect of our derivative contracts. In addition to the interest we incur on our outstanding indebtedness, we pay commitment fees of i0.50%
on unused commitments, which rate will vary based on our consolidated net leverage ratio, as defined in our Credit Agreement. At June 30, 2020, we were in compliance with the covenants set forth in our Credit Agreement.
i
Interest expense associated with our outstanding indebtedness was as follows for the specified periods:
We entered into a facilities connection agreement in 2014 with Gibson under which Gibson developed, constructed and operates a pipeline and related facilities connected to our Hardisty terminal. Gibson’s storage terminal is the exclusive means by which our Hardisty terminal receives crude oil. Subject to certain limited exceptions regarding manifest train facilities, our Hardisty terminal is the exclusive means by which crude oil from Gibson’s Hardisty storage terminal may be transported by rail. We remit pipeline fees to Gibson for the transportation of crude oil to our Hardisty terminal based on a predetermined formula. Pursuant to our arrangement with Gibson, we incurred pipeline fees of $i5.4 million
and $i4.9 million for the three months ended June 30, 2020 and 2019, and $i11.7
million and $i10.0 million for the six months ended June 30, 2020 and 2019, respectively, which are presented as “Pipeline fees” in our consolidated statements of operations. We have included a liability related to this agreement in “Other Current Liabilities” on our consolidated balance sheets of $i1.6
million and $i1.2 million at June 30, 2020 and December 31, 2019.
11. iNONCONSOLIDATED
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.
i
The following table summarizes the total assets and liabilities between us and the VIEs as reflected in our consolidated balance sheets at June 30, 2020 and December 31, 2019, as well as our maximum exposure to losses from
entities in which we have a variable interest, but are not the primary beneficiary. Generally, our maximum exposure to losses is limited to amounts receivable for services we provided, reduced by any deferred revenues.
We
have assigned certain payment and performance obligations under the leases and master fleet service agreements for i1,232 railcars to the VIEs, but we have retained certain rights and obligations with respect to the servicing of these railcars.
20
During
the quarter ended June 30, 2020, we provided no explicit or implicit financial or other support to these VIEs that were not previously contractually required.
12. iTRANSACTIONS 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 June 30, 2020, owns i11,557,090 of our common units representing a i42.3%
limited partner interest in us. As of June 30, 2020, a value of up to $i10.0 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 i461,136 of our general partner units representing a i1.7%
general partner interest in us, as well as all of our incentive distribution rights. Pursuant to our partnership agreement, our general partner is responsible for our overall governance and operations.
USD Marketing LLC, or USDM, is a wholly-owned subsidiary of USDG organized to promote contracting for services provided by our terminals and to facilitate the marketing of customer products.
USD Terminals Canada II ULC, or USDTC II, is an indirect, wholly-owned Canadian subsidiary of USDG, organized for the purposes of pursuing expansion and other development opportunities associated with our Hardisty Terminal, pursuant to the Development Rights and Cooperation agreement between our wholly-owned subsidiary USD Terminals Canada ULC, or USDTC, and USDG. USDTC owns the legacy crude oil loading facility we refer to as the Hardisty terminal. USDTC II completed construction of the Hardisty
South expansion (“Hardisty South”) which commenced operations in January 2019. Hardisty South, which is owned and operated by USDTC II, added one and one-half i120-railcar unit trains of transloading capacity per day, or approximately i112,500
barrels per day, of takeaway capacity to the terminal by modifying the existing loading rack and building additional infrastructure and trackage.
Omnibus Agreement
We are party to an omnibus agreement with USD, USDG and certain of their subsidiaries, or Omnibus Agreement, including our general partner, pursuant to which we obtain and make payments for specified services provided to us and for out-of-pocket costs incurred on our behalf. We pay USDG, in equal monthly installments, the annual amount USDG estimates will be payable by us during the calendar year for providing services for our benefit. The Omnibus Agreement provides that this amount may be adjusted annually to reflect, among other things, changes in the scope of the general and administrative services provided
to us due to a contribution, acquisition or disposition of assets by us or our subsidiaries, or for changes in any law, rule or regulation applicable to us, which affects the cost of providing the general and administrative services. We also reimburse USDG for any out-of-pocket costs and expenses incurred on our behalf in providing general and administrative services to us. This reimbursement is in addition to the amounts we pay to reimburse our general partner and its affiliates for certain costs and expenses incurred on our behalf for managing our business and operations, as required by our partnership agreement.
The total amounts charged to us under the Omnibus Agreement for the three months ended June 30, 2020 and 2019 was $i1.8
million and $i2.2 million, respectively, and for the six months ended June 30, 2020 and 2019 was $i3.8
million and $i4.7 million, respectively, which amounts are included in “Selling, general and administrative — related party” in our consolidated statements of operations. We had a payable balance of $i0.3
million and $i0.4 million with respect to these costs at June 30, 2020 and December 31, 2019, respectively included in “Accounts payable and accrued expenses — related party” in our consolidated balance sheets.
21
Marketing
Services Agreement
In connection with our purchase of the Stroud terminal, we entered into a Marketing Services Agreement with USDM, in May 2017, whereby we granted USDM the right to market the capacity at the Stroud terminal in excess of the original capacity of our initial customer in exchange for a nominal per barrel fee. USDM is obligated to fund any related capital costs associated with increasing the throughput or efficiency of the terminal to handle additional throughput. Upon expiration of our contract with the initial Stroud customer in June 2020, the same marketing rights now apply to all throughput at the Stroud terminal in excess of the throughput necessary for the Stroud terminal to generate Adjusted EBITDA that is at least equal to the average monthly Adjusted EBITDA derived from the initial Stroud customer during the 12
months prior to expiration. We also granted USDG the right to develop other projects at the Stroud terminal in exchange for the payment to us of market-based compensation for the use of our property for such development projects. Any such development projects would be wholly-owned by USDG and would be subject to our existing right of first offer with respect to midstream projects developed by USDG. Payments made under the Marketing Services Agreement during the periods presented in this Report are discussed below under the heading “Related Party Revenue and Deferred Revenue.”
Hardisty Terminal Services Agreement
We entered into a terminal services agreement with USDTC II during the third quarter of 2019, whereby Hardisty South will provide terminalling services for a third-party customer of our Hardisty terminal for contracted capacity
that exceeds the transloading capacity currently available, We incurred $i2.1 million and $i4.1
million of expenses pursuant to the arrangement for the three and six months ended June 30, 2020, which amounts are included in “Operating and maintenance expense — related party” in our consolidated statements of operations. These costs represent the same rate, on a per barrel basis, that we received as revenue from our third-party customer, which is included in “Terminalling Services” revenue in our consolidated statements of operations. Additionally, in conjunction with this agreement, we recorded a contract asset of $i0.8
million at June 30, 2020 on our consolidated balance sheet in “Other non-current assets — related party”, representing long-term prepaid expense associated with this agreement due to tiered billing provisions in the related terminalling services agreements. We had ino recorded asset at December 31, 2019, associated with this agreement.
Hardisty
Shared Facilities Agreement
USDTC facilitates the provision of services on behalf of USDTC II pursuant to the terms of a shared facilities agreement, which includes all subcontracted railcar loading, operating, maintenance, pipeline and management services for the entire Hardisty terminal, including Hardisty South owned by USDTC II. USDTC passes through a proportionate amount of the cost of such services to USDTC II. Our financial statements only reflect the cost incurred by USDTC.
Related Party Revenue and Deferred Revenue
We have agreements to provide terminalling and fleet services for USDM with respect to our Hardisty terminal and terminalling services with respect to our Stroud terminal, which also include reimbursement to us for certain out-of-pocket expenses we incur.
USDM assumed the rights
and obligations for terminalling capacity at our Hardisty terminal from another customer in June 2017 to facilitate the origination of crude oil barrels by the Stroud customer from our Hardisty terminal for delivery to the Stroud terminal. As a result of USDM assuming these rights and obligations and in order to accommodate the needs of the Stroud customer, the contracted term for the capacity held by USDM at our Hardisty terminal was extended from June 30, 2019 to June 30, 2020. The terms and conditions of these agreements are similar to the terms and conditions of agreements we have with other parties at the Hardisty terminal that are not related to us. USDM’s agreement with the third party customer was renewed and extended, effective July 1, 2020, and USDM subsequently assigned its terminalling services agreement with
the third party customer directly to us and is therefore no longer a customer at our Hardisty terminal. USDM controlled approximately i25% of the available monthly capacity of the Hardisty terminal through June 30, 2020.
22
In connection with our purchase of the Stroud terminal, we also entered
into a Marketing Services Agreement with USDM, as discussed above. Pursuant to the terms of the agreement, we receive a fixed amount per barrel from USDM in exchange for marketing the additional capacity available at the Stroud terminal. We also received revenue for providing additional terminalling services at our Hardisty terminal to USDM pursuant to the terms of its existing agreements with us. Additionally, effective January 2019, we entered into a six month terminalling services agreement with USDM at our Casper terminal to maximize utilization of available terminalling and storage capacity by offering these services to customers on an uncommitted basis at current market rates. This agreement automatically renews for successive periods of six months on an evergreen basis unless otherwise canceled by either party. We include amounts received pursuant to these arrangements as revenue in the table below under “Terminalling
services — related party” in our consolidated statements of operations. Additionally, we received revenue from USDM for the lease of i200 railcars pursuant to the terms of an existing agreement with us, which is included in the table below under “Fleet leases — related party” and “Fleet services — related party” and in our consolidated statements of operations.
i
Our
related party revenues from USD and affiliates are presented below in the following table for the indicated periods:
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:
Accounts
payable and accrued expenses — related party (1)
$
i64
$
i87
Other
current and non-current assets — related party (2)
$
i855
$
i358
Deferred
revenue — related party (3)
$
i410
$
i1,482
(1)Includes
amounts payable to a related party pursuant to the Hardisty Terminal Services Agreement, discussed above, as well as other accounts payable related party amounts associated with our terminalling services business. Does not include amounts payable to related parties associated with the Omnibus Agreement, as discussed above.
(2)Includes a contract asset associated with a lease agreement with USDM and cumulative revenue that has been recognized in advance of billing the customer due to tiered billing provisions. Refer to Note 4. Revenue for further discussion. Also includes a contract
asset associated with the Hardisty Terminal Services Agreement with USDTC II, as discussed above.
(3)Represents deferred revenues associated with our terminalling and fleet services agreements with USD and affiliates for amounts we have collected from them for their prepaid leases and prepaid minimum volume commitment fees.
/
23
Cash Distributions
i
We
paid the following aggregate cash distributions to USDG as a holder of our common units, and with respect to the February 2020 payment date, the sole owner of our subordinated units and to USD Partners GP LLC as sole holder of our general partner interest and IDRs.
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. iSEGMENT REPORTING
We manage our business in itwo
reportable segments: Terminalling services and Fleet services. The Terminalling services segment charges minimum monthly commitment fees under multi-year take-or-pay contracts to load and unload various grades of crude oil into and from railcars, as well as fixed fees per gallon to transload ethanol from railcars, including related logistics services. We also facilitate rail-to-pipeline shipments of crude oil. Our Terminalling services segment also charges minimum monthly fees to store crude oil in tanks that are leased to our customers. The Fleet services segment provides customers with railcars and fleet services related to the transportation of liquid hydrocarbons and biofuels under multi-year, take-or-pay contracts. Corporate activities are not considered a reportable segment, but are
included to present shared services and financing activities which are not allocated to our established reporting segments.
Our segments offer different services and are managed accordingly. Our chief operating decision maker, or CODM, regularly reviews financial information about both segments in order to allocate resources and evaluate performance. Our CODM assesses segment performance based on the cash flows produced by our established reporting segments using Segment Adjusted EBITDA. Segment Adjusted EBITDA is a measure calculated in accordance with GAAP. We define Segment Adjusted EBITDA as “Net income (loss)” of each segment adjusted for depreciation and amortization, interest, income taxes, changes in contract assets and liabilities, deferred revenues, foreign currency transaction gains and losses and other items which
do not affect the underlying cash flows produced by our businesses. As such, we have concluded that disaggregating revenue by reporting segments appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors.
The following tables present the computation of Segment Adjusted EBITDA, which is a measure determined in accordance with GAAP, for each of our segments for the periods indicated:
Three
Months Ended June 30,
Six Months Ended June 30,
Terminalling Services Segment
2020
2019
2020
2019
(in thousands)
Net
income (loss)
$
i7,623
$
i8,155
$
(i17,818)
$
i16,603
Interest
income (1)
(i2)
(i8)
(i23)
(i15)
Depreciation
and amortization
i5,203
i5,283
i10,625
i10,017
Provision
for income taxes
i208
i123
i161
i190
Foreign
currency transaction loss (gain) (2)
i81
(i54)
i7
(i95)
Loss
associated with disposal of assets
i—
i42
i—
i50
Goodwill
impairment loss
i—
i—
i33,589
i—
Other
income
i—
(i25)
i—
(i42)
Non-cash
deferred amounts (3)
i1,119
i161
i1,556
i110
Segment
Adjusted EBITDA
$
i14,232
$
i13,677
$
i28,097
$
i26,818
(1) Represents
interest income associated with our Terminalling Services segment that is included in “Other expense (income), net” in our consolidated statements of operations.
(2) Represents foreign exchange transaction amounts associated with activities between our U.S. and Canadian subsidiaries.
(3) Represents the change in non-cash contract assets and liabilities associated with revenue recognized at blended rates based on tiered rate structures in certain of our customer contracts and deferred revenue associated with deficiency
credits that are expected to be used in the future prior to their expiration. Amounts presented are net of the corresponding prepaid Gibson pipeline fee that will be recognized as expense concurrently with the recognition of revenue.
Three Months Ended June 30,
Six
Months Ended June 30,
Fleet Services Segment
2020
2019
2020
2019
(in thousands)
Net income (loss)
$
i41
$
i65
$
i435
$
(i11)
Provision
for (benefit from) income taxes
(i20)
i5
(i480)
i8
Foreign
currency transaction loss (gain) (1)
i3
i4
(i3)
i8
Segment
Adjusted EBITDA
i24
i74
(i48)
i5
(1) Represents
foreign exchange transaction amounts associated with activities between our U.S. and Canadian subsidiaries.
/
29
15. iINCOME
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 be classified as “qualifying income” as such term is defined in §7704(d) of the Internal Revenue Code of 1986, as amended, or the Code. 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 ii21/%,
as applied to USD Rail LP’s taxable loss of $i0.1 million for the three months ended June 30, 2019, and $i0.1
million and $i0.2 million for thesix months ended June 30, 2020 and 2019, respectively. USD Rail LP had no significant income or loss for the three months ended June 30, 2020.
Foreign
Income Taxes
Our Canadian operations are conducted through entities that are subject to Canadian federal and Alberta provincial income taxes. The Canadian federal income tax on business income is currently 15%. In June 2019, the Canadian province of Alberta enacted a tax rate decrease that reduces the tax rate on business income from the previous rate of 12% to an ultimate rate of 8% effective for 2022. The reduction in the tax rate on business income is phased in over three years beginning with a reduction to a rate of 11% effective July 1, 2019, with further reductions of 1% in each successive year until it reaches 8% on January 1, 2022. As a result, the tax rate on business income for Alberta businesses in 2020 is 10%.
We recognize income tax expense in our consolidated financial
statements based upon enacted rates in effect for the periods presented. As such for the three and six months ended June 30, 2020, income tax expense for our Canadian operations is determined based upon the combined federal and provincial income tax rate of i25%, representing a 15% federal income tax rate and a 10% provincial income tax rate. For the three and six months ended June 30, 2019, income tax expense of our Canadian operations was determined based on the combined
federal and provincial income tax rate of i26.5%. The combined income tax rate of 23%, representing a 15% federal income tax rate and an 8% provincial income tax rate, was used to compute the deferred income tax benefit, representing the impact of temporary differences that are expected to reverse in the future.
CARES Act
On March 27, 2020, the CARES Act was signed into law. The CARES Act is an emergency economic stimulus package enacted
in response to the coronavirus outbreak which, among other measures, contains numerous income tax provisions. Some of these tax provisions are expected to be effective retroactively for tax years ending before the date of enactment. For us, the most significant change included in the CARES Act was the impact to U.S. net operating loss carryback provisions. U.S. net operating losses incurred in tax years 2018, 2019, or 2020 can now be carried back to the preceding five tax years and may be used to fully offset taxable income (i.e. they are not subject to the 80 percent net income offset limitation of Section 172 of the Code).
As a result of these CARES Act changes, for the three and six months ended June 30, 2020 we recognized a current tax benefit of $i13 thousand
and $i530 thousand, respectively, for a claimable tax refund by carrying back U.S. net operating losses incurred in 2018, 2019, and the first half of 2020. We also recognized a one-time deferred tax expense of $i46 thousand
in the first quarter of 2020 due to the net effect of utilizing all U.S. net operating loss deferred tax assets and releasing the corresponding U.S. valuation allowance as of December 31, 2019. We expect to recognize an additional tax benefit in 2020 due to anticipated taxable losses. The tax impacts of the CARES Act were computed with the best available information, and will be adjusted after the 2020 U.S. tax return is finalized. However, we do not expect these adjustments to have a material change to the tax provision in future periods.
30
Estimated Annual Effective Income Tax Rate
i
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:
Income tax expense (benefit) at the U.S. federal statutory rate
$
i289
i21
%
$
i226
i21
%
$
(i6,912)
i21
%
$
i518
i21
%
Amount
attributable to partnership not subject to income tax
(i119)
(i9)
%
(i107)
(i10)
%
i7,034
(i21)
%
(i372)
(i15)
%
Foreign
income tax rate differential
i16
i1
%
i40
i4
%
i26
i—
%
i63
i3
%
Other
- CARES Act
(i8)
(i1)
%
(i53)
(i5)
%
(i212)
i—
%
(i53)
(i2)
%
State
income tax expense
i10
i1
%
i5
i1
%
i19
i—
%
i8
i—
%
Change
in valuation allowance
i—
i—
%
i17
i2
%
(i274)
i1
%
i34
i1
%
Provision
for (benefit from) income taxes
$
i188
i13
%
$
i128
i13
%
$
(i319)
i1
%
$
i198
i8
%
/i
We
determined our year-to-date 2020 provision for income taxes using an estimated annual effective income tax rate of i1% on a consolidated basis for fiscal year 2020. This rate incorporates the applicable income tax rates of the various domestic and foreign tax jurisdictions to which we are subject.
Canadian
federal and provincial income tax expense
i380
i277
i733
i593
Total
current income tax expense
i377
i282
i222
i601
Deferred
income tax expense (benefit):
U.S. federal income tax expense (benefit)
(i16)
i—
i31
i—
Canadian
federal and provincial income tax benefit
(i173)
(i154)
(i572)
(i403)
Total
change in deferred income tax benefit
(i189)
(i154)
(i541)
(i403)
Provision
for (benefit from) income taxes
$
i188
$
i128
$
(i319)
$
i198
/
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. Our deferred income tax assets are included in “Other non-current assets” and deferred income tax liabilities are
31
included in “Deferred income tax liabilities, net” on our consolidated balance sheets. iThe
major components of our deferred income tax assets and liabilities associated with our operations were as follows as of the dates indicated:
We
had ino loss carryforwards for U.S. federal tax purposes remaining at June 30, 2020. We had loss carryforwards of $i1.5 million
remaining as of December 31, 2019. We had loss carryforwards for Canadian tax purposes of $i4.2 million and $i4.3 million as of
June 30, 2020 and December 31, 2019, respectively. A portion of our Canadian loss carryforward is for capital items that do not expire under currently enacted Canadian tax law, while $i1.0 million of the carryforward amount relates to Canadian operating losses that will expire in 2034.
We are subject to examination by the taxing authorities for the
years ended December 31, 2019, 2018 and 2017. We did iino/t
have any unrecognized income tax benefits or any income tax reserves for uncertain tax positions as of June 30, 2020 and December 31, 2019.
Our net income, or loss, and cash flows are subject to fluctuations resulting from changes in interest rates on our variable rate debt obligations and from changes in foreign currency exchange rates, particularly with respect to the U.S. dollar and the Canadian dollar. In limited circumstances, we may also hold long positions in the commodities we handle on behalf of our customers, which exposes us to commodity price risk. We use derivative
32
financial instruments, including futures, forwards, swaps, options and other financial instruments with similar characteristics, to manage the risks associated with market fluctuations in interest rates, foreign currency exchange
rates and commodity prices, as well as to reduce volatility in our cash flows. We have not historically designated, nor do we expect to designate, our derivative financial instruments as hedges of the underlying risk exposure. All of our financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into for speculative purposes.
Interest Rate Derivatives
We use interest rate derivative financial instruments to partially mitigate our exposure to interest rate fluctuations on our variable rate debt. Under our Credit Agreement, one-month LIBOR is used as the index rate for the interest we are charged on amounts borrowed under our Revolving Credit Facility. Effective November 2017, we entered into a five-year interest rate collar contract
with a $i100 million notional value. The collar establishes a range where we will pay the counterparty if the one-month Overnight Index Swap, or OIS, falls below the established floor rate of i1.70%, and the counterparty
will pay us if the one-month OIS rate exceeds the established ceiling rate of i2.50%. 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 predetermined ceiling or floor rate. Prior to February 2019, our interest rate collar contract discussed above was based on one-month LIBOR, which
is being phased out by financial institutions in the United States.
Derivative Positions
i
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:
We
have not designated our derivative financial instruments as hedges of our interest rate exposure. As a result, changes in the fair value of these derivatives are recorded as “Loss associated with derivative instruments” in our consolidated statements of operations. The gains or losses associated with changes in the fair value of our derivative contracts do not affect our cash flows until the underlying contract is settled by making or receiving a payment to or from the counterparty. iIn
connection with our derivative activities, we recognized the following amounts during the periods presented:
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.
33
i
The following table presents summarized information about the fair values of our outstanding interest rate contracts
for the periods indicated:
We
record the fair market value of our derivative financial instruments in our consolidated balance sheets as current and non-current assets or liabilities on a net basis by counterparty. The terms of the International Swaps and Derivatives Association Master Agreement, which governs our financial contracts, include master netting agreements that allow the parties to our derivative contracts to elect net settlement in respect of all transactions under the agreements. iiThe
effect of the rights of offset are presented in the tables below as of the dates indicated./
Our common units represent and subordinated units represented limited partner interests in us. The holders of common units are and subordinated units were entitled to participate in partnership distributions and to exercise the rights and privileges available to limited partners under our partnership agreement.
In February 2019, pursuant to the terms set forth in our partnership agreement, the fourth and final vesting tranche of i38,750 Class A units vested and was converted into our common units. We determined that each vested Class A unit would receive ione
common unit at conversion based upon our distributions paid for the ifour preceding quarters. As a result, the final tranche of i38,750
Class A units were converted into i38,750 common units and ino Class A units remain outstanding at June 30, 2020.
Our Class A units were limited partner interests in us that entitled the holders to nonforfeitable distributions that were equivalent to the distributions paid with respect to our common units (excluding any arrearages of unpaid minimum quarterly distributions from prior quarters) and, as a result, were considered participating securities. Our Class A units did not have voting rights and vested in ifour 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
34
feature, which, upon vesting, provided for the conversion of the Class A units into common units based on a conversion factor that was tied to the level of our distribution growth for the applicable year. The conversion factor was i1.00
for the first vesting tranche, i1.50 for the second vesting tranche, i1.00 for the third vesting tranche and i1.00
for the fourth vesting tranche.
All of our subordinated units converted into common units on a ione-for-one basis in separate sequential tranches. Each tranche was comprised of i20.0%
of the subordinated units issued in conjunction with our IPO. Each separate tranche was eligible to convert on or after December 31, 2015 (but no more frequently than once in any twelve-month period), provided on such date: (i) distributions of available cash from operating surplus on each of the outstanding common units, Class A units, subordinated units and general partner units equaled or exceeded $i1.15 per unit (the annualized minimum quarterly distribution)
for the ifour quarter period immediately preceding that date; (ii) the adjusted operating surplus generated during the ifour
quarter period immediately preceding that date equaled or exceeded the sum of $i1.15 per unit (the annualized minimum quarterly distribution) on all of the common units, Class A units, subordinated units and general partner units outstanding during that period on a fully diluted basis; and (iii) there were no arrearages in the payment of the minimum quarterly distribution on our common units. For each successive tranche, the ifour
quarter period specified in clauses (i) and (ii) above must have commenced after the ifour quarter period applicable to any prior tranche of subordinated units. In February 2020, pursuant to the terms set forth in our partnership agreement, we converted the fifth and final tranche of i2,092,709
of our subordinated units into common units upon satisfaction of the conditions established for conversion.
Our partnership agreement provides that, while any subordinated units remained outstanding, holders of our common units had the right to receive distributions of available cash from operating surplus each quarter in an amount equal to our minimum quarterly distribution per unit, plus (with respect to the common units) any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus were made on the subordinated units.
Pursuant to the terms of the USD Partners LP Amended and Restated 2014 Long-Term Incentive Plan, which we refer to as the A/R LTIP, our phantom unit awards, or Phantom Units, granted to directors and employees of our general partner and its affiliates,
which are classified as equity, are converted into our common units upon vesting. Equity-classified Phantom Units totalingi518,475 vested during the first six months in 2020, of which i339,073
were converted into our common units after i179,402 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 $i0.2875 per unit ($i1.15
per unit on an annualized basis) on all of our units to the extent we have sufficient available cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. The board of directors of our general partner may change our distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis. The amount of distributions we pay under our cash distribution policy and the decision to make any distribution are determined by our general partner. For the quarter ended June 30, 2020, the board of directors of our general partner determined that we had sufficient available cash after the establishment of cash reserves and the payment of our expenses to distribute $i0.111
per unit on all of our units.
18. iUNIT BASED COMPENSATION
Class A units
Our Class A units vested annually over a four year period when established distribution growth target thresholds were met during each
year of the four year vesting period. In February 2019, pursuant to the terms set forth in our partnership agreement, the fourth and final vesting tranche of i38,750 Class A units vested based upon our distributions paid for the ifour
preceding quarters and were converted on a basis of ione common unit for each
35
Class A unit. As a result, we converted i38,750
Class A units into i38,750 common units in 2019 and ino Class A units remain outstanding at June 30, 2020.
iWe recognized compensation expense in “Selling, general and administrative” with regard to our Class A units for the following amounts during the periods presented:
For
the three and six months ended June 30, 2020 and 2019 we had iiiino///
forfeitures of Class A units. We elected to account for actual forfeitures as they occurred rather than applying an estimated forfeiture rate when determining compensation expense.
Each holder of a Class A unit was entitled to nonforfeitable cash distributions equal to the product of the number of Class A units outstanding for the participant and the cash distribution per unit paid to our common unitholders. These distributions were included in “Distributions” as presented in our consolidated statements of cash flows and our consolidated statements of partners’ capital. However, any distributions paid on Class A units that were forfeited were reclassified to unit based compensation expense when we determined that the Class A units were not expected to vest. We recognized iiiino///
compensation expense for the three and six months ended June 30, 2020 or 2019, for distributions paid on Class A units that were forfeited.
Long-term Incentive Plan
In 2020 and 2019, the board of directors of our general partner, acting in its capacity as our general partner, approved the grant of i694,140
and i633,637 Phantom Units, respectively, to directors and employees of our general partner and its affiliates under our A/R LTIP. At June 30, 2020, we had i943,277
Phantom Units remaining available for issuance. The Phantom Units are subject to all of the terms and conditions of the A/R LTIP and the Phantom Unit award agreements, which are collectively referred to as the Award Agreements. Award amounts for each of the grants are generally determined by reference to a specified dollar amount based on an allocation formula which included a percentage multiplier of the grantee’s base salary, among other factors, converted to a number of units based on the closing price of ione of our
common units preceding the grant date, as determined by the board of directors of our general partner and quoted on the NYSE.
Phantom Unit awards generally represent rights to receive our common units upon vesting. However, with respect to the awards granted to directors and employees of our general partner and its affiliates domiciled in Canada, for each Phantom Unit that vests, a participant is entitled to receive cash for an amount equivalent to the closing market price of ione
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
36
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.
i
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
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
37
of operations and recognizing a liability in “Other current liabilities” in our consolidated balance sheets. With respect to the Phantom Units granted to consultants, independent
directors and employees of our general partner and its affiliates domiciled in the United States, we amortize the initial grant date fair value over the requisite service period using the straight-line method with a charge to compensation expense in “Selling, general and administrative” in our consolidated statements of operations, with an offset to common units within the Partners’ Capital section of our consolidated balance sheet.
For the three months ended June 30, 2020 and 2019, we recognized $ii1.6/
million and for the six months ended June 30, 2020 and 2019 we recognized $i3.3 million and $i3.0
million, respectively, of compensation expense associated with outstanding Phantom Units. As of June 30, 2020, we have unrecognized compensation expense associated with our outstanding Phantom Units totaling $i12.9 million, which we expect to recognize over a weighted average period of i2.68
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.
i
We made payments to holders of the Phantom Units pursuant to the associated DERs we granted to them under the Award Agreements as follows:
(1) We
had no reclassifications to unit based compensation expense for DERs paid in relation to Phantom Units that have been forfeited for the three months ended June 30, 2020 and 2019. We reclassified $i57 thousand and $i7
thousand for the six months ended June 30, 2020 and 2019, respectively, for forfeitures.
/
19. iSUPPLEMENTAL
CASH FLOW INFORMATION
i
The following table provides supplemental cash flow information for the periods indicated:
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:
We recorded $ii2.8/
million of right-of-use lease assets and the associated liabilities on our consolidated balance sheet as of June 30, 2020, representing non-cash activities resulting from new or extended lease agreements. See Note 7. Leases for further discussion.
Non-cash Investing Activities
For the six months ended June 30, 2020 and 2019, we had non-cash investing activities for capital expenditures for property, plant and equipment that were financed through accounts payable and accrued expenses as presented in the table below for the periods indicated:
Property, plant and equipment financed through accounts payable accrued liabilities
$
(i252)
$
i2,316
20. iSUBSEQUENT
EVENTS
Distribution to Partners
On July 23, 2020, the board of directors of USD Partners GP LLC, acting in its capacity as our general partner, declared a quarterly cash distribution payable of $i0.111 per unit, or $i0.444
per unit on an annualized basis, for the three months ended June 30, 2020. Consistent with the distribution declared for the first quarter of 2020, the distribution represents a decrease of $i0.259 per unit, or i70.0%
below the distribution with respect to the fourth quarter of 2019. The distribution will be paid on August 14, 2020, to unitholders of record at the close of business on August 4, 2020. The distribution will include payment of $i1.7 million to our public common unitholders, $i1.3
million to USDG as a holder of our common units and $i51 thousand to USD Partners GP LLC as a holder of the general partner interest.
Revolving Credit Facility Activity
Subsequent to June 30, 2020, we made additional repayments of $i3.0
million under the terms of our existing $i385 million Revolving Credit Facility. The Credit Agreement provides for borrowings of up to $i385
million, expandable to $i500.0 million, with lender consent, and expires on November 2, 2022. As of August 3, 2020, we had amounts outstanding of $i215.0
million under the Revolving Credit Facility.
39
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with the unaudited consolidated financial statements and accompanying notes in “Item 1. Financial Statements” contained herein and our audited consolidated financial statements and accompanying notes included in “Item 8. Financial Statements and Supplementary
Data” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019. Among other things, those consolidated financial statements include more detailed information regarding the basis of presentation for the following discussion and analysis. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those discussed below. Factors that could cause or contribute to such differences include, but are not limited to, those identified below and those discussed in “Item 1A. Risk Factors” included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019, our Quarterly Report on Form 10-Q for the quarter ended March
31, 2020, and subsequent Quarterly Reports on Form 10-Q. Please also read the “Cautionary Note Regarding Forward-Looking Statements” following the table of contents in this Report.
We denote amounts denominated in Canadian dollars with “C$” immediately prior to the stated amount.
Overview
We are a fee-based, growth-oriented master limited partnership formed by our sponsor, USD, to acquire, develop and operate midstream infrastructure and complementary logistics
solutions for crude oil, biofuels and other energy-related products. We generate substantially all of our operating cash flows from multi-year, take-or-pay contracts with primarily investment grade customers, including major integrated oil companies, refiners and marketers. Our network of crude oil terminals facilitates the transportation of heavy crude oil from Western Canada to key demand centers across North America. Our operations include railcar loading and unloading, storage and blending in onsite tanks, inbound and outbound pipeline connectivity, truck transloading, as well as other related logistics services. We also provide our customers with leased railcars and fleet services to facilitate the transportation of liquid hydrocarbons and biofuels by rail.
We generally do not take ownership of the products that we handle nor do
we receive any payments from our customers based on the value of such products. We may on occasion enter into buy-sell arrangements in which we take temporary title to commodities while in our terminals. We expect any such arrangements to be at fixed prices where we do not take any exposure to changes in commodity prices.
We believe rail will continue as an important transportation option for energy producers, refiners and marketers due to its unique advantages relative to other transportation means. Specifically, rail transportation of energy-related products provides flexible access to key demand centers on a relatively low fixed-cost basis with faster physical delivery, while preserving the specific quality of customer products over long distances.
USDG, a wholly-owned subsidiary of USD, and the sole owner of our general partner, is engaged in designing, developing, owning, and
managing large-scale multi-modal logistics centers and energy-related infrastructure across North America. USDG’s solutions create flexible market access for customers in significant growth areas and key demand centers, including Western Canada, the U.S. Gulf Coast and Mexico. Among other projects, USDG is currently pursuing the development of a premier energy logistics terminal on the Houston Ship Channel with capacity for substantial tank storage, multiple docks (including barge and deepwater), inbound and outbound pipeline connectivity, as well as a rail terminal with unit train capabilities. USDG completed an expansion project in January 2019 at the Partnership’s Hardisty terminal, referred to herein as Hardisty South, which added one and one-half 120-railcar unit trains of transloading capacity per day, or approximately 112,500 barrels per day, or bpd.
USD, along with its partner, Gibson, is also pursuing long-term solutions
to transport heavier grades of crude oil produced in Western Canada through the construction of a Diluent Recovery Unit, or DRU, at the Hardisty terminal, which we expect will be placed into service in the second quarter of 2021. As of the date of this report, USD has secured the necessary financing, obtained all material permits and entered into fixed-price construction contracts regarding the construction of the project. USD’s patented DRU technology separates the diluent that has
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been added to the raw bitumen in the production process which meets two important market needs – it returns the recovered diluent for reuse in the Alberta market,
reducing delivered costs for diluent, and it creates DRUbit™, a proprietary heavy Canadian crude oil specifically designed for rail transportation. DRUbit™ is crude oil or bitumen that has been returned to a more concentrated, viscous state that is classified as a non-hazardous, non-flammable commodity when transported by rail in Canada and the U.S. DRUbit™ is a market access solution that will satisfy demand for heavy Canadian crude oil on the U.S. Gulf Coast and in other markets at a cost that is economically competitive to the crude oil that is transported by pipeline today. In addition, USD is constructing a new destination terminal in Port Arthur, Texas for the DRUbit™ that will be transloaded at our Hardisty origination terminal.
Recent Developments
Market Update
Substantially all of our operating cash flows are generated from take-or-pay
contracts and, as a result, are not directly related to actual throughput volumes at our crude oil terminals. Throughput volumes at our terminals are primarily influenced by the difference in price between Western Canadian Select, or WCS, and other grades of crude oil, commonly referred to as spreads, rather than absolute price levels. WCS spreads are influenced by several market factors, including the availability of supplies relative to the level of demand from refiners and other end users, the price and availability of alternative grades of crude oil, the availability of takeaway capacity, as well as transportation costs from supply areas to demand centers.
COVID-19 and Crude Oil Pricing Environment Update
In December 2019, a novel coronavirus disease (“COVID-19”) was reported and
on March 11, 2020, the World Health Organization declared that the spread of COVID-19 qualified as a global pandemic. The COVID-19 pandemic has adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the pandemic has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement worldwide. As a result, there has been a significant reduction in demand for and prices of crude oil, natural gas and natural gas liquids. In addition, in March 2020, members of the Organization of the Petroleum Exporting Countries, or OPEC+, failed to agree on oil production levels, which led to a substantial decline in oil prices and an increasingly volatile market. In March and April 2020, domestic oil and natural gas producers announced dramatic reductions or curtailments of their development programs,
as well as plans to shut-in production. In April 2020, even though OPEC+ announced that it had reached an agreement to cut production by 9.7 million barrels per day, or Mmbpd, oil prices did not meaningfully increase. As concerns about domestic oil storage capacity being fully subscribed in May 2020 grew, on April 20, 2020, WTI oil futures priced at historic lows. While COVID-19 is still a global pandemic, parts of the world are starting to recover and some economies are starting to reopen. However, there still remains considerable uncertainty, as certain jurisdictions have begun re-opening only to return to restrictions in the face of increases in new COVID-19 cases.
These events have negatively impacted our customers and thereby limited our ability to grow our business. For example, as a result of the overall downturn in the crude market and the decline in the demand for petroleum
products, in March 2020, we tested the goodwill associated with our Casper terminal for impairment, which resulted in an impairment loss. Declining demand for petroleum products could lead to delays or reductions of expected throughput levels and changes in expectations for current contracts in place at the Casper terminal. Additionally, declining demand for export capacity by customers of our Hardisty terminal resulted in a significant decrease in the average daily terminal throughput during the second quarter of 2020. Refer to Part I. Item 1. Financial Statements, Note 8. Goodwill and intangible assets of this Report for further discussion of the impairment loss at the Casper terminal.
Given
the current uncertainty in the energy industry, the board of directors of our general partner elected to reduce the quarterly distribution per unit declared for the first and second quarters of 2020 by 70% as compared to the distribution for the fourth quarter of 2019 as a proactive measure to strengthen our financial position and redeploy certain free cash flow to de-lever. During the second quarter of 2020, we repaid $6 million of the
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outstanding balance of our revolving credit facility. Refer to Liquidity and Capital Resources — Cash Requirement — Distributions for further discussion.
Recent efforts to reopen the economy have led to increases
in the demand for crude oil and petroleum products, which resulted in a modest recovery in oil prices as compared to the lower price levels that were present at the end of the first quarter and during the second quarter of 2020. As a result, as of the beginning of July 2020, producers in Canada and the U.S. have stated that they will start to bring back some of the temporary shut-in production from the first quarter of 2020. Additionally, OPEC+ agreed in July 2020 to taper oil production cuts, which will scale back production cuts from 9.7 Mmbpd to 7.7 Mmbpd between August 2020 and January 2021. We believe that if the increases in demand continue, additional producers in Canada and the U.S. will likely announce that they are bringing back further production throughout the end of the year. However, there still remains significant uncertainty given the unprecedented and evolving nature of the COVID-19 pandemic, and the extent and duration of any increases in demand and
price levels are difficult to predict, if such increases occur at all. As demand and prices increase, the need for crude by rail export capacity from our terminals is also expected to increase.
The broader implications of COVID-19 and lower oil and natural gas prices on our results of operations and overall financial performance remain uncertain. We have implemented protocols and procedures designed to manage risk associated with the direct impact of COVID-19 on our operations. We have not experienced material disruptions to our operations or material increase in our cash expenses. Currently, we expect to have sufficient liquidity to operate our business and remain in compliance with the financial covenants under our credit agreement for at least the next twelve months and we do not expect our customers to terminate existing contracts.
However, if the pandemic continues and/or oil prices decline or remain at relatively low levels, these conditions may have an adverse effect on the Company’s results of future operations, financial position, and liquidity in fiscal year 2020. Given the unprecedented and evolving nature of the COVID-19 pandemic and the state of the commodity markets, we continue to actively monitor their impact on our operations and financial condition. Refer to Item 1A. Risk Factors in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 for further discussion of certain risks relating to the COVID-19 pandemic.
Impact of Current Market Events
The WCS to West Texas Intermediate, or WTI, crude oil spread
narrowed to between $2-$19 per barrel during the second quarter of 2020, as a result of the decline in global oil supply described in COVID-19 and Crude Oil Pricing Environment Update discussed above. The narrowing of the WCS to WTI crude oil spread resulted in a decrease in the utilization of our rail terminals by our customers in the second quarter of 2020 and to date in the third quarter of 2020.
Apportionment levels on the primary heavy crude oil pipelines of the largest export pipeline system from Western Canada to the U.S. averaged approximately 50% and apportionment on the light crude oil pipelines on the system averaged approximately 8% in the first quarter of 2020 (representing the percentage of barrels nominated that were not shipped due to pipeline capacity constraints). In the second quarter of 2020, apportionment levels on the primary heavy crude oil pipelines of the
largest export pipeline system from Western Canada to the U.S. decreased to an average of approximately 13%. Apportionment levels have started to increase modestly as of July 2020 and are expected to continue to increase with the increase in demand and lack of available pipeline takeaway capacity. Inventory levels in Western Canada at the end of the second quarter of 2020 have decreased by approximately 30% compared to the levels that existed at the end of 2019. However, in the second half of 2020 and as a result of the recent events, inventory levels are expected to increase. There still remains significant uncertainty given the unprecedented and evolving nature of the COVID-19 pandemic, and the extent and duration of any increases in apportionment or inventory levels are difficult to predict, if such increases occur at all.
Future WCS to WTI spreads published by Bloomberg through 2024 average approximately $15 per barrel,
as a result of the decline in global oil demand previously discussed. Given the current market conditions, as stated above, and as pipeline outages continue and uncertainty remains, supply is expected to be higher than pipeline takeaway capacity, with pipeline apportionment levels trending higher than current levels. As this occurs, crude by rail volumes from Western Canada to the United States are expected to increase, possibly in the latter part of 2020.
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Additionally, projects to increase pipeline export capacity have continued to experience significant regulatory delays. For example, the anticipated in-service date of Enbridge’s Line 3 Replacement project to upgrade and expand an existing pipeline delivering Western Canadian crude
to U.S. markets in the second half of 2020 is now uncertain, due to regulatory issues on the U.S. portion of the pipeline. In March 2020, the government of Alberta announced that it had reached an agreement to invest $1.5 billion in equity investment in the Keystone XL crude oil pipeline project in 2020 followed by a $6 billion loan guarantee in 2021 in order to enable the completion of the project by 2023. However, in April 2020, a U.S. judge cancelled a key permit needed for the construction of the Keystone XL crude oil pipeline. The construction of the Keystone XL pipeline is now on hold until at least 2021. In July 2020, the White House issued a permit to expand the cross-border shipping limit on the existing Keystone pipeline to 760,000 bpd from 590,000 bpd. TC Energy plans to expand the pipeline by 50,000 bpd in 2021 with the use of drag reducing agent, or DRA. The additional capacity will be assessed in the future and may require additional capital expenditures.
This decision comes after a U.S judge cancelled a key permit needed for construction of Keystone XL. Current pipeline operators are also facing legal challenges to keep their pipelines in operation. Enbridge Line 5 is currently operating without the East Leg portion of the pipeline, therefore decreasing natural gas liquids, or NGL, and crude oil take-away in Alberta, Canada. The Dakota Access Pipeline is in the middle of a legal dispute to determine whether the pipeline can continue to operate and if a full environmental impact statement, or EIS, is required. As pipeline export capacity challenges remain, crude by rail exports will remain a valuable egress solution.
As producers in Western Canada start to bring back production, we expect demand for and utilization of our rail terminals will increase as produced barrels will need to be exported, in the event relative price differentials
make it economic to do so, which continues to remain uncertain and difficult to predict. In the long-term, we expect demand for rail capacity at our terminals to increase over the next several years and potentially longer if proposed pipeline developments do not meet currently planned timelines and regulatory or other challenges persist. Our Hardisty and Casper terminals, with established capacity and scalable designs, are well-positioned as strategic outlets to meet growing takeaway needs as Western Canadian crude oil supplies continue to exceed available pipeline takeaway capacity. Also, USD is pursuing long-term solutions to transport heavier grades of crude oil produced in Western Canada through the construction of a Diluent Recovery Unit, or DRU, at the Hardisty terminal, which we expect will be placed into service in the second quarter of 2021. This project is expected to maximize benefits to producers, refiners and railroads. Additionally, we believe our Stroud
terminal provides an advantageous rail destination for Western Canadian crude oil given the optionality provided by its connectivity to the Cushing hub and multiple refining centers across the United States. Rail also generally provides a greater ability to preserve the specific quality of a customer’s product relative to pipelines, providing value to a producer or refiner. We expect these advantages, including our recently established origin-to-destination capabilities, to continue to result in long-term contract extensions and expansion opportunities across our terminal network.
Alberta Government Update
In December 2018, the Alberta Government announced that it would curtail crude oil and bitumen production by 325,000 bpd beginning January 1,
2019, to an allowed production level of 3.56 million bpd. The Alberta Government’s objective was to reduce inventory levels to a targeted level to ensure more economical prices for WCS. In late August 2019, the Alberta Government announced changes to the curtailment policy including extending the curtailment end date to December 31, 2020, with possible earlier termination. To date in 2020, the allowed production level under the curtailment has remained at 3.81 million bpd.
In late October 2019, the Alberta Government announced a special production allowance, whereby beginning with the December 2019 production month, producers will be allowed to produce above their curtailment order, as long as this extra production is shipped out of Alberta through additional rail capacity.
To address pipeline capacity constraints from Western
Canada and to increase Alberta’s overall export capacity, the Alberta Government also announced an initiative to increase rail capacity in order to export WCS to markets with more economical returns. This initiative included leasing approximately 4,400 new rail cars to move up to 120,000 bpd of crude oil by 2020, as well as agreements for terminalling services (including an agreement with USDG) and rail transportation contracts. In June 2019, the Alberta Government announced that they engaged CIBC Capital Markets to help oversee the divestment of this crude-by-rail program and its transition to the private
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sector. In February 2020, the Alberta
Government announced that it has agreed to divest of its contracts to move additional crude by rail to market, but did not release any other details as the agreements are still being finalized.
How We Generate Revenue
We conduct our business through two distinct reporting segments: Terminalling services and Fleet services. We have established these reporting segments as strategic business units to facilitate the achievement of our long-term objectives, to assist in resource allocation decisions and to assess operational performance.
Terminalling Services
The
terminalling services segment includes a network of strategically-located terminals that provide customers with railcar loading and/or unloading capacity, as well as related logistics services, for crude oil and biofuels. Substantially all of our cash flows are generated under multi-year, take-or-pay terminal services agreements that include minimum monthly commitment fees. We generally have no direct commodity price exposure, although fluctuating commodity prices could indirectly influence our activities and results of operations over the long term. We may on occasion enter into buy-sell arrangements in which we take temporary title to commodities while in our terminals. We expect any such agreements to be at fixed prices where we do not take commodity price exposure.
Our Hardisty terminal is an origination terminal where we load into railcars various grades of Canadian crude oil received from Gibson’s Hardisty storage terminal.
Our Hardisty terminal can load up to two 120-railcar unit trains per day and consists of a fixed loading rack with approximately 30 railcar loading positions, a unit train staging area and loop tracks capable of holding five unit trains simultaneously.
Our Stroud terminal is a crude oil destination terminal in Stroud, Oklahoma, which we use to facilitate rail-to-pipeline shipments of crude oil from our Hardisty terminal to the crude oil storage hub located in Cushing, Oklahoma. The Stroud terminal includes 76-acres with current unit train unloading capacity of approximately 50,000 Bpd, two onsite tanks with 140,000 barrels of capacity, one truck bay, and a 12-inch diameter, 17-mile pipeline with a direct connection to the crude oil storage hub in Cushing Oklahoma. Our Stroud terminal was purchased in June 2017 and commenced operations in October 2017.
Our Casper terminal is a crude
oil storage, blending and railcar loading terminal. The terminal currently offers six storage tanks with 900,000 barrels of total capacity, unit train-capable railcar loading capacity in excess of 100,000 bpd, as well as truck transloading capacity. Our Casper terminal is supplied with multiple grades of Canadian crude oil through a direct connection with the Express Pipeline. Additionally, the Casper terminal has a connection from the Platte terminal, where it has access to other pipelines and can receive other grades of crude oil, including locally sourced Wyoming sour crude oil. The Casper terminal can also receive volumes through one truck unloading station and is also equipped with one truck loading station. Additionally, to supplement the rail loading options from the terminal, we constructed an outbound pipeline connection from the Casper terminal to the nearby Platte terminal located at the termination point of the Express pipeline that was placed into service
in December 2019.
Our West Colton terminal is a unit train-capable destination terminal that can transload up to 13,000 bpd of ethanol received from producers by rail onto trucks to meet local demand in the San Bernardino and Riverside County-Inland Empire region of Southern California. The West Colton terminal has 20 railcar offloading positions and three truck loading positions.
Fleet Services
We provide our customers with leased railcars and fleet services related to the transportation of liquid hydrocarbons and biofuels by rail on multi-year, take-or-pay terms under master fleet services agreements for initial periods ranging from five to nine years. We do not own any railcars. As of June 30, 2020, our railcar fleet consisted of 1,432 railcars, which we leased from various railcar manufacturers
and financial entities, including 1,058 coiled and insulated, or C&I, railcars. We have assigned certain payment and performance obligations under the leases and master fleet service agreements for 1,232 of the railcars to other parties, but we have retained certain rights and
44
obligations with respect to the servicing of these railcars. The weighted average remaining contract life on our railcar fleet is 2.0 years as of June 30, 2020. At the end of June 2020, leases on 250 railcars were assigned directly to one of our customers. We do not expect this transfer to have a material impact on
our business, cash flows or results of operations.
Under the master fleet services agreements, we provide customers with railcar-specific fleet services, which may include, among other things, the provision of relevant administrative and billing services, the repair and maintenance of railcars in accordance with standard industry practice and applicable law, the management and tracking of the movement of railcars, the regulatory and administrative reporting and compliance as required in connection with the movement of railcars, and the negotiation for and sourcing of railcars. Our customers typically pay us and our assignees monthly fees per railcar for these services, which include a component for fleet services.
Historically, we contracted with railroads on behalf of some of our customers to arrange for the movement of railcars from our terminals to the destinations selected by
our customers. We were the contracting party with the railroads for those shipments and were responsible to the railroads for the related fees charged by the railroads, for which we were reimbursed by our customers. Both the fees charged by the railroads to us and the reimbursement of these fees by our customers are included in our consolidated statements of operations in the revenues and operating costs line items entitled “Freight and other reimbursables.”
How We Evaluate Our Operations
Our management uses a variety of financial and operating metrics to evaluate our operations. When we evaluate our consolidated operations and related liquidity, we consider these metrics to be significant factors in assessing
our ability to generate cash and pay distributions and include: (i) Adjusted EBITDA and DCF; (ii) operating costs; and (iii) volumes. We define Adjusted EBITDA and DCF below. When evaluating our operations at the segment level, we evaluate using Segment Adjusted EBITDA. Refer to Part I, Item 8. Financial Statements and Supplementary Data, Note 14. Segment Reporting.
Adjusted EBITDA and Distributable Cash Flow
We define Adjusted EBITDA as “Net cash provided by operating activities” adjusted for changes in working capital items, interest, income taxes, foreign currency transaction gains and losses, and other items which do not affect the underlying cash flows produced by our businesses. Adjusted EBITDA is a non-GAAP,
supplemental financial measure used by management and external users of our financial statements, such as investors and commercial banks, to assess:
•our liquidity and the ability of our business to produce sufficient cash flow to make distributions to our unitholders; and
•our ability to incur and service debt and fund capital expenditures.
We define Distributable Cash Flow, or DCF, as Adjusted EBITDA less net cash paid for interest, income taxes and maintenance capital expenditures. DCF does not reflect changes in working capital balances. DCF is a non-GAAP, supplemental financial measure used by management and by external users of our financial statements, such as investors and commercial banks, to assess:
•the amount
of cash available for making distributions to our unitholders;
•the excess cash flow being retained for use in enhancing our existing business; and
•the sustainability of our current distribution rate per unit.
We believe that the presentation of Adjusted EBITDA and DCF in this Report provides information that enhances an investor’s understanding of our ability to generate cash for payment of distributions and other purposes. The GAAP measure most directly comparable to Adjusted EBITDA and DCF is “Net cash provided by operating activities.” Adjusted EBITDA and DCF should not be considered alternatives to “Net cash provided by operating activities” or any other measure of liquidity presented in accordance with GAAP. Adjusted EBITDA and DCF exclude some, but not all, items that
affect “Net cash provided by operating activities,” and these measures may vary
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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:
Reconciliation
of Net cash provided by operating activities to Adjusted EBITDA and Distributable cash flow:
Net cash provided by operating activities
$
5,409
$
9,336
$
17,126
$
19,507
Add
(deduct):
Amortization of deferred financing costs
(207)
(207)
(414)
(657)
Deferred income taxes
189
154
541
403
Changes
in accounts receivable and other assets
334
3,134
2,137
2,298
Changes in accounts payable and accrued expenses
2,130
(1,221)
1,232
(2,009)
Changes
in deferred revenue and other liabilities
213
(2,264)
(2,822)
(2,462)
Interest expense, net
2,253
2,970
4,968
6,150
Provision
for (benefit from) income taxes
188
128
(319)
198
Foreign currency transaction loss (1)
1,150
20
1,058
202
Other
income
—
(25)
—
(42)
Non-cash deferred amounts (2)
1,119
161
1,556
110
Adjusted
EBITDA
12,778
12,186
25,063
23,698
Add (deduct):
Cash paid for income taxes
(116)
(329)
(433)
(607)
Cash
paid for interest
(2,874)
(2,995)
(4,957)
(5,815)
Maintenance capital expenditures
(82)
(45)
(114)
(45)
Distributable
cash flow
$
9,706
$
8,817
$
19,559
$
17,231
(1) Represents foreign exchange transaction amounts associated with activities between our U.S. and Canadian subsidiaries.
(2) Represents
the change in non-cash contract assets and liabilities associated with revenue recognized at blended rates based on tiered rate structures in certain of our customer contracts and deferred revenue associated with deficiency credits that are expected to be used in the future prior to their expiration. Amounts presented are net of the corresponding prepaid Gibson pipeline fee that will be recognized as expense concurrently with the recognition of revenue.
Operating Costs
Our operating costs are comprised primarily of subcontracted rail services, pipeline fees, repairs and maintenance expenses, materials and supplies, utility costs, insurance premiums and lease
costs for facilities and equipment. In addition, our operating expenses include the cost of leasing railcars from third-party railcar suppliers and the shipping fees charged by railroads, which costs are generally passed through to our customers. We expect our expenses to remain relatively stable, but they may fluctuate from period to period depending on the mix of activities performed during a period and the timing of these expenditures. We expect to incur additional operating costs, including subcontracted rail services and pipeline fees, when we handle additional volumes at our terminals.
Our management seeks to maximize the profitability of our operations by effectively managing both our operating and maintenance expenses. As our terminal facilities and related equipment age, we expect to incur regular maintenance expenditures to maintain the operating capabilities of our facilities and equipment in compliance with sound
business practices, our contractual relationships and regulatory requirements for operating these assets. We record these maintenance and other expenses associated with operating our assets in “Operating and maintenance” costs in our consolidated statements of operations.
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Volumes
The amount of Terminalling services revenue we generate depends on minimum customer commitment fees and the throughput volume that we handle at our terminals in excess of those minimum commitments. These volumes are primarily affected by the supply of and demand for crude oil, refined products and biofuels in the markets served directly or indirectly by our assets. Additionally, these volumes are affected
by the spreads between the benchmark prices for these products, which are influenced by, among other things, the available takeaway capacity in those markets. Although customers at our terminals have committed to minimum monthly fees under their terminal services agreements with us, which will generate the majority of our Terminalling services revenue, our results of operations will also be affected by:
•our customers’ utilization of our terminals in excess of their minimum monthly volume commitments;
•our ability to identify and execute accretive acquisitions and commercialize organic expansion projects to capture incremental volumes; and
•our ability to renew contracts with
existing customers, enter into contracts with new customers, increase customer commitments and throughput volumes at our terminals, and provide additional ancillary services at those terminals.
General Trends and Outlook
We expect our business to continue to be affected by the key trends and recent developments discussed in “Item 7. Management’s Discussion and Analysis of Financial Condition—Factors that May Impact Future Results of Operations” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019.
To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results. The unprecedented nature of the COVID-19 pandemic, its impact on world economic conditions and the decline in the oil and natural gas markets have created increased uncertainty with respect to future conditions and our ability to accurately predict future results.
Casper Terminal Customer Contract Expirations and Goodwill Impairment
The final legacy terminalling services agreement at our Casper Terminal expired at the end of August 2019 and was not renewed or extended. We continue to seek other opportunities to enhance the utilization and profitability of the Casper terminal with other producers, refiners and marketers
of crude oil. The revenue provided by the current agreements at our Casper terminal, certain of which contain take-or-pay terms for storage services and variable fees associated with actual throughput volumes and other services, may be less predictable than the revenue historically provided by the legacy contracts, which were based on minimum volume commitments. We have not yet entered into arrangements to replace all of the revenue previously provided by the legacy contracts at the Casper Terminal.
In July 2019, Enbridge Inc. announced a program to increase the capacity of the Express pipeline by up to an additional 50,000 bpd with the use of DRA and pump stations. We anticipate that some of the additional volumes resulting from the increased
capacity on the Express pipeline could be delivered to our Casper terminal, as we believe outbound pipeline connections from the Express pipeline and nearby terminals are at or near full capacity. Our ability to secure additional commercial opportunities and replace the revenue previously generated under the expired contracts may be limited until Enbridge successfully completes its DRA project. In late July 2020, Enbridge announced that it has placed 25,000 bpd of the additional capacity on its Express pipeline into service and plans to place the additional 25,000 bpd into service sometime in 2021.
In Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — General Trends and Outlook — Casper Terminal Customer Contract
Renewals and Expirations in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019, we previously disclosed that we may recognize an impairment of the Casper terminal’s goodwill under certain conditions. In March 2020, in light of the overall downturn in the crude oil market and the decline in the demand for petroleum products, we tested the goodwill associated with our Casper terminal for impairment since such downturn could lead to delays or reductions of expected throughput levels and changes in expectations for current contracts in place at the Casper terminal. As a result of our impairment testing, we recognized an impairment loss of $33.6 million of goodwill associated with our
Factors Affecting the Comparability of Our Financial Results
The comparability of our current financial results in relation to prior periods are affected by the factors described below.
Casper Terminal Customer Contract
Expirations and Goodwill Impairment
Our last legacy terminalling services agreement at our Casper Terminal expired at the end of August 2019 and was not renewed or extended. The expired agreement contributed $9.3 million to our “Terminalling Services” revenue and $6.5 million of Adjusted EBITDA during the twelve months preceding the expiration of the agreement. Furthermore, in March 2020, we tested the goodwill associated with our Casper terminal for impairment due to the overall downturn in the crude market and the decline in the demand for petroleum products, which could lead to delays or reductions of expected throughput levels and changes in expectations for current contracts in place at the Casper terminal. As a result of our impairment testing, we recognized an impairment loss of $33.6 million for the six months ended June
30, 2020.
Income Tax
In June 2019, the Canadian Province of Alberta enacted a tax rate decrease that reduces the tax rate on business income from the previous rate of 12% to an ultimate rate of 8% effective for 2022. The reduction in the tax rate on business income will be phased in over three years beginning with a reduction to an 11% rate effective July 1, 2019, with further reductions of 1% in each successive year until it reaches 8% on January 1, 2022. As a result, the income tax rate on business income for Alberta businesses in 2020 is 10%. The rate in 2019 was 11.5%, representing a blended rate of 12% from January 1, 2019 through June 30, 2019 and 11% from July
1, 2019 through December 31, 2019.
CARES Act
On March 27, 2020, United States legislation referred to as the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”), was signed into law. The CARES Act is an emergency economic stimulus package enacted in response to the coronavirus outbreak which, among other measures, contains numerous income tax provisions. Some of these tax provisions are expected to be effective retroactively for tax years ending before the date of enactment. For us, the most significant change included in the CARES Act was the impact to U.S. net operating loss carryback provisions. U.S. net operating losses incurred in tax years 2018, 2019, or 2020 can now be fully carried back to the preceding five tax years and may be used to fully offset
taxable income (i.e. they are not subject to the 80 percent net income offset limitation of Section 172 of the Code).
As a result of these CARES Act changes, for the three and six months ended June 30, 2020, we recognized a current tax benefit of $i13 thousand and $i530 thousand,
respectively, for a claimable tax refund by carrying back U.S. net operating losses incurred in 2018, 2019, and in the first half of 2020. We also recognized a one-time deferred tax expense of $i46 thousand in the first quarter of 2020 due to the net effect of utilizing all U.S. net operating loss deferred tax assets and releasing the corresponding U.S. valuation allowance as of December 31, 2019. We expect to recognize additional tax benefit in 2020 due to anticipated taxable losses. The tax impacts of the CARES Act
were computed with the best available information, and will be adjusted after the 2020 U.S. tax return is finalized. However, we do not expect these adjustments to have a material change to the tax provision in future periods.
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RESULTS OF OPERATIONS
We conduct our business through two distinct reporting segments: Terminalling services and Fleet services. We have established these reporting segments as strategic business units to facilitate the achievement of our long-term objectives, to aid in resource allocation decisions and to assess operational performance.
The
following table summarizes our operating results by business segment and corporate charges for each of the periods indicated:
Changes in our operating results for the three and six months ended June 30, 2020, as compared with our operating results for the three
and six months ended June 30, 2019, were primarily driven by:
•activities associated with our terminalling services business including:
◦higher revenues resulting from higher rates on certain of our terminalling services agreements at our Hardisty terminal that became effective July 1, 2019;
◦higher revenue associated with revenue that was recognized in the first half of 2020 that we previously deferred associated with the make-up right options we granted to customers of our Hardisty terminal;
◦lower operating income (loss) resulting from the conclusion of a contract
at our Casper terminal in August 2019 and lower subcontracted rail service costs due to lower throughput;
◦higher operating costs resulting from a non-cash impairment of the goodwill associated with our Casper terminal due to current economic conditions as a result of the COVID-19 pandemic, the overall downturn in the crude market and the decline in the demand for petroleum products.
•a decrease in interest expense due to lower weighted average interest rates partially offset by additional amounts outstanding on our credit facility;
•non-cash losses associated with declines in the fair value of our interest rate derivatives resulting from decreases in the interest rate index upon which the derivative values are based; and
•an
increase in benefit from income taxes associated with our fleet services segment primarily related to net operating loss carrybacks made available by provisions in the CARES Act.
A comprehensive discussion of our operating results by segment is presented below.
49
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:
Revenue generated by our Terminalling services segment
increased $0.7 million to $26.1 million for the three months ended June 30, 2020, as compared with the three months ended June 30, 2019. This increase was primarily due to increased revenue at our Hardisty terminal resulting from revenue recognized during the quarter for contracted capacity that exceeds the current transloading capacity of the terminal. This revenue was offset by additional operating costs incurred pursuant to a new agreement with a related party for providing terminalling services for the additional capacity on our behalf at the same rate, on a per barrel basis, that we received as revenue. Additionally, higher rates included in some of our terminalling services agreements that became effective July 1, 2019 due to our re-contracting efforts contributed to the increase in revenues. The increases in revenues
were partially offset by lower revenue at our Casper terminal resulting from the conclusion of a customer agreement in August 2019.
Our average daily terminal throughput decreased 78,543 bpd to 38,628 bpd for the three months ended June 30, 2020, as compared with 117,171 bpd for the three months ended June 30, 2019. Our throughput volumes decreased primarily due to a decrease in demand for export capacity by customers of our Hardisty terminal, a portion of which drives the demand for deliveries to our Stroud terminal and its connection to the Cushing oil hub.
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The decreased demand associated
with our Hardisty terminal resulted from the narrowed WCS to WTI pricing spreads during the three months ended June 30, 2020, primarily as a result of the decline in global oil demand, as described in Recent Developments- Market Update- COVID-19 and Crude Oil Pricing Environment Update. Our terminalling services revenues are recognized based upon the contractual terms set forth in our agreements that contain primarily “take-or-pay” provisions, where we are entitled to the payment of minimum
monthly commitment fees from our customers, which are recognized as revenue as we provide terminalling services.
Our terminalling services revenue for the three months ended June 30, 2020, would have been $0.7 million more if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the three months ended June 30, 2020, was the same as the average exchange rate for the three months ended June 30, 2019. The average exchange rate for the Canadian dollar in relation to the U.S. dollar was 0.7215 for the three months ended June 30, 2020 as compared with 0.7477 for the three months ended June 30, 2019.
Operating
Costs
The operating costs of our Terminalling services segment increased $1.1 million to $18.3 million for the three months ended June 30, 2020, as compared with the $17.2 million for the three months ended June 30, 2019. The increase was primarily attributable to an increase in operating and maintenance costs and higher pipeline fees, partially offset by a decrease in subcontracted rail services costs.
Our terminalling services operating costs for the three months ended June 30, 2020, 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 June 30, 2020, was the same as the average exchange rate
for the three months ended June 30, 2019.
Subcontracted rail services. Our costs for subcontracted rail services decreased $1.0 million to $2.7 million for the three months ended June 30, 2020, from $3.7 million for the three months ended June 30, 2019, primarily due to the reduced throughput at our terminals discussed above.
Pipeline fees. We incur pipeline fees related to a facilities connection agreement with Gibson for the delivery of crude oil from Gibson’s Hardisty storage terminal to our Hardisty terminal via pipeline. The pipeline fees we pay to Gibson are based on a predetermined formula, which includes amounts collected from customers at our Hardisty terminal less direct operating
costs.Our pipeline fees increased $0.5 million to $5.4 million for the three months ended June 30, 2020, as compared with $4.9 million for the three months ended June 30, 2019, primarily due to higher revenues at our Hardisty terminal.
Operating and maintenance. Operating and maintenance expense increased $2.1 million to $3.6 million for the three months ended June 30, 2020, as compared with $1.5 million the three months ended June 30, 2019. The increased operating and maintenance expenses are primarily due to expenses incurred pursuant to a new agreement with a related party for providing terminalling services on our behalf to a customer of our Hardisty
terminal for contracted capacity that exceeds the current transloading capacity available at our Hardisty terminal. These costs represent the same rate, on a per barrel basis, that we received as revenue from our third-party customer.
Other Expense (Income), net
Other expense (income), net. Other expense (income), net increased $0.1 million to $0.1 million of income for the three months ended June 30, 2020, as compared with $25 thousand of expense for the three months ended June 30, 2019. This increase is primarily attributable to income that we earned in 2020 as an incentive for railcar movements of a customer at our Hardisty terminal associated with new railroad incentive agreements.
Revenue generated by our Terminalling services segment increased $3.7 million to $55.1 million for the six months ended June 30, 2020, as compared with $51.4 million for the six months ended June 30, 2019. This increase was primarily due to increased revenue at our Hardisty terminal resulting from revenue recognized during the first half of 2020 for contracted capacity that exceeds the current transloading capacity of the terminal. This revenue was
51
offset
by additional operating costs incurred pursuant to a new agreement with a related party for providing terminalling services for the additional capacity on our behalf at the same rate, on a per barrel basis, that we received as revenue. Higher rates included in some of our terminalling services agreements that became effective July 1, 2019 due to our re-contracting efforts also contributed to the increase in revenues. Additionally, we recognized revenue in the first six months of 2020 that we previously deferred associated with the make-up right options we granted to customers of our Hardisty terminal, as the likelihood that the make-up right options will be utilized in future periods is now remote. The increases in revenues were partially offset by lower revenue at our Casper terminal resulting from the conclusion of a customer agreement in August 2019.
Our average daily terminal
throughput decreased 1,635 bpd to 98,696 bpd for the six months ended June 30, 2020, as compared with 100,331 bpd for the six months ended June 30, 2019. Our throughput volumes decreased primarily due to a decrease in demand for export capacity by customers of our Hardisty terminal that occurred during the second quarter of 2020, a portion of which drives the demand for deliveries to our Stroud terminal and its connection to the Cushing oil hub. The decreased demand associated with our Hardisty terminal resulted from the narrowed WCS to WTI pricing spreads during the second quarter of 2020, primarily as a result of the decline in global oil demand, as described in Recent Developments- Market Update- COVID-19 and Crude Oil Pricing Environment Update.
Our terminalling services revenues are recognized based upon the contractual terms set forth in our agreements that contain primarily “take-or-pay” provisions, where we are entitled to the payment of minimum monthly commitment fees from our customers, which are recognized as revenue as we provide terminalling services.
Our terminalling services revenue for the six months ended June 30, 2020, would have been $0.9 million more if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the six months ended June 30, 2020, was the same as the average exchange rate for the six months ended June 30, 2019. The average exchange rate for the Canadian dollar in relation to the U.S. dollar was 0.7335 for the six months ended June 30, 2020
as compared with 0.7499 for the six months ended June 30, 2019.
Operating Costs
The operating costs of our Terminalling services segment increased $38.9 million to $73.6 million for the six months ended June 30, 2020, as compared with the $34.7 million for the six months ended June 30, 2019. The increase is primarily attributable to an impairment of our goodwill recognized in the first quarter of 2020 at our Casper terminal due to current economic conditions, an increase in operating and maintenance costs, higher pipeline fees and increased depreciation and amortization, partially offset by lower subcontracted rail services costs.
Our terminalling services operating costs for the six months
ended June 30, 2020, would have been $0.5 million more if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the six months ended June 30, 2020, was the same as the average exchange rate for the six months ended June 30, 2019.
Subcontracted rail services. Our costs for subcontracted rail services decreased $1.1 million to $6.1 million for the six months ended June 30, 2020, as compared with the six months ended June 30, 2019, primarily due to the reduced throughput at our terminals that occurred during the second quarter of 2020, as discussed above.
Pipeline fees. We
incur pipeline fees related to a facilities connection agreement with Gibson for the delivery of crude oil from Gibson’s Hardisty storage terminal to our Hardisty terminal via pipeline. The pipeline fees we pay to Gibson are based on a predetermined formula, which includes amounts collected from customers at our Hardisty terminal less direct operating costs.Our pipeline fees increased $1.8 million to $11.7 million for the six months ended June 30, 2020, as compared with the six months ended June 30, 2019, primarily due to higher revenues at our Hardisty terminal. Additionally, we recognized pipeline fees during the six months ended June 30, 2020, associated with revenue that we previously deferred associated with the make-up right options we granted to customers of our Hardisty
terminal, since the likelihood that the make-up right options will be utilized in future periods is now remote.
Operating and maintenance. Operating and maintenance expense increased $4.0 million to $7.7 million for the six months ended June 30, 2020, as compared with $3.7 million the six months ended June 30, 2019. The increased operating and maintenance expenses are primarily due to expenses incurred pursuant to a new agreement
52
with a related party for providing terminalling services on our behalf to a customer of our Hardisty terminal for contracted capacity that
exceeds the current transloading capacity available at our Hardisty terminal. These costs represent the same rate, on a per barrel basis, that we received as revenue from our third-party customer.
Goodwill impairment loss. In March 2020, we tested the goodwill associated with our Casper terminal for impairment due to the overall downturn in the crude market and the decline in the demand for petroleum products. As a result of our impairment testing, we recognized an impairment loss of $33.6 million for the six months ended June 30, 2020. Refer to Part I. Item 1. Financial Statements,Note 2. Recent Accounting Pronouncementsand Note
8. Goodwill and intangible assets of this Quarterly Report for further discussion.
Depreciation and amortization. Depreciation and amortization expense increased $0.6 million to $10.6 million for the six months ended June 30, 2020, as compared with $10.0 million for the six months ended June 30, 2019. The increase is primarily due to a revised estimate of our asset retirement obligations, or ARO, that decreased depreciation and amortization expense by $0.6 million in the first quarter of 2019 associated with our decommissioned San Antonio rail terminal as compared to a revised ARO estimate that decreased depreciation and amortization by only $0.2 million during the second quarter of 2020 associated with the same terminal, coupled with an increase in depreciation associated with
the outbound pipeline at our Casper terminal that was placed into service in December 2019.
Other Expense (Income), net
Other expense (income), net. Other expense (income), net increased $0.8 million for the six months ended June 30, 2020, as compared with the six months ended June 30, 2019. This increase is primarily attributable to income that we earned in 2020 as an incentive for railcar movements of a customer at our Hardisty terminal associated with new railroad incentive agreements.
FLEET SERVICES
The
following table sets forth the operating results of our Fleet services segment for the periods indicated:
The underlying business activities associated with our Fleet services segment have remained relatively consistent for the three months ended June 30, 2020, as compared with the three months ended June 30, 2019. As a result, we have experienced only modest changes in the operating revenues and expenses associated with this business segment.
Historically we have assisted our customers with procuring railcars to facilitate their use of our terminalling services. Our wholly-owned subsidiary USD Rail LP has historically entered into leases with third-party manufacturers of railcars and financial firms, which it has then leased to customers. Although we expect to continue assisting
our customers with obtaining railcars for their use transporting crude oil from our terminals, as our existing lease agreements expire, or are otherwise terminated, or assigned to our existing customers, we do not expect to enter into similar leasing arrangements in the future. Should market conditions change, we would potentially assist with the procurement and management of railcars on behalf of our customers again in the future.
Revenues from our Fleet services segment decreased $0.2 million to $2.6 million for the six months ended June 30, 2020, as compared with $2.8 million for the six months ended June 30, 2019.
The decrease in revenue was primarily attributable to fewer customer reimbursements to us for freight and other reimbursable charges that we have incurred on their behalf. The decrease in Freight and other reimbursables revenue was exactly offset by a corresponding decrease in Freight and other reimbursables operating costs for the same reason.
Our benefit for income taxes in the Fleet services segment increased $0.5 million to a benefit of $0.5 million for six months ended June 30, 2020 as compared with a provision of $8 thousand for the six months ended June 30, 2019. This increase in benefit is due to a provision in the CARES Act that allows U.S. net operating losses incurred in tax years 2018, 2019, or 2020 to be carried back to the preceding five years and generate a tax refund. Under prior guidance, these net operating
losses could only be carried forward.
CORPORATE ACTIVITIES
The following table sets forth our corporate charges for the periods indicated:
Costs associated with our corporate activities decreased $0.8 million to $6.5 million for the three months ended June 30, 2020, as compared to $7.3 million for the three months ended June 30, 2019. Our interest expense costs decreased $0.7 million to $2.3 million due to a decrease in interest rates we were charged under our Credit Agreement, partially offset by a higher weighted average balance of debt outstanding during the three months ended June 30, 2020, as compared to the same period in 2019. In addition, we incurred a non-cash loss of $0.3 million on
54
our
interest rate derivatives for the three months ended June 30, 2020, as compared to a non-cash loss of $1.1 million for the same period in 2019. We had a foreign currency transaction loss of $1.1 million for three months ended June 30, 2020 primarily due to repayments and anticipated repayments to us related to an intercompany loan with one of our consolidated subsidiaries.
Costs associated with our corporate activities increased $0.9 million to $15.2 million for the six months ended June 30, 2020
as compared with the same period in 2019. The decreased interest expense costs and higher foreign currency transaction loss for the current period as compared to the same period in the prior year were due to the same reasons cited above in our three month analysis. In addition, we incurred a higher non-cash loss of $3.2 million on our interest rate derivatives for the six months ended June 30, 2020, as compared to a non-cash loss of $1.7 million for the same period in 2019.
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LIQUIDITY AND CAPITAL RESOURCES
Our principal liquidity requirements
include:
•financing current operations;
•servicing our debt;
•funding capital expenditures, including potential acquisitions and the costs to construct new assets; and
•making distributions to our unitholders.
We have historically financed our operations with cash generated from our operating activities, borrowings under our Revolving Credit Facility and loans from our sponsor.
Liquidity Sources
We expect our ongoing sources of liquidity to include borrowings under our senior secured credit agreement, issuances of debt securities and additional partnership interests as
well as cash generated from our operating activities. We believe that cash generated from these sources will be sufficient to meet our ongoing working capital and capital expenditure requirements and to make quarterly cash distributions at current levels for the next 12 months.
For information regarding our Credit Agreement, please see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Agreement in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019 and Part I. Item 1. Financial Statements,Note 9. Debt of this Quarterly Report.
The
following table presents our available liquidity as of the dates indicated:
Available liquidity
based on Credit Agreement capacity (2)
$
170.1
$
168.1
Available liquidity based on Credit Agreement covenants (2)
$
29.3
$
31.9
(1) Excludes amounts
that are restricted pursuant to our collaborative agreement with Gibson.
(2) Pursuant to the terms of our Credit Agreement, our borrowing capacity currently is limited to 4.5 times our trailing 12-month consolidated EBITDA, which equates to $26.2 million and $28.8 million of borrowing capacity available at June 30, 2020 and December 31, 2019, respectively.
Energy Capital Partners must approve any additional issuances of equity by us, and such determinations may be made free of any duty to us or our unitholders. Members of our general partner’s board of directors appointed by Energy Capital Partners must also approve the incurrence by us of additional indebtedness or refinancing outside of our existing indebtedness that is not in the ordinary course of business.
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Cash
Flows
The following table and discussion summarize the cash flows associated with our operating, investing and financing activities for the periods indicated:
Net change in cash, cash equivalents and restricted cash
$
(438)
$
2,077
Operating Activities
Net cash provided by operating activities decreased $2.4 million to $17.1 million for the six months ended June 30, 2020,
as compared with $19.5 million for the six months ended June 30, 2019. The decrease in net cash provided by operating activities was primarily due to the timing of receipts and payments on accounts receivable, accounts payable and deferred revenue balances.
Investing Activities
Net cash used in investing activities decreased to $0.4 million for the six months ended June 30, 2020 compared to $2.7 million for the six months ended June 30, 2019 primarily due to the construction of the outbound pipeline connection from our Casper terminal to the Platte terminal located at the termination point of the Express pipeline that was placed into service in December 2019.
Financing Activities
Net cash used in financing activities increased to $17.6 million for the six months ended June 30, 2020 from $15.4 million for the six months ended June 30, 2019. Our net proceeds from long-term debt during the six months ended June 30, 2020 were $9.0 million lower than the amounts we borrowed during the six months ended June 30, 2019. Additionally, cash paid for distributions decreased during the six months ended June 30, 2020, as compared to the same period in 2019.
Cash Requirements
Our primary requirements for cash are: (1) financing current operations, (2) servicing
our debt, (3) funding capital expenditures, including potential acquisitions and the costs to construct new assets, and (4) making distributions to our unitholders.
Capital Requirements
Our historical capital expenditures have primarily consisted of the costs to construct and acquire energy-related logistics assets. Our operations are expected to require investments to expand, upgrade or enhance existing facilities and to meet environmental and operational regulations. We also occasionally invest in our assets to expand their capacity or capability, such as the pipeline connection from our Casper Terminal to the Platte Terminal. We may incur unanticipated costs in connection with any expansion projects, which costs could be material or be incurred in periods after the project is completed.
We expect to fund future capital expenditures
from cash on our balance sheet, cash flow generated from our operating activities, borrowings under our Credit Agreement and the issuance of additional partnership interests or long-term debt.
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Our partnership agreement requires that we categorize our capital expenditures as either expansion capital expenditures, maintenance capital expenditures, or investment capital expenditures. Although we have not experienced significant maintenance capital expenditures in prior years, as the age and usage of our assets increase, we expect that costs we incur to maintain them in compliance with sound business practice, our contractual relationships and applicable regulatory requirements will likely increase. Some of these costs will be characterized
as maintenance capital expenditures. We incurred $114 thousand for maintenance capital expenditures during the six months ended June 30, 2020. Our total expansion capital expenditures for the six months ended June 30, 2020 were $0.3 million.
Debt Service
We anticipate reducing our outstanding indebtedness to the extent we generate cash flows in excess of our operating, investing and distribution needs. During the six months ended June 30, 2020, we received proceeds from borrowings of $10.0 million on our Revolving Credit Facility which we used for general partnership purposes and made repayments of $12.0 million on our Revolving Credit Facility from cash flow in excess of our operating and investing needs.
Distributions
Our
partnership agreement does not require us to pay cash distributions on a quarterly or other basis, and we do not have a legal obligation to distribute any particular amount per common unit.
For the quarter ended June 30, 2020, the board of directors of our general partner determined that we had sufficient available cash after the establishment of cash reserves and the payment of our expenses to distribute $0.111 per unit on all of our units. Our current quarterly distribution of $0.111 per unit equates to $3.0 million per quarter, or $12.1 million per year, based on the number of common and general partner units outstanding as of August 4, 2020. This distribution represents a decrease of 70.0% from the distribution with respect to the fourth quarter of 2019, and is consistent with the distribution declared for the first quarter
of 2020. Given the current uncertainty in the energy industry, the board of directors made a proactive decision to strengthen our financial position by reducing our quarterly distribution and redeploying certain free cash flow to de-lever. During the second quarter of 2020, we repaid $6 million of the outstanding balance of our revolving credit facility.
The board of directors of our general partner may change our distribution policy or suspend distributions at any time and from time to time. Additionally, members of our general partner’s board of directors appointed by Energy Capital Partners, must approve any distributions made by us.
Other Items Affecting Liquidity
Credit Risk
Our exposure to credit risk may be affected by the concentration of our customers within the energy industry, as well
as changes in economic or other conditions. Our customers’ businesses react differently to changing conditions. We believe that our credit-review procedures, customer deposits and collection procedures have adequately provided for amounts that may become uncollectible in the future.
Foreign Currency Exchange Risk
We currently derive a significant portion of our cash flow from our Canadian operations, particularly our Hardisty terminal. As a result, portions of our cash and cash equivalents are denominated in Canadian dollars and are held by foreign subsidiaries, which amounts are subject to fluctuations resulting from changes in the exchange rate between the U.S. dollar and the Canadian dollar. We employ derivative financial instruments to minimize our exposure to the effect of foreign currency
fluctuations, as we deem necessary based upon anticipated economic conditions.
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SUBSEQUENT EVENTS
Refer to Note 20. Subsequent events of our consolidated financial statements included in Part I — Financial Information, Item 1. Financial Statements of this Report for a discussion regarding subsequent events.
RECENT ACCOUNTING PRONOUNCEMENTS — NOT YET ADOPTED
Refer to Note 2. Recent Accounting Pronouncements of our consolidated financial statements included in Part I — Financial Information, Item 1. Financial Statements of this Report for a discussion regarding recent accounting pronouncements that we have not yet adopted.
OFF
BALANCE SHEET ARRANGEMENTS
In the normal course of business, we are a party to off-balance sheet arrangements relating to various master fleet services agreements, whereby we have agreed to assign certain payment and other obligations to third-party special purpose entities that are not consolidated with us. We have also entered into agreements to provide fleet services to these special purpose entities for fixed servicing fees and reimbursement of out-of-pocket expenses. The purpose of these transactions is to remove the risk to us of non-payment by our customers, which would otherwise negatively impact our financial condition and results of operations. For more information on these special purpose entities, see the discussion of our relationship with the variable interest entities described in Note 11. Nonconsolidated
Variable Interest Entities to our consolidated financial statements included in Part I — Financial Information, Item 1. Financial Statements of this Report. Assets and liabilities related to these arrangements are generally not reflected in our consolidated balance sheets, and we do not expect any material impact on our cash flows, results of operations or financial condition as a result of these off-balance sheet arrangements.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
There have been no changes to our critical accounting policies and estimates described in the Annual Report on Form 10-K for the year ended
December 31, 2019, that have had a material impact on our consolidated financial statements and related notes, other than as discussed below.
Assessment of Recoverability of Goodwill
Goodwill represents the future economic benefits arising from assets acquired in a business combination that are not individually identified and separately recognized. Historically, goodwill was only included in our Terminalling services segment as part of our Casper terminal reporting unit.
We do not amortize goodwill, but test it for impairment annually based on the carrying amounts of our reporting units on the first day of the third quarter of each year or more frequently if impairment indicators arise that suggest the carrying amount of goodwill may be impaired. Our assessment of the recoverability of goodwill
is highly subjective due to frequent changes in economic conditions underlying the assumptions upon which the valuations are based and global factors affecting the prices for various grades of crude oil and demand for our services.
In assessing our ability to recover the carrying amount of goodwill, we make critical assumptions that include but are not limited to:
1)our projections of future financial performance;
2)our expectations for contract renewals for existing and additional capacity with current customers;
3)our ability to expand our services and attract new customers;
4)our
expected market weighted average cost of capital;
5)an expected range of EBITDA multiples derived from equity prices of public companies with similar operating and investment characteristics; and
6)an expected range of EBITDA multiples for transactions based on actual sales and purchases of comparable businesses.
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We recognize an impairment loss when the carrying amount of a reporting unit exceeds its implied fair value. We reduce the carrying amount of goodwill to its fair value at the time we determine that an impairment has occurred.
Our goodwill originated
from our acquisition of the Casper terminal in November 2015 and is wholly attributed to this reporting unit. We measured the fair value of our Casper terminal reporting unit using customary business valuation techniques including an income analysis, market analysis and transaction analysis, which we weighted at 50%, 25% and 25%, respectively. Our weighting of the measurement methods is consistent with weightings used to value organizations that are similar to the Casper terminal reporting unit.
In March 2020, we tested the goodwill associated with our Casper terminal for impairment due to the overall downturn in the crude market and the decline in the demand for petroleum products, which could lead to delays or reductions of expected throughput levels and changes in expectations for current and future contracts at the Casper terminal.
The
critical assumptions used in our analysis include the following:
1)a weighted average cost of capital of i12%;
2)a capital structure consisting of approximately i65%
debt and i35% equity based on the capital structure of market participants;
3)a range of EBITDA multiples derived from equity prices of public companies with similar operating and investment characteristics, from i7.25x
to i8.25x;
4)a range of EBITDA multiples for transactions based on actual sales and purchases of comparable businesses, from i8.0x
to i9.0x; and
5)a range of incremental volumes expected at our Casper terminal of approximately i4,000
to i25,000 bpd for terminalling and storage services resulting from the anticipated successful completion of the Enbridge DRA project in the second half of 2020.
The key assumptions listed above were based upon economic and other operational conditions existing at or prior to our March 31, 2020 valuation date. Our weighted average cost of capital is subject to variability and is dependent upon such factors
as changes in benchmark rates of interest established by the Federal Open Market Committee of the Federal Reserve Board, the British Bankers Association and other central banking regulatory authorities, as well as perceptions of risk and market uncertainty regarding our business, industry and those of our peers and our underlying capital structure. We expect our long-term underlying capital structure to approximate a weighting of 50% debt and 50% equity. Each of the above assumptions are likely to change due to economic uncertainty surrounding global and North American energy markets that are highly correlated with crude oil, natural gas and other energy-related commodity prices and other market factors.
The EBITDA multiples we used to estimate the fair value of the Casper terminal reporting unit are subject to uncertainty associated with market conditions in the energy sector. We derived the assumption based upon the EBITDA
multiples from several comparable businesses that operate in the midstream energy sector, generally providing services associated with the transportation of energy-related products. The EBITDA multiples of each of these entities is affected by changes in the supply of and demand for energy-related products, which affects the demand for the services they provide. Declines in the production of energy-related products as well as lower demand for these products can reduce the operating results of these organizations, and accordingly, the multiples that market participants are willing to pay. Changes in the EBITDA multiples of these comparable businesses we use to estimate fair value could significantly affect the fair value of the Casper terminal reporting unit we derived using this approach.
The EBITDA multiples from executed purchase and sales transactions of businesses that are similar to our Casper terminal reporting unit we
used to estimate the fair value are also subject to variability, which is dependent upon market conditions in the energy sector, as well as the perceived benefits the acquiring entity expects to derive from the transaction. The transactions comprising the pool occurred during the immediately preceding three years and future transactions may have no correlation to the EBITDA multiples for similar transactions in the future. Further deterioration in economic conditions in the energy sector could result in a greater number of distressed sales
60
at lower EBITDA multiples than currently estimated. Additionally, a representative sample of transactions in the future may not provide a sufficient population upon which to derive an EBITDA multiple.
These factors, among others, could cause our estimates of fair value for the Casper terminal reporting unit to vary significantly from the amounts determined under this method.
As indicated above, our estimate of fair value for the Casper terminal reporting unit required us to use significant unobservable inputs representative of Level 3 fair value measurements, including assumptions related to the future performance of our Casper terminal. During the first quarter of 2020, we completed our goodwill impairment analysis and determined that the carrying amount of the Casper terminal reporting unit exceeded its fair value at March 31, 2020. Accordingly, we have recognized an impairment loss of $i33.6
million in our goodwill asset and have included this charge in “Goodwill impairment loss” within our consolidated statement of operations for the six months ended June 30, 2020. At June 30, 2020, we had ino goodwill balance in our consolidated balance sheet.
Impairment of Long-lived Assets
We evaluate long-lived assets for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may
not be recoverable.
We consider a long-lived asset to be impaired when the sum of the estimated, undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset. Factors that indicate potential impairment include: a significant decrease in the market value of the asset, operating or cash flow losses associated with the use of the asset, or a significant change in the asset’s physical condition or use.
When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable based on the estimated future undiscounted cash flows, an impairment loss is recognized to the extent the carrying amount
exceeds the estimated fair value of the long-lived asset.
We determined the overall downturn in the crude market and the decline in the demand for petroleum products, which could lead to delays or reduction of expected throughput levels and changes in expectations for current and future contracts in our terminalling services at the Casper terminal was an event that required us to evaluate our Casper terminal asset group for impairment. We measured the fair value of our Casper terminal assets by using projections of the undiscounted cash flows expected to be derived from the operation and disposition of the Casper terminal asset.
The critical assumptions underlying our projections included the following:
1)a range of incremental
volumes expected at our Casper terminal of approximately 4,000 to 25,000 bpd for terminalling and storage services resulting from the anticipated successful completion of the Enbridge DRA project in the second half of 2020
2)expected volumes for our blended services business for distribution to local refiners;
3)a 15 year remaining useful life of the primary asset, represented by our property and equipment of the Casper terminal asset group; and
4)a residual value of 8.0x projected cash flows for the Casper terminal at the end of the 15 year remaining life of the primary asset.
Our projections of the undiscounted cash flows expected to be derived from the operation and disposition of the Casper terminal asset group exceeded
the carrying amount of the asset group as of March 31, 2020, the date of our evaluation, indicating cash flows were expected to be sufficient to recover the carrying amount of the Casper terminal asset group. Accordingly, we did not recognize any impairment of our Casper terminal asset.
To the extent that our assumptions as set forth above do not materialize, our projections of future financial performance underlying our cash flow projections for the Casper terminal could yield undiscounted cash flows and a fair value that indicate our long-lived assets are impaired. Moreover, these assumptions may change over time in
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response to the effects
of the COVID-19 pandemic and the state of the commodity markets, which are inherently uncertain and difficult to predict.
We have not observed any events or circumstances subsequent to our analysis at March 31, 2020 that would suggest the fair value of our Casper terminal asset is below its carrying amount as of June 30, 2020.
Item 3. Quantitative and Qualitative Disclosures about Market Risk.
As a smaller reporting company, we are not required to provide the information required by this Item.
Item 4. Controls
and Procedures.
DISCLOSURE CONTROLS AND PROCEDURES
As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended, or the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2020. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow for timely
decisions regarding required disclosure and to ensure information is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2020, at the reasonable assurance level.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
We did not make any changes in our internal control over financial reporting during the three months ended June 30, 2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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PART II
— OTHER INFORMATION
Item 1. Legal Proceedings
Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. We do not believe that we are currently a party to any litigation that will have a material adverse impact on our financial condition, results of operations or statements of cash flows. We are not aware of any material legal or governmental proceedings against us, or any proceedings known to be contemplated by governmental authorities.
Item 1A. Risk Factors
We
are subject to various risks and uncertainties in the ordinary course of our business. Risk factors relating to us are set forth under “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019 and in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020. We may be subject to additional risks and uncertainties that we currently consider immaterial or that are unknown to us but may have a material impact on our business, financial condition and results of operations.
Item 6. Exhibits
The following “Index of Exhibits” is hereby
incorporated into this Item.
Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH*
Inline XBRL Schema Document
101.CAL*
Inline
XBRL Calculation Linkbase Document
101.LAB*
Inline XBRL Label Linkbase Document
101.PRE*
Inline XBRL Presentation Linkbase Document
101.DEF*
Inline XBRL Definition Linkbase Document
104*
The
cover page of the USD Partners LP Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, formatted in Inline XBRL (included within the Exhibit 101 attachments)
†† Portions of this exhibit (indicated by asterisks) have been omitted pursuant to Regulation S-K Item 601(b)(10). Such omitted information is not material and would likely cause competitive harm to the registrant if publicly disclosed.
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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.
