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FINANCIAL DATA
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First |
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Second |
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Third |
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Fourth |
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(in thousands, except per unit amounts) |
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2022 Quarters
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Operating revenue
|
$ |
35,786 |
|
$ |
33,741 |
|
$ |
21,479 |
|
$ |
20,649 |
|
Operating expense
|
$ |
30,791 |
|
$ |
28,533 |
|
$ |
93,940 |
|
$ |
18,076 |
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Operating income (loss)
|
$ |
4,995 |
|
$ |
5,208 |
|
$ |
(72,461) |
|
$ |
2,573 |
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Net income (loss)
|
$ |
7,473 |
|
$ |
3,805 |
|
$ |
(69,353) |
|
$ |
(3,211) |
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Net income (loss) attributable to limited partner ownership
interest in USD Partners LP
|
$ |
8,842 |
|
$ |
3,805 |
|
$ |
(69,353) |
|
$ |
(3,211) |
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Net income (loss) per limited partner unit, basic and
diluted
|
$ |
0.32 |
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$ |
0.11 |
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$ |
(2.08) |
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$ |
(0.10) |
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First |
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Second |
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Third |
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Fourth |
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(in thousands, except per unit amounts) |
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2021 Quarters
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|
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Operating revenue
|
$ |
43,627 |
|
$ |
91,513 |
|
$ |
35,448 |
|
$ |
33,897 |
|
Operating expense
|
$ |
37,289 |
|
$ |
82,363 |
|
$ |
29,829 |
|
$ |
29,119 |
|
Operating income
|
$ |
6,338 |
|
$ |
9,150 |
|
$ |
5,619 |
|
$ |
4,778 |
|
Net income
|
$ |
7,524 |
|
$ |
6,886 |
|
$ |
4,133 |
|
$ |
4,286 |
|
Net income attributable to limited partner ownership interest in
USD Partners LP
|
$ |
7,204 |
|
$ |
6,605 |
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$ |
3,744 |
|
$ |
3,546 |
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Net income per limited partner unit, basic and diluted
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$ |
0.27 |
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$ |
0.24 |
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$ |
0.13 |
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$ |
0.13 |
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First |
|
Second |
|
Third |
|
Fourth |
|
(in thousands, except per unit amounts) |
|
2022 Quarters
|
|
|
|
|
|
|
|
|
Operating revenue
|
$ |
35,786 |
|
$ |
33,741 |
|
$ |
21,479 |
|
$ |
20,649 |
|
Operating expense
|
$ |
30,791 |
|
$ |
28,533 |
|
$ |
93,940 |
|
$ |
18,076 |
|
Operating income (loss)
|
$ |
4,995 |
|
$ |
5,208 |
|
$ |
(72,461) |
|
$ |
2,573 |
|
Net income (loss)
|
$ |
7,473 |
|
$ |
3,805 |
|
$ |
(69,353) |
|
$ |
(3,211) |
|
Net income (loss) attributable to limited partner ownership
interest in USD Partners LP
|
$ |
8,842 |
|
$ |
3,805 |
|
$ |
(69,353) |
|
$ |
(3,211) |
|
Net income (loss) per limited partner unit, basic and
diluted
|
$ |
0.32 |
|
$ |
0.11 |
|
$ |
(2.08) |
|
$ |
(0.10) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
(in thousands, except per unit amounts) |
|
2021 Quarters
|
|
|
|
|
|
|
|
|
Operating revenue
|
$ |
43,627 |
|
$ |
91,513 |
|
$ |
35,448 |
|
$ |
33,897 |
|
Operating expense
|
$ |
37,289 |
|
$ |
82,363 |
|
$ |
29,829 |
|
$ |
29,119 |
|
Operating income
|
$ |
6,338 |
|
$ |
9,150 |
|
$ |
5,619 |
|
$ |
4,778 |
|
Net income
|
$ |
7,524 |
|
$ |
6,886 |
|
$ |
4,133 |
|
$ |
4,286 |
|
Net income attributable to limited partner ownership interest in
USD Partners LP
|
$ |
7,204 |
|
$ |
6,605 |
|
$ |
3,744 |
|
$ |
3,546 |
|
Net income per limited partner unit, basic and diluted
|
$ |
0.27 |
|
$ |
0.24 |
|
$ |
0.13 |
|
$ |
0.13 |
35,78633,74121,47920,64930,79128,53393,94018,0764,9955,20872,4612,5737,4733,80569,3533,2118,8423,80569,3533,2110.320.112.080.1043,62791,51335,44833,89737,28982,36329,82929,1196,3389,1505,6194,7787,5246,8864,1334,2867,2046,6053,7443,5460.270.240.130.1300016106822022-01-012022-12-3100016106822022-06-30iso4217:USD00016106822023-02-21xbrli:shares0001610682usdp:TerminallingServicesMember2022-01-012022-12-310001610682usdp:TerminallingServicesMember2021-01-012021-12-310001610682usdp:TerminallingServicesMember2020-01-012020-12-310001610682usdp:TerminallingServicesMembersrt:AffiliatedEntityMember2022-01-012022-12-310001610682usdp:USDMarketingMembersrt:AffiliatedEntityMemberusdp:TerminallingServicesMember2022-01-012022-12-310001610682usdp:TerminallingServicesMembersrt:AffiliatedEntityMember2021-01-012021-12-310001610682usdp:TerminallingServicesMembersrt:AffiliatedEntityMember2020-01-012020-12-310001610682usdp:FleetLeasesMembersrt:AffiliatedEntityMember2022-01-012022-12-310001610682usdp:FleetLeasesMemberusdp:USDMarketingMembersrt:AffiliatedEntityMember2022-01-012022-12-310001610682usdp:FleetLeasesMembersrt:AffiliatedEntityMember2021-01-012021-12-310001610682usdp:FleetLeasesMembersrt:AffiliatedEntityMember2020-01-012020-12-310001610682usdp:FleetServicesMember2022-01-012022-12-310001610682usdp:FleetServicesMember2021-01-012021-12-310001610682usdp:FleetServicesMember2020-01-012020-12-310001610682usdp:USDMarketingMemberusdp:FleetServicesMembersrt:AffiliatedEntityMember2022-01-012022-12-310001610682srt:AffiliatedEntityMemberusdp:FleetServicesMember2022-01-012022-12-310001610682srt:AffiliatedEntityMemberusdp:FleetServicesMember2021-01-012021-12-310001610682srt:AffiliatedEntityMemberusdp:FleetServicesMember2020-01-012020-12-310001610682usdp:FreightAndOtherReimbursablesMember2022-01-012022-12-310001610682usdp:FreightAndOtherReimbursablesMember2021-01-012021-12-310001610682usdp:FreightAndOtherReimbursablesMember2020-01-012020-12-310001610682usdp:USDMarketingMemberusdp:FreightAndOtherReimbursablesMembersrt:AffiliatedEntityMember2022-01-012022-12-310001610682usdp:FreightAndOtherReimbursablesMembersrt:AffiliatedEntityMember2022-01-012022-12-310001610682usdp:FreightAndOtherReimbursablesMembersrt:AffiliatedEntityMember2021-01-012021-12-310001610682usdp:FreightAndOtherReimbursablesMembersrt:AffiliatedEntityMember2020-01-012020-12-3100016106822021-01-012021-12-3100016106822020-01-012020-12-310001610682usdp:SubcontractedRailServicesMember2022-01-012022-12-310001610682usdp:SubcontractedRailServicesMember2021-01-012021-12-310001610682usdp:SubcontractedRailServicesMember2020-01-012020-12-310001610682usdp:PipelineFeesMember2022-01-012022-12-310001610682usdp:PipelineFeesMember2021-01-012021-12-310001610682usdp:PipelineFeesMember2020-01-012020-12-310001610682srt:AffiliatedEntityMember2022-01-012022-12-310001610682srt:AffiliatedEntityMember2021-01-012021-12-310001610682srt:AffiliatedEntityMember2020-01-012020-12-310001610682usdp:CommonUnitsMember2022-01-012022-12-31iso4217:USDxbrli:shares0001610682usdp:CommonUnitsMember2021-01-012021-12-310001610682usdp:CommonUnitsMember2020-01-012020-12-310001610682usdp:SubordinatedUnitsMember2022-01-012022-12-310001610682usdp:SubordinatedUnitsMember2021-01-012021-12-310001610682usdp:SubordinatedUnitsMember2020-01-012020-12-3100016106822021-12-3100016106822020-12-3100016106822019-12-3100016106822022-12-310001610682usdp:CommonUnitsMember2022-12-310001610682usdp:CommonUnitsMember2021-12-310001610682us-gaap:LimitedPartnerMemberusdp:CommonUnitsMember2021-12-310001610682us-gaap:LimitedPartnerMemberusdp:CommonUnitsMember2020-12-310001610682us-gaap:LimitedPartnerMemberusdp:CommonUnitsMember2019-12-310001610682us-gaap:LimitedPartnerMemberusdp:CommonUnitsMember2021-01-012021-12-310001610682us-gaap:LimitedPartnerMemberusdp:CommonUnitsMember2020-01-012020-12-310001610682us-gaap:LimitedPartnerMemberusdp:CommonUnitsMember2022-01-012022-12-310001610682us-gaap:LimitedPartnerMemberusdp:CommonUnitsMember2022-12-310001610682usdp:SubordinatedUnitsMemberus-gaap:LimitedPartnerMember2021-12-310001610682usdp:SubordinatedUnitsMemberus-gaap:LimitedPartnerMember2020-12-310001610682usdp:SubordinatedUnitsMemberus-gaap:LimitedPartnerMember2019-12-310001610682usdp:SubordinatedUnitsMemberus-gaap:LimitedPartnerMember2022-01-012022-12-310001610682usdp:SubordinatedUnitsMemberus-gaap:LimitedPartnerMember2021-01-012021-12-310001610682usdp:SubordinatedUnitsMemberus-gaap:LimitedPartnerMember2020-01-012020-12-310001610682usdp:SubordinatedUnitsMemberus-gaap:LimitedPartnerMember2022-12-310001610682us-gaap:GeneralPartnerMember2021-12-310001610682us-gaap:GeneralPartnerMember2020-12-310001610682us-gaap:GeneralPartnerMember2019-12-310001610682us-gaap:GeneralPartnerMember2022-01-012022-12-310001610682us-gaap:GeneralPartnerMember2020-01-012020-12-310001610682us-gaap:GeneralPartnerMember2021-01-012021-12-310001610682us-gaap:GeneralPartnerMember2022-12-310001610682us-gaap:AccumulatedOtherComprehensiveIncomeMember2021-12-310001610682us-gaap:AccumulatedOthe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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
☒ ANNUAL
REPORT PURSUANT TO SECTION 13
OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2022
or
☐ TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from
to
Commission file number 001-36674
USD PARTNERS LP
(Exact name of registrant as specified in its charter)
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Delaware |
30-0831007 |
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(State or other jurisdiction of incorporation or
organization) |
(I.R.S. Employer Identification No.) |
811 Main Street, Suite 2800
Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code
(281) 291-0510
Securities registered pursuant to Section 12(b) of the
Act:
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Title of each class |
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Trading Symbol |
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Name of each exchange on which registered |
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Common Units Representing Limited Partner Interests |
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USDP |
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New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned
issuer, as defined in Rule 405 of the Securities
Act. Yes ¨ No x
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past
90 days. Yes x
No
¨
Indicate by check mark whether the registrant has submitted
electronically every Interactive Data File required to be submitted
pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter)
during the preceding 12 months (or for such shorter period
that the registrant was required to submit such
files). Yes x No ¨
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated filer, a
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.
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Large accelerated filer |
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Accelerated filer |
☒ |
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Non-accelerated filer
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☐ |
Smaller reporting company |
☒ |
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Emerging growth company |
☐ |
If an emerging growth company, indicate by check mark if the
registrant has elected not to use the extended transition period
for complying with any new or revised financial accounting
standards provided pursuant to Section 13(a) of the Exchange
Act.
¨
Indicate by check mark whether the registrant has filed a report on
and attestation to its management’s assessment of the effectiveness
of its internal control over financial reporting under Section
404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the
registered public accounting firm that prepared or issued its audit
report.
☒
If securities are registered pursuant to Section 12(b) of the Act,
indicate by check mark whether the financial statements of the
registrant included in the filing reflect the correction of an
error to previously issued financial statements.
☐
Indicate by check mark whether any of those error corrections are
restatements that required a recovery analysis of incentive-based
compensation received by any of the registrant’s executive officers
during the relevant recovery period pursuant to
§240.10D-1(b).
☐
Indicate by check mark whether the registrant is a shell company
(as defined in Rule 12b-2 of the
Act). Yes ☐ No x
As of June 30, 2022, the last business day of the registrant’s
most recently completed second fiscal quarter, the aggregate market
value of the registrant’s common units held by non-affiliates was
$75,680,067 computed by reference to the price at which the common
equity was last sold, or the average bid and asked price of such
common equity.
As of February 21, 2023, the registrant has outstanding
33,758,607 common units.
DOCUMENTS INCORPORATED BY REFERENCE: NONE
TABLE OF CONTENTS
Unless the context otherwise requires, all references in this
Annual Report on Form 10-K, or this “Annual Report,” this “Report”
or this “Form 10-K” 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
Annual Report to (i) “our general partner” refer to USD Partners GP
LLC, a Delaware limited liability company; (ii) “USD” refers to US
Development Group, LLC, a Delaware limited liability company, and
where the context requires, its subsidiaries; (iii) “USDG” and “our
sponsor” refer to USD Group LLC, a Delaware limited liability
company and currently the sole direct subsidiary of USD; (iv)
“Energy Capital Partners” refers to Energy Capital Partners III, LP
and its parallel and co-investment funds and related investment
vehicles; and (v) “Goldman Sachs” refers to The Goldman Sachs
Group, Inc. and its affiliates.
Cautionary Note Regarding Forward-Looking Statements
This Annual 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 Annual 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) our
ability to continue as a going concern; (2) the impact of world
health events, epidemics and pandemics, such as the novel
coronavirus (COVID-19) pandemic; (3) changes in general
economic conditions and commodity prices, including as a result of
the invasion of Ukraine by Russia and its regional and global
ramifications, inflationary pressures, or slowing growth or
recession; (4) the effects of competition, in particular, by
pipelines and other terminal facilities; (5) shut-downs or cutbacks
at upstream production facilities, refineries or other related
businesses; (6) government regulations regarding oil production,
including if the Alberta Government were to resume setting
production limits; (7) the supply of, and demand for, terminalling
services for crude oil and biofuels; (8) the price and availability
of debt and equity financing; (9) actions by third parties,
including customers, potential customers, construction-related
services providers, our sponsors and lenders, including with
respect to modifications to our credit agreement or refinancing of
our credit agreement before its maturity; (10) our ability to enter
into new contracts for uncontracted capacity and to renew expiring
contracts; (11) hazards and operating risks that may not be covered
fully by insurance; (12) disruptions due to equipment interruption
or failure at our facilities or third-party facilities on which our
business is dependent; (13) natural disasters, weather-related
delays, casualty losses and other matters beyond our control; (14)
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
(15) our ability to successfully identify
and finance potential acquisitions, development projects and other
growth opportunities. For additional factors that may affect our
results, see Item 1A.
Risk
Factors
included in Part 1 of this Annual Report and our subsequently filed
Quarterly Reports on Form 10-Q, which are 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).
GLOSSARY
The following abbreviations, acronyms and terms used in this
Form 10-K are defined below:
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API gravity |
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American Petroleum Institute Gravity. |
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Bitumen |
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A dense, highly viscous, petroleum-based hydrocarbon that is found
in deposits such as oil sands. |
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Diluent |
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Refers to lighter hydrocarbon products such as natural gasoline or
condensate that are blended with heavy crude oil to allow for
pipeline transportation of heavy crude oil. |
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Diluent Recovery Unit |
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USD’s patented diluent recovery unit, or DRU, technology separates
the diluent that has been added to raw bitumen in the production
process. |
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DRUbit™ |
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DRUbit™ is crude oil or bitumen that has been returned to a more
concentrated, viscous state that is classified as a non-hazardous,
non-flammable commodity when transported by rail in Canada and the
United States. |
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Ethanol |
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A clear, colorless, flammable oxygenated liquid typically produced
chemically from ethylene, or biologically from fermentation of
various sugars from carbohydrates found in agricultural crops and
cellulosic residues from crops or wood, which is used in the United
States as a gasoline octane enhancer and oxygenate. |
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Heavy crude |
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A crude oil with a low API Gravity characterized by high relative
density and viscosity. Heavy crude oils require greater levels of
processing to produce high value products such as gasoline and
diesel. |
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Crude-by-rail |
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The transportation of hydrocarbons, such as crude oil and ethanol,
by rail, particularly through the use of unit trains. |
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Manifest train |
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Trains that are composed of mixed cargos and often stop at several
destinations. |
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Oil sands |
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Deposits of loose sand or partially consolidated sandstone that are
saturated with highly viscous bitumen, such as those found in
Western Canada. |
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Renewable diesel |
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Refers to a biomass-derived transportation fuel suitable for use in
diesel engines that meets ASTM D975 specification for petroleum
diesel. It is a hydrocarbon produced through various processes such
as hydrotreating, gasification, pyrolysis, and other biochemical
and thermochemical technologies. |
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Throughput |
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The volume processed through a terminal or refinery. |
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Unit train |
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Refers to trains comprised of up to 120 railcars and are composed
of one cargo shipped from one point of origin to one
destination. |
RISK FACTOR SUMMARY
The following is a summary of the material factors that make an
investment in our common units speculative or risky, all of which
are more fully described in the section titled Item
1A.
Risk
Factors
in Part I of this Annual Report. This summary should not be relied
upon as an exhaustive summary of the material risks facing our
business. You should consider the information set forth in the
“Risk Factors” section and the other information contained in this
Annual Report before investing in our securities.
•We
depend on a limited number of customers for a significant portion
of our revenues.
•Our
contracts are subject to renewal risks and reductions in volume
commitments.
•The
lack of diversification of our assets and geographic locations
could adversely affect us.
•Our
business is subject to the risk of a capacity overbuild of
midstream infrastructure and the entrance of new competitors in the
areas where we operate.
•Adverse
developments affecting the oil and gas industry or drilling
activity could cause a reduction of volumes transported through our
terminals.
•Any
reduction in our or our customers’ ability to utilize third-party
storage facilities, pipelines, railroads or trucks that
interconnect with our terminals could negatively impact customer
volumes and renewal rates at our terminals.
•Increases
in rail freight costs may adversely affect our results of
operations.
•Our
business could be adversely affected from the impact and effects of
public health crises, pandemics and endemics, such as the COVID-19
pandemic.
•Our
business involves many hazards and operational risks, which may
cause disruptions, expose us to significant liabilities and not be
fully covered by insurance.
•If
we are unable to make acquisitions on economically acceptable terms
our future growth would be limited.
•Our
right of first offer to acquire certain of USD’s assets and
projects is limited and subject to uncertainty.
•Growing
our business by constructing new assets subjects us to construction
risks.
•Our
intent to distribute a significant portion of our available cash
could limit our ability to pursue growth projects and make
acquisitions.
•Our
ability to make cash distributions is subject to risks, including
that we may not have sufficient cash from operations to pay
distributions.
•Our
general partner may modify or revoke our cash distribution policy
at any time and our partnership agreement does not require us to
pay any distributions at all.
•Restrictions
in our senior secured credit agreement, or Credit Agreement, as
defined in Part II. Item 8. Financial Statements and Supplementary
Data,
Note 11.
Debt
in this Annual Report,
could adversely affect us and our ability to make
distributions.
•Our
ability to refinance our Credit Agreement before its maturity in
November 2023, is not certain and depends on, among other factors,
our financial condition and operating performance.
•Tightened
capital markets or increased competition for investment
opportunities could impair our ability to grow.
•Our
debt may limit our flexibility to obtain financing and to pursue
other business opportunities.
•We
may issue additional units without unitholder approval, which would
dilute unitholder interests.
•Some
of our customers’ operations are subject to cross-border
regulation.
•Changes
in provincial royalty rates and drilling incentive programs in
Canada could adversely affect the demand for our terminalling
services.
•Our
business could be adversely affected if service on the railroads is
interrupted or if more stringent regulations are adopted regarding
railcar design or the transportation of crude oil by
rail.
•We
operate in a highly regulated industry, which may expose us to
significant costs and liabilities.
•Legislation,
regulatory initiatives, litigation and investor sentiment relating
to the oil and gas industry or climate change could have an adverse
effect on us.
•The
credit and risk profile of our general partner could adversely
affect our credit ratings and risk profile.
•There
are risks inherent in our master limited partnership ownership
structure, including the limited duties owed to us and our
unitholders by our general partner and limitations on its
liability, potential conflicts between us and our general partner,
and unitholders’ limited voting rights and inability to remove our
general partner without its consent or prevent the transfer of our
general partner to a third party.
•The
New York Stock Exchange does not require us to comply with certain
of its corporate governance requirements.
•Our
status as a partnership for U.S. federal income tax purposes, or
our ability to take certain of the positions we take for U.S.
federal income tax purposes, may be successfully challenged or
changed by law, by judicial interpretation, or by administrative
action.
•We
are still required to pay non U.S. taxes and may be subject to
significant federal, state and local taxes.
•Our
unitholders’ share of our income will be taxable to them for U.S.
federal income tax purposes even if they do not receive any cash
distributions from us.
•Corporate
income tax on our subsidiary, which is treated as a corporation for
U.S. federal income tax purposes, reduces our cash available for
distributions.
•If
the IRS makes audit adjustments to our income tax returns, current
and former unitholders may be required to indemnify us for any
taxes (including any applicable penalties and interest) resulting
from such audit adjustments we pay on such unitholders’
behalf.
•Ownership
of our common units is subject to certain tax-related risks,
including that tax gain or loss on the disposition of our common
units could be more or less than expected, certain actions that we
may take may increase the U.S. federal income tax liability of
unitholders, and there are limits on the deductibility of our
losses by unitholders.
•Tax-exempt
entities and non-U.S. persons face potentially adverse tax
consequences from owning our common units.
•As
a result of investing in our common units, you may become subject
to state, local and foreign taxes and return filing requirements in
jurisdictions where we operate or own or acquire
properties.
•Increases
in interest rates could adversely affect us.
•We
may recognize impairment on long-lived assets and intangible
assets.
•Terrorist
or cyber-attacks and threats could have a material adverse effect
on us.
•If
we fail to maintain an effective system of internal controls, we
may not be able to report our financial results timely and
accurately or prevent fraud.
PART I
Item 1. Business
OVERVIEW
We are a fee-based, growth-oriented master limited partnership
formed in 2014 by US Development Group LLC, or USD, to acquire,
develop and operate midstream infrastructure and complementary
logistics solutions for crude oil, biofuels and other
energy-related products. We generate substantially all of our
operating cash flows from multi-year, take-or-pay contracts with
primarily investment grade customers, including major integrated
oil companies, refiners and marketers. Our network of crude oil
terminals facilitates the transportation of heavy crude oil from
Western Canada to key demand centers across North America. Our
operations include railcar loading and unloading, storage and
blending in onsite tanks, inbound and outbound pipeline
connectivity, truck transloading, as well as other related
logistics services. We also provide our customers with leased
railcars and fleet services to facilitate the transportation of
liquid hydrocarbons by rail.
We generally do not take ownership of the products that we handle
nor do we receive any payments from our customers based on the
value of such products. On occasion we enter into buy-sell
arrangements in which we take temporary title to commodities while
in our terminals. We expect any such arrangements to be at fixed
prices where we do not take commodity price exposure.
We believe rail will continue as an important transportation option
for energy producers, refiners and marketers due to its unique
advantages relative to other transportation means. Specifically,
rail transportation of energy-related products provides flexible
access to key demand centers on a relatively low fixed-cost basis
with faster physical delivery, while preserving the specific
quality of customer products over long distances. As the role of
biofuels continues to expand in the clean energy transition, we are
committed to offering new capabilities and services across growing
demand in clean fuels to include ethanol, renewable diesel and
biodiesel.
USD Group LLC, or 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. During 2021, USD, along
with its joint venture partner, successfully completed construction
on and placed into service a diluent recovery unit, or DRU, near
Hardisty, Alberta, Canada, as a part of a long-term solution to
transport heavier grades of crude oil produced in Western Canada by
rail, discussed in more detail below. USD believes the DRU project
will maximize benefits to producers, refiners and railroads.
Additionally, in January 2019, USDG completed an expansion project
at the Partnership’s Hardisty Terminal, or 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,
which we acquired in April 2022. USDG is also 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. In addition, USD Clean Fuels LLC, or
USDCF, a subsidiary of USD, was organized in 2021 for the purpose
of providing production and logistics solutions to the growing
market for clean energy transportation fuels, as discussed below in
further detail.
The following table summarizes information about our current
terminalling facility assets:
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Terminal Name |
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Location |
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Designed
Capacity
(Bpd) |
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Commodity
Handled |
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Primary
Customers |
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Terminal
Type
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Hardisty Terminal
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Alberta, Canada |
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~262,500
(1)
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Crude Oil |
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Producers/Refiners
/Marketers |
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Origination |
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Casper Terminal
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Wyoming, U.S. |
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~105,000
(2)
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Crude Oil |
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Refiners/Marketers |
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Origination |
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Stroud Terminal |
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Oklahoma, U.S. |
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~50,000
(3)
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Crude Oil |
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Producers |
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Destination |
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West Colton Terminal |
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California, U.S. |
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13,000 |
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Ethanol/Renewable Diesel |
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Refiners/Blenders |
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Destination |
(1)Represents
the capacity of the combined Hardisty Terminal which includes the
legacy Hardisty Terminal and the Hardisty South Terminal. The
designed capacity is based on three and one-half 120-railcar unit
trains comprised of 28,371 gallon (approximately 675.5 barrels, or
bbls) railcars being loaded at 92.5% of volumetric capacity per
day. Actual amount of crude oil loading capacity may vary based on
factors including the size of the unit trains, the size, type and
volumetric capacity of the railcars utilized and the type and
specifications of crude oil loaded, among other
factors.
(2)Based
on one and one-half 112-railcar unit trains comprised of 28,371
gallon (approximately 675.5 bbls) railcars being loaded at 92.5% of
volumetric capacity per day. Actual amount of crude oil loading
capacity may vary based on factors including the size of the unit
train, the size, type and volumetric capacity of the railcars
utilized and the type and specifications of crude oil loaded, among
other factors.
(3)Our
current Stroud Terminal capacity of approximately 50,000 Bpd
includes pipeline pumping capacity constraints on the pipeline that
is utilized to move crude oil between our Stroud Terminal storage
tanks and third-party storage tanks at Cushing. With pump
modifications, the 104-railcar unit train could unload up to 65,000
Bpd based on 28,371 gallon (approximately 675.5 bbls) railcars
being unloaded at 92.5% of volumetric capacity per day. Actual
amount of crude oil loading capacity may vary based on factors
including the size of the unit train, the size, type and volumetric
capacity of the railcars utilized and the type and specifications
of crude oil unloaded, among other factors.
We offer our terminalling services pursuant to multi-year,
take-or-pay agreements primarily with high quality, investment
grade customers. Our agreements typically range in term between
three and ten years and include renewal options. As of
December 31, 2022, the volume-weighted average remaining
contract life of our take-or-pay terminal service agreements was
7.1 years. Refer to the
Business Segments
section below for further information regarding our customer
contracts for each of our rail terminals.
In addition to terminalling services, we currently provide a
customer with leased railcars and fleet services related to the
transportation of liquid hydrocarbons by rail on a take-or-pay
basis. In the aggregate, our master fleet services agreement has a
remaining contract life of six months as of
December 31, 2022. Although we expect to continue to
assist our customers in obtaining railcars for their use
transporting crude oil to or from our terminals, we do not intend
to continue to act as an intermediary between railcar lessors and
our customers as our existing lease agreement expires. Should
market conditions change, we could potentially act as an
intermediary with railcar lessors on behalf of our customers again
in the future.
We believe one of our key strengths is our relationship with our
sponsor, USDG, the sole direct subsidiary of USD. USD was among the
first companies to successfully develop the hydrocarbon-by-rail
concept and has built or operated unit train-capable terminals with
an aggregate capacity of over one million bpd. Ten of these
terminals were subsequently sold in multiple transactions for an
aggregate sales price in excess of $740 million. From January
2006 through December 2022, USD has loaded or handled through
its terminal network a total of approximately 450 million
barrels, or MMbbls, of liquid hydrocarbons and biofuels. USD also
has a nationally recognized safety record with only one recordable
injury, that did not result in lost time, and one reportable spill
at its terminals since 2008, as defined by the regulatory agencies
with applicable jurisdiction, including in the United States the
Occupational Safety and Health Administration, or OSHA, the U.S.
Department of Transportation, or DOT, and the Pipeline and
Hazardous Materials Safety Administration, or PHMSA. There have
been no reportable injuries or spills associated with the
Partnership’s assets. USD is currently owned by Energy Capital
Partners, Goldman Sachs and certain of USD’s management team
members.
In September 2014, Energy Capital Partners made a significant
investment in USD. Energy Capital Partners, together with its
affiliates and affiliated funds, is a private equity firm with over
$27.0 billion in capital commitments that primarily invests in
North America’s energy infrastructure. Energy Capital Partners has
significant energy infrastructure, midstream, master limited
partnership and financial expertise to complement its investment in
USD. To date, Energy Capital Partners and its affiliated funds have
61 investment platforms with investments in the renewable and power
generation, environmental infrastructure and midstream sectors of
the energy industry.
USD, through its direct ownership of USDG, has stated that it
intends for us to be its primary growth vehicle in North America.
We intend to strategically expand our business by acquiring
energy-related logistics assets related to the storage and
transportation of liquid hydrocarbons and biofuels from both USDG
and third parties, to the extent opportunities exist that are
accretive to our unitholders. We also intend to grow organically by
opportunistically pursuing growth projects and enhancing the
profitability of our existing assets. We believe that our
relationship with USD and its successful project development and
operating history, safety track record and industry relationships
provide us with many avenues to execute our growth
strategy.
The following chart depicts a simplified organization and ownership
structure as of December 31, 2022. The ownership
percentages referred to below illustrate the relationships among
us, our general partner, USDG, USD, Energy Capital Partners and
Goldman Sachs, and excludes 1,438,355 phantom unit awards, or
Phantom Units, outstanding under our Long-Term Incentive Plan at
December 31, 2022.
BUSINESS STRATEGY
Our primary business objective is to generate sustainable free cash
flow to strengthen our financial position and prudently grow the
quarterly cash distributions we make to our unitholders over time.
We intend to accomplish this objective by executing the following
business strategies:
• Generate
stable and predictable fee-based cash
flows. A
substantial amount of the operating cash flow we expect to generate
is attributable to multi-year, take-or-pay agreements. We intend to
seek stable and predictable cash flows by extending the term of our
agreements with existing customers, as well as executing additional
multi-year, take-or-pay agreements with existing and new customers
across our terminal network.
• Pursue
accretive acquisitions. We
intend to pursue strategic and accretive acquisitions of
energy-related logistics assets related to the storage and
transportation of liquid hydrocarbons and biofuels from both USD
and third parties. We regularly evaluate and monitor the
marketplace to identify acquisitions and expansions that may be
pursued independently or jointly with USD.
• Pursue
organic growth initiatives and expansions. We
intend to pursue organic growth opportunities and seek operational
efficiencies that complement, optimize or improve the profitability
of our assets. For example, as the role of biofuels continues to
expand in the clean energy transition, we are committed to offering
new capabilities and services across growing demand in clean fuels
to include ethanol, renewable diesel and biodiesel.
• Maintain
a conservative capital structure. We
intend to maintain a conservative capital structure which, when
combined with our focus on stable, fee-based cash flows, should
support access to capital at a competitive cost, subject to market
conditions. Consistent with our disciplined financial approach, we
intend to fund the capital required for expansion and acquisition
projects through a balanced combination of equity and debt
financing. We believe this approach may provide us with the
flexibility to effectively pursue accretive acquisitions and
organic growth projects as they become available.
• Maintain
safe, reliable and efficient operations. We
are committed to safe, efficient and reliable operations that
comply with environmental and safety regulations. We strive to
continually improve operating performance through our commitment to
technologically-advanced logistics and operations systems, employee
training programs and other safety initiatives and programs with
railroads, railcar producers and first responders. All of our
facilities currently meet or exceed applicable government safety
regulations and are in compliance with recently enacted orders
regarding the movement of liquid hydrocarbons and biofuels by rail.
We believe these objectives are integral to the success of our
business as well as to our access to growth
opportunities.
BUSINESS SEGMENTS
We conduct our business through two distinct reporting segments:
Terminalling services and Fleet services.
These segments have unique business activities that require
different operating strategies. For information relating to
revenues from external customers, operating income or loss and
total assets for each segment, refer to
Note 15.
Segment Reporting
of our consolidated financial statements included in Part
II,
Item 8. Financial Statements and Supplementary Data
of this Annual Report. For information relating to revenues from
material customers, refer to
Note 17.
Major Customers and Concentration of Credit Risk
of our consolidated financial statements included in Part
II,
Item 8.
Financial Statements and Supplementary Data
of this Annual Report.
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. These services are primarily
provided under multi-year, take-or-pay agreements that include
minimum monthly commitment fees. We generally have no direct
commodity price exposure, although changes in crude oil prices
could indirectly influence our activities and results of operations
over the long term. We may on occasion enter into buy-sell and
other arrangements in which we take temporary title to commodities
while held in our terminals. We expect any such agreements to be at
fixed prices where we do not take commodity price
exposure.
Our Terminalling services business consists of the following
operations:
Hardisty Terminal
Our Hardisty Terminal, which commenced operations in June 2014, is
an origination terminal where we load various grades of Canadian
crude oil onto railcars for transportation to end markets. Hardisty
is one of the major crude oil hubs in North America and is an
origination point for several major export pipelines to the United
States. In April 2022, we completed the acquisition of 100% of the
entities owning the Hardisty South Terminal assets from USDG. The
new combined Hardisty Terminal, which includes our legacy Hardisty
Terminal and the newly acquired Hardisty South Terminal, now has
the designed takeaway capacity of three and one-half unit trains
per day, or approximately 262,500 barrels per day and consists of a
fixed loading rack with approximately 60 railcar loading positions,
a unit train staging area and loop tracks capable of holding five
unit trains simultaneously. The terminal is also equipped with an
onsite vapor management system that allows our customers to
minimize hydrocarbon loss while improving safety during the loading
process. Our Hardisty Terminal receives inbound deliveries of crude
oil through a direct pipeline connection from Gibson Energy Inc.’s,
or Gibson’s, Hardisty storage terminal. Gibson is one of the
largest independent midstream companies in Canada with almost 14
MMbbls of crude oil storage facilities at Hardisty plus the
greatest number of connections to inbound and outbound pipelines in
the Hardisty hub. Our Hardisty Terminal’s strategic location and
direct pipeline connection to substantial storage capacity provides
efficient access to the major producers in the region. Our Hardisty
Terminal is also connected to the Canadian Pacific Railway’s North
Main Line, a high capacity line with the ability to service key
refining markets across North America.
We have a facilities connection agreement with Gibson under which
Gibson operates and maintains a 24-inch diameter pipeline and
related facilities connecting Gibson’s storage terminal with our
Hardisty Terminal, which we operate and maintain. Gibson is
responsible for transporting product through the pipeline to our
Hardisty Terminal. This pipeline from 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 also 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 the Hardisty Terminal based on a
predetermined formula. The facilities connection agreement also
gives Gibson a right of first refusal in the event of a sale of our
Hardisty Terminal to a third party. The agreement will expire in
2034 unless renewed. Our and Gibson’s obligations under this
facilities connection agreement may be suspended in the case of a
force majeure event. Additionally, the agreement may be terminated
by the non-defaulting party in case of specified events of
default.
The combined contracted terminalling capacity at our Hardisty
Terminal is contracted under multi-year, take-or-pay Terminal
Services Agreements with four customers, including major integrated
oil companies, refiners and marketers. Contracts representing
approximately 26% of the combined Hardisty Terminal’s capacity
expired in June 2022. Approximately 54% of the capacity is
contracted through June 30, 2023 and approximately 31% is
contracted through January 2024. Additionally, due to the
successful commencement of USD’s DRU and Port Arthur Terminal, or
PAT, projects discussed in more detail below, approximately 17% of
the combined capacity of the Hardisty Terminal was contracted
through mid-2031.
Our Terminal Services Agreements generally include automatic
renewal provisions for periods up to one-year following the
conclusion of the initial term and will only terminate if written
notice is given by either party within a specified time period
before the end of the initial term or a renewal term. Some of our
Terminal Services Agreements contain annual inflation-based rate
escalators based upon the consumer price index of either Canada or
Alberta. If a force majeure event occurs, a customer’s obligation
to pay us may be suspended, in which case the length of the
contract term will be extended by the same duration as the force
majeure event. We will not be liable for any losses of crude oil
handled at our Hardisty Terminal unless due to our
negligence.
Under the Terminal Services Agreements we have entered into with
customers of our Hardisty Terminal, our customers are obligated to
pay the greater of a minimum monthly commitment fee or a throughput
fee based on the actual volume of crude oil loaded at our Hardisty
Terminal. If a customer loads fewer unit trains or barrels than its
allotted amount in any given month, that customer will receive a
credit for up to 12 months, which may be used to
offset fees on throughput volumes in excess of its minimum monthly
commitments in future periods, to the extent capacity is available
for the excess volume.
Sponsor and USD’s
Initiatives at Hardisty
USD’s
Diluent Recovery Unit and Port Arthur Terminal
In December 2019, USD and Gibson jointly announced an agreement and
formed a 50%/50% joint venture to construct and operate a diluent
recovery unit, or DRU, located adjacent to the Partnership’s
Hardisty Terminal. A subsidiary of ConocoPhillips contracted to
process 50,000 barrels per day of dilbit through the DRU to produce
and ultimately ship bitumen by rail to USD’s newly constructed Port
Arthur Terminal, or PAT, on the U.S. Gulf Coast.
In December 2021, USD and Gibson jointly announced that the DRU has
been declared fully operational and the shipment of DRUbit™ by
Rail™, or DBR, has commenced. The DBR network creates a
first-of-its-kind separation technology and network that safely and
sustainably moves heavy Canadian crude oil, also known as bitumen,
from Canada to the U.S. Gulf Coast at a cost that is competitive
with pipeline alternatives. The DBR network is highly scalable and
is well-positioned for future commercial expansions. USD and Gibson
continue to pursue commercial discussions with current and
potential producer and refiner customers to secure additional
long-term agreements to support future expansions at both the DRU
and the PAT.
USD’s patented DRU technology separates the diluent that is added
to raw bitumen in the production process, which meets two important
market needs. It creates DRUbit™, a proprietary heavy Canadian
crude oil or bitumen that ships by rail and does not meet any of
the defined categories of hazardous materials by U.S. DOT Hazardous
Materials regulations and Canada’s Transport of Dangerous Goods
regulations, creating safety and environmental benefits.
Additionally, it returns the recovered diluent for reuse in the
Western Canadian market, which reduces delivered costs for diluent.
The DBR network provides meaningful safety, economic and
environmental benefits relative to conventional crude by rail. The
DBR network is supported by Canadian Pacific and Kansas City
Southern Railway Company. As the initial destination terminal, PAT
is unloading DRUbit™, blending it to customers’ specifications, and
is currently delivering it downstream through pipe or barge at or
above current contractual requirements. PAT has significant marine,
pipeline, rail and tank expansion capabilities and it is pipeline
connected to Phillips 66’s Beaumont Terminal, providing customers
access to a large network of refining and marine facilities. We
believe PAT has the infrastructure and ability to support growth,
including allowing for efficient rail movements along mainlines
from Canada and into the growing Mexico market, as discussed
below.
Port Arthur Terminal
PAT has the capability for rail unloading, barge dock loading and
unloading, tank storage and blending and is pipeline connected to
Phillips 66’s Beaumont Terminal, providing customers access to a
large network of refining and marine facilities. The facility can
handle DRUbit™, Dilbit and a heavy Canadian conventional barrel and
manage the blending of DRUbit™ into a marketable product for
shippers. The marine and pipeline delivery options for blended
products at the terminal allows customers to enhance market
flexibility and take advantage of cost advantaged delivery options.
PAT is served by the Kansas City Southern railroad and sits on
exclusive rail infrastructure, providing seamless scheduling,
operations, and communications resulting in ratable and reliable
service. Within the 233-acre terminal footprint, there is ample
waterfront and upland acreage that allows PAT expansion
capabilities to accommodate any foreseeable demand.
We believe the PAT project is well positioned in a market poised
for growth. The Port Arthur market is home to over 1.6 million
barrels of refining capacity per the EIA and a growing
petrochemical market. With ExxonMobil’s 250,000 barrel per day
refinery expansion which is expected to be in service sometime in
the first half of 2023, and Motiva’s acquisition of the Flint Hills
ethane cracker dovetailing into planned downstream expansions into
the petrochemical market, Port Arthur’s heavily utilized midstream
infrastructure can expect liquid volumes to increase.
Within the Port Arthur market, PAT will be well positioned to take
advantage of these opportunities and other organic growth projects.
Pipeline connectivity to the hub of Port Arthur’s liquids business
provides an advantage through reduced costs to deliver crude
locally relative to a barge alternative and will extend the market
reach for
customers of PAT. Customers of PAT are able to deliver barrels by
pipeline and water into the Houston and Louisiana
markets.
Benefits to the Partnership
The successful completion of USD’s Hardisty DRU project enhanced
the sustainability and quality of the Partnership’s cash flows by
significantly increasing the average tenor of Terminal Services
Agreements at our Hardisty Terminal. The average remaining terms of
our three Terminal Services Agreements with ConocoPhillips at the
combined Hardisty Terminal were extended through mid-2031,
representing approximately 17% of the combined Hardisty Terminal’s
capacity. We expect that future customers of the Hardisty DRU
project will enter into similar long-term, more sustainable
commitments for terminalling services at the Partnership’s Hardisty
Terminal. USD’s interest in the Hardisty DRU and PAT projects would
also be available for possible acquisition by the Partnership, and
would be subject to the terms and conditions of the Partnership’s
ROFO on USD’s assets pursuant to the Omnibus Agreement between USD
and the Partnership, which extends through October 15,
2026.
Effective August 2021, the existing DRU customer elected to reduce
its volume commitments at the Stroud Terminal attributable to the
Partnership by one-third of the previous commitment through June
2022, at which point the agreement terminated and there was no
renewal period. Management believes that the lower utilization at
the Stroud Terminal as a result of successful completion of the DRU
project will be short-term in nature, and will allow the
Partnership the opportunity to offer terminalling services to other
customers that may be in need of access to the numerous markets
connected to the Cushing oil hub. If and to the extent we continue
to be unable to replace our customer at the Stroud Terminal, our
revenue, cash flows from operating activities and Adjusted EBITDA
will be further materially adversely impacted. Refer to
Growth
Opportunities for our Operations
- Other Opportunities Related to Our Crude Oil Terminal Network -
Stroud Terminal
included in Part II,
Item 7. Management’s Discussion and Analysis of Financial
Condition and Results of Operations
of this Annual Report for further details. Additionally, refer to
Item
1A.Risk
Factors
of this Annual Report for further discussion of certain risks
relating to our customer contract renewals.
Stroud Terminal
Our Stroud Terminal, which we purchased in June 2017, is a crude
oil destination terminal in Stroud, Oklahoma. We use the terminal
to facilitate rail-to-pipeline shipments of crude oil from our
Hardisty Terminal in Western Canada 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. We
have also secured 300,000 bbls of crude oil tank storage at the
Cushing hub to facilitate outbound shipments of crude oil from the
Stroud Terminal. Inbound product is delivered by the Stillwater
Central Rail, which handles deliveries from both the BNSF Railway,
or BNSF, and the Union Pacific Railroad, or UP.
Our Stroud Terminal is the only rail facility connected to the
Cushing storage hub, which provides for strategic and competitive
advantages. The benchmark price in the domestic spot market for
U.S. crude oil known as West Texas Intermediate, or WTI, is set at
the Cushing hub. According to the EIA, the Cushing storage hub has
approximately 78 million barrels of working storage capacity. There
is also an expansive pipeline infrastructure that connects into and
out of the Cushing hub. Because of the vast connectivity that
Cushing offers, crude oil that is delivered into Cushing can then
be delivered to either local refineries or it can be shipped to
other markets such as the United States Gulf Coast, which is the
largest refinery complex in the U.S. As such, 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.
We own 50% of the Stroud Terminal’s current capacity. USD Marketing
LLC, or USDM, a wholly-owned subsidiary of USDG, owns the rights to
the other 50% of the Stroud Terminal’s current capacity, pursuant
to the Marketing Services Agreement, or MSA, that we entered into
in May 2017 at the time of the acquisition of the terminal. Under
the MSA, 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 earnings
before interest, taxes, depreciation and amortization, or 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. The capacity attributable
to USDM is currently not under any contracted
agreements.
To facilitate marketing the capacity that is currently available at
the Stroud Terminal, USDM has expanded the downstream connectivity
at our Stroud Terminal and added a pipeline connection to a second
storage tank at a third-party facility at the Cushing, Oklahoma
crude oil hub, or the Cushing Hub. The expanded connectivity
facilitates incremental rail-to-pipeline shipments of crude oil to
the Cushing Hub by giving the Stroud Terminal better capability to
service multiple customers and/or grades of crude oil
simultaneously including the unloading of multiple grades of
dilbit. Additionally, this development project is wholly-owned by
USDG and is subject to the terms and conditions of our existing
ROFO, should USDG propose to sell or transfer the
asset.
Casper Terminal
The Casper Terminal, which we acquired in November 2015, is a crude
oil storage, blending and railcar loading terminal located in
Casper, Wyoming, where the Express pipeline from Western Canada
(~280,000 bpd of capacity) interconnects with the Platte Pipeline
to Wood River, Illinois (~145,000 bpd of capacity). The Casper
Terminal currently offers six storage tanks with 900,000 bbls of
total capacity, unit train-capable railcar loading capacity in
excess of 100,000 bpd, as well as truck transloading capacity. The
terminal’s approximately 300-acre footprint and modular design
allow for the addition of a second loading station and an
additional 1.1 MMbbls of storage capacity with minimal disruption
to existing operations and relatively low incremental capital
costs.
Inbound crude oil is delivered to the Casper Terminal primarily
through our dedicated 24-inch diameter, six-mile direct pipeline
connection from the Express pipeline, which provides our customers
with access to multiple grades of Canadian crude oil. 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. Inbound volumes are typically fed directly into the
customer’s dedicated storage tank(s), which enhances their ability
to control the quality of the product from origin to end market.
This also allows customers to blend multiple grades of crude oil to
optimize the economics associated with refining varying grades of
crude oil.
Outbound crude oil from our Casper Terminal is loaded onto railcars
and is then transported to end markets by BNSF, in either manifest
or unit train shipments. The terminal’s location on BNSF’s main
line offers advantageous transportation costs to key U.S. refining
markets where several customer-preferred destinations are also
served by BNSF. Shipping with a single Class 1 railroad reduces
railroad switching fees and enables faster train turn-times, thus
improving railcar fleet utilization. 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.
We provide service at the Casper Terminal under a Terminal Services
Agreement with a midstream customer. The agreement contains
take-or-pay terms for storage services and variable fees associated
with actual throughput volumes and other services. Additionally, we
are currently utilizing our available storage and throughput
capacity to support our customers’ spot activity through buy-sell
agreements that generate cash flows in addition to those provided
by our agreements.
West Colton Terminal
Our West Colton Terminal, which was initially completed in November
2009, is a unit train-capable destination terminal that can
transload up to 13,000 bpd of ethanol and renewable diesel received
from producers by rail onto trucks to meet local demand in the San
Bernardino and Riverside County-Inland Empire region of Southern
California. During 2021, we completed a modification project at our
West Colton Terminal so that it has the
capability to transload renewable diesel in addition to the ethanol
that it is was initially capable of transloading. The West Colton
Terminal has 20 railcar offloading positions and four truck loading
positions. Our terminal receives inbound deliveries exclusively by
rail on the UP high speed lines.
Ethanol Transloading
We receive fixed fees per gallon of ethanol transloaded at our
terminal pursuant to a Terminal Services Agreement with one of the
world’s largest producers of biofuels. Effective January 2022, we
entered into a new five-year agreement with the existing West
Colton ethanol customer that has a minimum monthly throughput
commitment. This new agreement replaced the previous short-term
agreement at the terminal that had been in place since July 2009
and is expected to add incremental “Net
Cash from Operating Activities”
over the previous agreement, subject to changes in expected
throughput. Refer to
Part II, Item 7. Management’s Discussion and Analysis,
Factors
Affecting the Comparability of Our Financial Results
of this Annual Report for further information. Under this new
agreement, our customer is obligated to pay the greater of a
minimum monthly commitment fee or a throughput fee based on the
actual volume of ethanol loaded at our West Colton Terminal. If the
customer loads fewer volumes than its allotted amount in any given
month, that customer will receive a credit for up to six months,
which may be used to offset fees on throughput volumes in excess of
its minimum monthly commitments in future periods, to the extent
capacity is available for the excess volume.
Due to corrosion concerns unique to biofuels such as ethanol, the
long-haul transportation of biofuels by multi-product pipelines is
less efficient and less economical than transportation by rail. We
believe these corrosion concerns, combined with the proximity of
our terminals to local demand markets, strategically position our
terminal to benefit from anticipated changes in environmental and
gasoline blending regulations that are expected to increase the use
of ethanol in the market for transportation fuel.
Renewable Diesel Transloading
In June 2021, we entered into a new Terminal Services Agreement
with USD Clean Fuels LLC, or USDCF, a subsidiary of USD, that is
supported by a minimum throughput commitment to USDCF from an
investment-grade rated, refining customer as well as a performance
guaranty from USD. The Terminal Services Agreement provides for the
inbound shipment of renewable diesel on rail at our West Colton
Terminal and the outbound shipment of the product on tank trucks to
local consumers. The new Terminal Services Agreement has an initial
term of five years and commenced on December 1, 2021.
In exchange for the new Terminal Services Agreement at our West
Colton Terminal with USDCF discussed above, we also entered into a
Marketing Services Agreement with USDCF in June 2021, or the West
Colton MSA, pursuant to which we agreed to grant USDCF marketing
and development rights pertaining to future renewable diesel
opportunities associated with the West Colton Terminal in excess of
the Terminal Services Agreement with USDCF discussed
above.
Refer to
Part II, Item 8. Financial Statements and Supplementary
Data,
Note 13.
Transactions with Related Parties
of this Annual Report for further information.
For more information on USDCF, refer to
Part II, Item 7, Management’s Discussion and Analysis of Financial
Condition and Results of Operations,
Growth
Opportunities
for
our Operations,
Opportunities Related to Clean Energy Transportation Fuels, USD
Clean Fuels
of this Annual Report.
Fleet Services
We provide one of our customers with leased railcars and fleet
services related to the transportation of liquid hydrocarbons by
rail on a take-or-pay basis under a master fleet services
agreement. We do not own any railcars. As of
December 31, 2022, our railcar fleet consisted of 200
railcars, which we lease from a railcar manufacturer, all of which
are coiled and insulated, or C&I, railcars. Our C&I
railcars can reheat heavy viscous grades of crude oil, reducing the
need to blend these heavier grades with diluents. Our master fleet
services agreement has a remaining contract life of six months as
of December 31, 2022.
Under the master fleet services agreement, we provide a customer
with railcar-specific fleet services, which may include, among
other things, the provision of relevant administrative and billing
services, the repair and
maintenance of railcars in accordance with standard industry
practice and applicable law, the management and tracking of the
movement of railcars, the regulatory and administrative reporting
and compliance as required in connection with the movement of
railcars, and the negotiation for and sourcing of railcars. Our
customer typically pays us and our assignees monthly fees per
railcar for these services, which include a component for fleet
services.
All of our railcars currently in service were constructed in 2013
or later. The average age of our fleet currently in service is nine
years, as compared with the estimated 50-year life associated with
these types of railcars. Our current railcars are designed at a
minimum to be compliant with all regulatory railcar standards
currently in effect. We have partnered with leaders in the railcar
supply industry, such as CIT Rail, Union Tank Car Company and
others. We believe that our relationships with these industry
leaders enable us to obtain railcar market insight and to procure
railcars for our terminalling customers on beneficial terms, with
shorter lead times than some of our competitors.
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 to assist our customers in obtaining railcars for their
use transporting crude oil to or from our terminals, we do not
intend to continue to act as an intermediary between railcar
lessors and our customers as our existing lease agreement expires.
Should market conditions change, we could potentially act as an
intermediary with railcar lessors on behalf of our customers again
in the future.
BENEFITS OF RAIL
We believe that the following benefits of rail have established, or
have the potential to establish, rail as a preferred mode of
transportation for crude oil, biofuels, and other energy-related
products:
Market access for areas without adequate pipeline transportation
infrastructure.
Certain producing regions, such as the Western Canadian oil sands,
have concentrated production in areas without adequate existing
pipeline takeaway capacity. The extensive existing rail
infrastructure network provides additional takeaway capacity for
these producing regions and flexible access to multiple demand
centers.
Faster deployment.
Rail terminals can be constructed at a fraction of the time
required to lay a long-haul pipeline, providing a timely solution
to meet new and evolving market demands. Relative to rail, new
pipeline construction faces challenges such as lengthier build
times and more extensive environmental permitting processes,
geographic constraints and, in some cases, the lack of required
political and regulatory support.
Flexibility to deliver to different end markets.
Unlike pipelines, which typically transport product to a single
demand market, rail offers customers access to many of the most
advantageous demand centers throughout North America, enabling
producers and shippers to obtain competitive prices for their
products and to retain the flexibility to determine the ultimate
destination until the time of transportation.
Comprehensive solution for refiners.
Rail provides refiners flexible access to multiple qualities and
grades of crude oil (feedstock) from multiple production sources.
Additionally, shipping in railcars improves the customer’s ability
to preserve the specific quality of the product over long distances
relative to pipelines.
Faster delivery to demand markets.
Rail can transport energy-related products to end markets much
faster than pipelines, trucks or waterborne tankers. While a
pipeline can take 30-45 days to transport crude oil to the Gulf
Coast from Western Canada, unit trains can move crude oil along a
similar path in approximately nine days.
Reduced shipper commitment requirements.
Whereas all of the pipeline transportation fee is typically subject
to long-term shipper commitments, only a portion of rail
transportation costs require long-term shipper commitments
(railroads have historically been contracted on a spot basis or
only require partial term commitments). Consequently, pipeline
customers bear greater risk of shifts in regional price
differentials and the location of demand markets.
Reduced shipper transportation cost.
Rail provides shippers a competitive transportation option,
particularly in situations where either (i) the amount of diluent
required for the transportation of crude oil by pipeline is high,
which is generally the case for production from the Canadian oil
sands, or (ii) multiple modes of transportation are required to
reach a particular end market.
RIGHT OF FIRST OFFER
In October 2014, we entered into the Omnibus Agreement with USD and
USDG, pursuant to which we were granted a ROFO on any midstream
infrastructure assets that they may develop, construct, or acquire
for a period of seven years. In June 2021, we entered into an
Amended and Restated Omnibus Agreement with USD, USDG and certain
other of their subsidiaries, which amends and restates the Omnibus
Agreement, dated October 15, 2014, to extend the termination date
of the ROFO period, as defined in the Omnibus Agreement, by an
additional five years such that the ROFO Period will terminate on
October 15, 2026 unless a Partnership Change of Control,
as defined in the Omnibus Agreement, occurs prior to such date.
Additional information about the Omnibus Agreement and the ROFO are
included in
Note 13.
Transactions with Related Parties
of our consolidated financial statements in
Part II, Item 8. Financial Statements and Supplementary Data
of this Annual Report.
USD has not engaged in any transactions that trigger our ROFO. We
cannot assure you that USD will be able to develop or construct, or
that we or USD will be able to acquire, any additional midstream
infrastructure projects. Among other things, the ability of USD to
further develop the Stroud Terminal, the DRU project, or any other
project, and our ability to acquire such projects, will depend upon
USD’s and our ability to raise additional equity and debt
financing. We are under no obligation to make any offer, and USD
and USDG are under no obligation to accept any offer we make, with
respect to any asset subject to our ROFO. Additionally, the
approval of Energy Capital Partners is required for the sale of any
assets by USD or its subsidiaries, including us (other than sales
in the ordinary course of business), acquisitions of securities of
other entities that exceed specified materiality thresholds and any
material unbudgeted expenditures or deviations from our approved
budgets. Energy Capital Partners may make these decisions free of
any duty to us and our unitholders. This approval would be required
for the potential acquisition by us of any of USD’s projects, as
well as any other projects or assets that USD may develop or
acquire in the future or any third-party acquisition we may pursue
independently or jointly with USD. Energy Capital Partners is under
no obligation to approve any such transaction. Please refer to the
discussion in
Part III, Item 10.
Directors,
Executive Officers and Corporate Governance
— Special Approval Rights of Energy Capital Partners
of this Annual Report regarding the rights of Energy Capital
Partners. If we are unable to acquire any projects to expand the
Stroud Terminal from USD, such expansions may compete directly with
our existing business for future throughput volumes, which may
impact our ability to enter into new Terminal Services Agreements,
including with our existing customers, following the expiration of
our existing agreements, or the terms thereof, and our ability to
compete for future spot volumes. Furthermore, cyclical changes in
the demand for crude oil and other liquid hydrocarbons may cause
USD, or us, to further re-evaluate any future expansion projects,
including expansion of the Stroud Terminal.
COMPETITION
The energy-related logistics infrastructure business is highly
competitive. The ability to secure additional agreements for rail
terminal services is primarily based on the availability of
alternative means of transportation, primarily pipelines, as well
as the reputation, efficiency, flexibility, location, market
economics and reliability of the services provided and pricing for
those services.
Our crude oil terminals face competition from other logistics
services providers, such as pipelines and other terminalling
service providers. In addition, our customers may also choose to
construct or acquire their own terminals. If our customers choose
to ship crude oil via alternative means, we may only receive the
minimum monthly commitment fees at our terminals and may be unable
to renew, extend or replace customer agreements following
expiration of their terms. Our West Colton Terminal business faces
competition from other terminals and trucks that may be able to
supply end-user markets with ethanol and other biofuels on a more
competitive basis due to terminal location, price, rail rates,
versatility or services provided. Additionally, our West Colton
Terminal business faces competition from waterborne imports
including ethanol imports from Brazil as well as domestic
waterborne renewable diesel volumes delivered to California from
the U.S. Gulf Coast. The West Colton Terminal
is served by the UP and competes directly with ethanol facilities
in the Fontana, Carson and San Diego areas, which are served by the
BNSF Railway. A combination of rail freight and trucking economics,
which comprise the largest share of the value chain, make it very
difficult to compete with other facilities in this market based on
terminalling throughput fees alone.
We believe that we are favorably positioned to compete in our
industry due to the strategic location of our terminals, quality of
service provided at our terminals, our independent strategy, our
reputation and industry relationships, and the versatility and
complementary nature of our services. The competitiveness of our
service offerings could be significantly impacted by the entry of
new competitors into the markets in which we operate. However, we
believe that significant barriers to entry exist in the
energy-related logistics business. These barriers include
significant costs and execution risk, a lengthy permitting and
development cycle, financing challenges, shortage of personnel with
the requisite expertise, and a finite number of sites suitable for
development.
SEASONALITY
The amount of throughput at our terminals is affected by the level
of supply and demand for crude oil, refined products and biofuels,
as well as, to a lesser extent, seasonality. Demand for gasoline is
generally higher during the summer months than during the winter
months due to seasonal increases in highway traffic and
construction work. Production in Western Canada may be impeded by
severe winter conditions that reduce production and volumes.
However, many effects of seasonality on our revenues are
substantially mitigated due to our terminal service agreements with
our customers that include minimum monthly commitment fees, as well
as our master fleet services agreement which requires our customer
to pay a base monthly fee per railcar. Furthermore, because there
are multiple end markets for the crude oil and biofuels handled at
our terminals, the effect of seasonality otherwise attributable to
one particular end market is mitigated.
IMPACT OF REGULATION
General
Our operations are subject to complex and frequently-changing
federal, state, provincial and local laws and regulations regarding
the protection of health, property and the environment, including
laws and regulations that govern the handling and release of crude
oil and other liquid hydrocarbon materials. Compliance with
existing and anticipated environmental and safety laws and
regulations increases our overall cost of business, including our
capital costs to construct, maintain, operate, and upgrade
equipment and facilities. While these laws and regulations may
affect our maintenance capital expenditures and net income or loss,
customers typically place additional value on utilizing established
and reputable third-party providers to satisfy their terminal and
logistics needs. As a result, we expect increased regulations to
provide opportunities for us to increase our market share in
relation to customer-owned operations or smaller operators that
lack an established track record of safety and environmental
compliance.
Violations of environmental or safety laws or regulations can
result in the imposition of significant administrative, civil and
criminal fines and penalties, permit modifications or revocations,
and in some instances, operational interruptions or injunctions
banning or delaying certain activities. We believe our facilities
are in substantial compliance with applicable environmental and
safety laws and regulations. However, these laws and regulations
are subject to frequent change at the federal, state, provincial
and local levels, and the legislative and regulatory trend has been
to place increasingly stringent limitations on activities that may
affect the environment.
Our operations contain risks of accidental releases into the
environment, such as releases of crude oil, ethanol or hazardous
substances from our terminals. To the extent an event is not
covered by our insurance policies, such accidental releases could
subject us to substantial liabilities arising from environmental
cleanup and restoration costs, claims made by neighboring
landowners and other third parties for personal injury and property
damage, and fines or penalties for any related violations of
environmental or safety laws or regulations.
Air Emissions
Our operations are subject to and affected by the Clean Air Act, or
CAA, and its implementing regulations, as well as comparable state
and local statutes and regulations. Our operations are subject to
the CAA’s permitting
requirements and related emission control requirements relating to
specific air pollutants, as well as the requirement to maintain a
risk management program to help prevent accidental releases of
certain regulated substances. We are currently required to obtain
and maintain various construction and operating permits under the
CAA and have incurred capital expenditures to maintain compliance
with all applicable federal and state laws regarding air emissions.
We may, nonetheless, be required to incur additional capital
expenditures in the near future for the installation of certain air
pollution control devices at our terminals when regulations change,
when we add new equipment, or when we modify our existing
equipment. Our Canadian operations are similarly subject to federal
and provincial air emission regulations.
Our customers are also subject to, and similarly affected by,
environmental regulations restricting air emissions. These include
U.S. and Canadian federal and state or provincial actions to
develop programs for the reduction of greenhouse gas, or GHG,
emissions such as proposals to create a cap-and-trade system that
would require companies to purchase carbon dioxide emission
allowances for emissions at manufacturing facilities and emissions
caused by the use of the fuels sold. In addition, the U.S.
Environmental Protection Agency, or EPA, and the federal Bureau of
Land Management, or BLM, has begun to regulate emissions of carbon
dioxide and other GHGs. As a result of these regulations, our
customers could be required to undertake significant capital
expenditures, operate at reduced levels, and/or pay significant
penalties. These regulations’ impact on our oil and natural gas
exploration and production customers could result in a decreased
demand for the services that we provide. We are uncertain what our
customers’ responses to these emerging issues will be. Those
responses could reduce throughput at our terminals, as well as
impact our cash flows and our ability to make distributions or
satisfy debt obligations.
Climate Change
Following its December 2009 “endangerment finding” that GHG
emissions pose a threat to public health and welfare, the
Environmental Protection Agency, or EPA, has begun to regulate GHG
emissions under the authority granted to it by the federal CAA.
Based on these findings, the EPA has adopted regulations under
existing provisions of the federal CAA that require Prevention of
Significant Deterioration, or PSD, pre-construction permits and
Title V operating permits for GHG emissions from certain large
stationary sources that already are potential major sources of
certain principal, or criteria, pollutant emissions. Under these
regulations, certain facilities required to obtain PSD permits must
meet “best available control technology” standards for their GHG
emissions established by the states or, in some cases, by the EPA
on a case-by-case basis. The EPA has also adopted rules requiring
the monitoring and reporting of GHG emissions from specified
sources in the United States, including, among others, certain
onshore oil and natural gas processing and fractionating facilities
and onshore petroleum and natural gas gathering and boosting
activities as well as natural gas transmission pipelines. We
believe we are in substantial compliance with all GHG emissions
permitting and reporting requirements applicable to our
operations.
In response to studies suggesting that emissions of
CO2,
methane and certain other gases may be contributing to warming of
the Earth’s atmosphere, over 190 countries, including the United
States and Canada where we operate, committed to a legally binding
treaty to reduce GHG emissions, the terms of which were defined at
the Paris climate conference in December 2015. President Biden and
the Democratic Party, which has controlled Congress for the past
two years, have identified climate change as a priority, and it is
likely that new executive orders, regulatory action, and/or
legislation targeting greenhouse gas emissions, or prohibiting,
delaying or restricting oil and gas development activities in
certain areas, will be proposed and/or promulgated during the Biden
Administration. With the next Congress set to have a
Republican-controlled House of Representatives, the prospects for
additional federal legislation have dimmed significantly. However,
the Biden administration likely will continue to proceed with
executive and regulatory action.
During the first half of President Biden’s administration, Congress
and the Executive branch have issued actions to address greenhouse
gas emissions and oil and gas development. For example, in 2021 the
EPA proposed updated Clean Air Act performance standards governing
methane emissions from new and existing sources in the oil and gas
sector. In 2022, EPA issued a supplemental notice proposing to
increase emissions standards beyond the 2021 notice of proposed
rulemaking and proposing requirements for additional sources not
covered by the 2021 notice. Additionally, the Department of the
Interior, or DOI, issued an order preventing staff from producing
any new fossil fuel leases or permits without sign-off from a top
political appointee, and President Biden issued a
“pause” on new oil and gas leasing on federal lands and offshore
waters pending completion of a comprehensive review and
reconsideration of federal oil and gas permitting and leasing
practices. The leasing pause was challenged and was preliminarily
enjoined by the U.S. District Court for the Western District of
Louisiana. DOI resumed holding lease sales in compliance with the
district’s court order. The United States appealed. The United
States Court of Appeals for the Fifth Circuit vacated the
preliminary injunction and remanded the case. On remand, the
District Court issued a permanent injunction against the United
States, preventing it from implementing the “pause pending further
proceedings in the case. The DOI continues to hold lease sales in
accordance with the injunction and the Inflation Reduction Act,
subject to certain other court orders. DOI also issued a report on
the federal oil and gas leasing program indicating that the
Department would increase royalty and bonding rates, prioritize
leases in areas with known resource potential, and avoid issuing
leases where they may conflict with recreation, wildlife habitat,
conservation efforts, and historical and cultural resources.
Finally, DOI recently announced a proposed rule from the Bureau of
Land Management to reduce methane releases from venting, and leaks
from oil and gas production on public and tribal land.
Congress recently passed, and the President signed, the Inflation
Reduction Act, which included spending provisions and voluntary
programs focused on reducing greenhouse gas emissions. Congress
allocated billions of dollars for renewable energy production and
grid energy storage, electric vehicle incentives, reducing carbon
emissions in the industrial and transportation sectors, and
reducing methane emissions from the production and transportation
of natural gas, among other programs.
The Supreme Court recently issued
West Virginia v. EPA,
or
West Virginia,
a significant decision curtailing agency authority to enact
sweeping regulations without clear statutory authorization. In
2015, EPA issued the Clean Power Plan, which required coal and gas
power plants either to reduce their production of electricity or to
offset their production by subsidizing the generation of natural
gas, wind, or solar energy. The issue in
West Virginia
was whether the Clean Air Act empowered EPA to transform the
electric generation sector through the Clean Power Plan. The Court
held that Congress had not delegated broad authority to EPA under
the Clean Air Act to restructure the energy industry by requiring
existing power plants to shift to different forms of energy
production. In doing so, the Court reaffirmed the principle that
agency action with vast economic and political significance
requires a clear delegation from Congress. The Court’s application
of the “major questions doctrine” indicates its commitment to
limiting executive agencies’ regulation of particularly significant
matters to circumstances where Congress clearly delegated such
regulatory authority to the agency. The Court’s decision makes it
much more difficult for agencies to justify extraordinary and
far-reaching regulatory initiatives.
President Biden’s executive order also established climate change
as a primary foreign policy and national security consideration,
affirms that achieving net-zero greenhouse gas emissions by or
before mid-century is a critical priority, affirms President
Biden’s desire to establish the United States as a leader in
addressing climate change generally, further integrates climate
change and environmental justice considerations into government
agencies’ decision making, and eliminates fossil fuel subsidies,
among other measures. Additionally, some U.S. states are taking
measures to reduce GHG emissions. For example, a coalition of over
20 governors of U.S. states formed the United States Climate
Alliance to advance the objectives of the Paris treaty, and several
U.S. cities have committed to advance the objectives of the Paris
treaty at the state or local level. Increased costs associated with
compliance with any future legislation or regulation of GHG
emissions, if it occurs, may have a material adverse effect on our
results of operations, financial condition and cash flows. In
addition, climate change legislation and regulations may result in
increased costs not only for our business but also for our
customers, thereby potentially decreasing demand for our services.
Decreased demand for our services may have a material adverse
effect on our results of operations, financial condition and cash
flows. Finally, many scientists believe that increasing
concentrations of GHGs in the Earth’s atmosphere produce climate
changes that can have significant physical effects, such as
increased frequency and severity of storms, droughts and floods, as
well as other climatic events. If any such effects were to occur,
it is uncertain if they would have an adverse effect on our
financial condition and results of operations.
Waste Management and Related Liabilities
To a large extent, the environmental laws and regulations affecting
our operations relate to the release of hazardous substances or
solid wastes into soils, groundwater, and surface water, and
include measures to control
pollution of the environment. These laws generally regulate the
generation, storage, treatment, transportation, and disposal of
solid and hazardous waste. They also require corrective action,
including investigation and remediation, at a facility where such
waste may have been released or disposed.
Site Remediation. The
federal Comprehensive Environmental Response, Compensation, and
Liability Act, commonly referred to as CERCLA or the Superfund law,
and comparable state laws impose liability without regard to fault
or to the legality of the original conduct on certain classes of
persons regarding the presence or release of a “hazardous
substance” in (or into) the environment. Those persons include the
former and present owner or operator of the site where the release
occurred and the transporters and generators of the hazardous
substance found at the site. Under CERCLA, these persons may be
subject to joint and several liability for the costs of cleaning up
the hazardous substances and for damages to natural resources.
CERCLA also authorizes the EPA and, in some instances, third
parties, to act in response to threats to the public health or the
environment and to seek to recover the costs they incur from
the
responsible classes of persons. Claims filed for personal injury
and property damage allegedly caused by hazardous substances or
other pollutants released into the environment are not uncommon
from neighboring landowners and other
third parties. Petroleum products are typically excluded from
CERCLA’s definition of “hazardous substances.” In the ordinary
course of operating our business, we do not handle wastes that are
designated as hazardous substances and, as a result, we have
limited exposure under CERCLA for all or part of the costs required
to clean up sites at which hazardous substances have been released
into the environment. Costs for any such remedial actions, as well
as any related claims, could have a material adverse effect on our
maintenance capital expenditures and operating expenses to the
extent not covered by insurance. Canadian and provincial laws also
impose liabilities for releases of certain substances into the
environment.
We also currently own or lease properties where hydrocarbons are
currently handled or have been handled for many years. Although we
have utilized operating and disposal practices that were standard
in the industry at the time, petroleum hydrocarbons or other wastes
may have been disposed of or released on or under the properties
owned or leased by us, or on or under other locations where these
wastes have been taken for disposal. These properties and wastes
disposed thereon may be subject to CERCLA, the federal Resource
Conservation and Recovery Act, as amended, or RCRA, and comparable
state and Canadian federal and provincial laws and regulations.
Under these laws and regulations, we could be required to remove or
remediate previously disposed wastes (including wastes disposed of
or released by prior owners or operators), to clean up contaminated
property (including contaminated groundwater), or to perform
remedial operations to prevent future contamination. We have not
been identified by any state or federal agency as a Potentially
Responsible Party under CERCLA in connection with the transport
and/or disposal of any waste products to third-party disposal
sites.
We maintain insurance of various types with varying levels of
coverage that we consider adequate under the circumstances to cover
our operations and properties. Our insurance policies are subject
to deductibles and retention levels that we consider reasonable and
not excessive. Consistent with insurance coverage generally
available in the industry, in certain circumstances our insurance
policies provide limited coverage for losses or liabilities
relating to certain pollution events, including gradual pollution
or sudden and accidental occurrences.
Solid and Hazardous Wastes. Our
operations generate solid wastes, including some hazardous wastes,
which are subject to the requirements of RCRA and analogous state
and Canadian federal and provincial laws that impose requirements
on the handling, storage, treatment and disposal of hazardous
wastes. Many of the
wastes that we generate are not subject to the most stringent
requirements of RCRA because our operations generate primarily oil
and gas wastes, which currently are excluded from consideration as
RCRA hazardous wastes. EPA has excluded from regulation as
hazardous waste under RCRA produced waters and other wastes
intrinsically associated with the exploration, development, or
production of crude oil and natural gas. However, these oil and gas
exploration and production wastes may still be regulated under
state solid waste laws and regulations. Oil and gas wastes may be
included as hazardous wastes under
RCRA in the future, in which event our wastes as well as the wastes
of our competitors will be subject to more rigorous and costly
disposal requirements, resulting in additional capital expenditures
or operating expenses.
Water
The Federal Water Pollution Control Act, as amended, also known as
the Clean Water Act, or CWA, and analogous state and Canadian
federal and provincial laws impose restrictions and strict controls
regarding the discharge of pollutants into navigable waters of the
United States or into any type of water body in Canada, as well as
state and provincial waters. Federal, state and provincial
regulatory agencies can impose administrative, civil and/or
criminal penalties for non-compliance with discharge permits or
other requirements of the CWA and comparable laws, in addition to
requiring remedial action to clean up such water body and
surrounding land.
The regulatory scope of the CWA has been in flux since 2015. In
June 2015, the EPA and the Army Corps of Engineers, or Corps,
revised the definition of “waters of the United States,” or WOTUS,
in a manner which was widely viewed as expanding the jurisdictional
reach of all Clean Water Act programs. The 2015 rule was the
subject of litigation and various injunctions and never took effect
nationwide. In 2019, the U.S. District Court for the Southern
District of Georgia and the U.S. District Court for the Southern
District of Texas each held the 2015 rule to be unlawful and
remanded the rule to the agencies. In September 2019, the EPA and
the Corps repealed this rule and in January 2020 finalized a
revised WOTUS definition. The revised definition became effective
in June 2020. The 2020 rule was the subject of litigation and was
vacated by the U.S. District Court for the District of Arizona in
August 2021 and the U.S. District Court for the District of New
Mexico in September 2021. The EPA and the Corps currently are
implementing the pre-2015 regulatory regime and have proposed to
formally repeal the 2020 rule. The agencies have also indicated
that they still intend to propose a wholly new definition of WOTUS,
that takes into account stakeholder engagement and the experiences
implementing the pre-2015 rule, the Obama-era Clean Water Rule, and
the Trump-era Navigable Waters Protection Rule. Such proposed
definition is likely to share similarities with the more-expansive
definition from the 2015 rule.
The regulatory scope of the Clean Water Act, including any future
new definition, will likely be influenced by the Supreme Court’s
upcoming decision in Sackett v. EPA, concerning whether the CWA’s
scope reaches certain wetlands deemed adjacent to a traditional
navigable water or other water of the United States. The Supreme
Court will decide the appropriate test for determining whether
wetlands are “waters of the United States” under the CWA. The Court
heard oral argument in October 2022, and a decision is expected by
June 2023.
The Oil Pollution Act of 1990, or OPA, amended certain provisions
of the CWA, as they relate to the release of petroleum products
into navigable waters. OPA subjects owners of facilities to strict,
joint and potentially unlimited liability for containment and
removal costs, natural resource damages, and certain other
consequences of an oil spill. These laws impose regulatory burdens
on our operations. We believe that we are in substantial compliance
with applicable OPA requirements. State and Canadian federal and
provincial laws also impose requirements relating to the prevention
of oil releases and the remediation of areas affected by releases
when they occur. We believe that we are in substantial compliance
with all such federal, state and Canadian
requirements.
Endangered Species Act
The Endangered Species Act, or ESA, restricts activities that may
affect endangered species or their habitats. While some of our
facilities are in areas that may be designated as habitat for
endangered species, we believe that we are in substantial
compliance with the Endangered Species Act. However, the discovery
of previously unidentified endangered species could cause us to
incur additional costs or become subject to operating restrictions
or bans in the affected area. Similar protections are in place for
bald and golden eagles under the Bald and Golden Eagle Protection
Act and for migratory birds under the Migratory Bird Treaty Act.
DOI and the Department of Commerce have announced their intent to
repeal regulations finalized during the Trump Administration that
narrowed the definition of “habitat” under the ESA, set out the
process for determining exclusions from critical habitat
designations, and removed a provision stating that listing
determinations are made without reference to possible economic or
other impacts of such determination. As of June 2022, DOI has
proposed a rule removing language from the regulations that
restricts the introduction of experimental populations to only the
species’ “historical range” to allow for the introduction of
populations into habitats outside of their historical range for
conservation purposes. This proposed rule would expand the
definition of “habitat” under the ESA. The public comment period
closed in August 2022.
Rail Safety
We facilitate the transport of crude oil and related products by
rail in the United States and Canada. We do not own or operate the
railroads on which crude oil carrying railcars are transported;
however, we currently lease or manage a railcar fleet on behalf of
one of our customers. Accordingly, we are indirectly subject to
regulations governing railcar design and manufacture, and
increasingly stringent regulations pertaining to the shipment of
crude
oil by rail.
High-profile accidents involving crude oil unit trains in Quebec,
North Dakota, Virginia, West Virginia and Illinois have raised
concerns about the environmental and safety risks associated with
transporting crude oil by rail, and the associated risks arising
from railcar design.
In May 2015, the DOT, in coordination with Transport Canada,
finalized new rail safety rules. The final rule includes more
stringent and new construction standards for rail tank cars
constructed after October 1, 2015. The final rule also creates a
new North American tank car standard known as the DOT Specification
117 (DOT-117) with thicker steel and redesigned bottom outlet
valves, among other improvements, over the DOT-111 tank car. In
addition, the final rule includes mandates for using electronically
controlled pneumatic braking systems and for performing routing
analyses and imposes speed limits based on population centers, age
of tank cars and types of petroleum-based products.
In February 2019, PHMSA, in cooperation with the Federal Railroad
Association, issued a final rule that requires railroads to develop
and submit Comprehensive Oil Spill Response Plans for route
segments traveled by High Hazard Flammable Trains, or
HHFTs.
In subsequent years there have been additional modifications to
these regulations and we continuously monitor the railcar
regulatory landscape and remain in close contact with railcar
suppliers and other industry stakeholders to stay informed of
railcar regulation rulemaking developments. Given the current
railcar design compliance requirements and timelines outlined in
the most recent Transport Canada and DOT rules, we do not
anticipate a material impact to our ability to transport crude oil
under our existing contracts. If future rulemakings result in more
stringent design requirements and compressed compliance timelines,
then our ability to transport these volumes could be affected by a
delay in the railcar industry’s ability to provide adequate railcar
modification repair services. Our customers may not have access to
a sufficient number of compliant cars to transport the required
volumes under our existing contracts. This may lead to a decrease
in revenues and other consequences. DOT and Transport Canada have
also required operators to take certain precautions relating to
rail routing, and mandated reductions in train speed and the
implementation of new braking technology, to address rail safety
concerns.
Certain of the railroads serving our terminals have in the
past and are currently considering imposing tariffs, fees or other
limitations on the utilization of older railcar designs. These
tariffs, fees and limitations could have the effect of imposing
limits on the use of railcars that are more stringent than current
regulatory standards, and could reduce the size of the overall
railcar fleet available to be loaded at our terminals and increase
the costs of obtaining usable railcars. Similar to other industry
participants, compliance with existing and any additional
environmental laws and regulations, or the imposition of additional
tariffs, fees or limitations on the transportation of crude oil in
certain railcars or all railcars by the railroads, could increase
our overall cost of business, including our capital costs to
construct, maintain, operate and upgrade equipment and facilities,
or the costs of our customers, which may reduce the attractiveness
of rail transportation and limit our ability to extend existing
agreements or attract new customers. Our master fleet services
agreement generally obligates our customer to pay for modifications
and other
required repairs to our leased and managed railcar fleet. However,
we cannot assure that we will be able to successfully pass all such
regulatory costs on to our customer.
The adoption of additional federal, state, provincial or local laws
or regulations, including any voluntary measures by the rail
industry regarding railcar design or crude oil and liquid
hydrocarbon rail transport activities, or efforts by local
communities to restrict or limit rail traffic involving crude oil,
could affect our business by increasing compliance costs and
decreasing demand for our services, which could adversely affect
our financial position and cash flows.
Crude Oil Pipeline Safety
In connection with our acquisition of the Casper Terminal and
Stroud Terminal and related facilities, we became subject to
regulation by the Federal Energy Regulatory Commission, or FERC,
the DOT through PHMSA, as well as other federal, state and local
laws and regulations relating to the operation of our dedicated
crude oil pipelines, rates charged for transportation service, and
protection of health, property and the environment. The
transportation and storage of crude oil and refined petroleum
products involve a risk that hazardous liquids may be released into
the environment, potentially causing harm to the public or the
environment. In turn, such incidents may result in substantial
expenditures for response actions, significant government
penalties, liability to government agencies for natural resources
damages, and significant business interruption. DOT has adopted
safety regulations with respect to the design, construction,
operation, maintenance, inspection and management of our crude oil
pipeline and related assets. These regulations contain requirements
for the development and implementation of pipeline integrity
management programs, which include the inspection and testing of
pipelines and necessary maintenance or repairs. These regulations
also require that pipeline operation and maintenance personnel meet
certain qualifications and that pipeline operators develop
comprehensive spill response plans.
We are subject to regulation by the DOT under the Hazardous Liquid
Pipeline Safety Act of 1979, or the HLPSA. The HLPSA delegated to
DOT the authority to develop, prescribe, and enforce minimum
federal safety standards for the transportation of hazardous
liquids by pipeline. Congress also enacted the Pipeline Safety Act
of 1992, or the PSA, which added the environment to the list of
statutory factors that must be considered in establishing safety
standards for hazardous liquid pipelines, required that regulations
be issued to define the term “gathering line” and that safety
standards for certain “regulated gathering lines” be established,
and mandated that regulations be issued to establish criteria for
operators to use in identifying and inspecting pipelines located in
High Consequence Areas, or HCAs, defined as those areas that are
unusually sensitive to environmental damage, that cross a navigable
waterway, or that have a high population density. In 1996, Congress
enacted the Accountable Pipeline Safety and Partnership Act, or the
APSPA, which limited the operator identification requirement
mandate to pipelines that cross a waterway where a substantial
likelihood of commercial navigation exists, required that certain
areas where a pipeline rupture would likely cause permanent or
long-term environmental damage be considered in determining whether
an area is unusually sensitive to environmental damage, and
mandated that regulations be issued for the qualification and
testing of certain pipeline personnel. In the Pipeline Inspection,
Protection, Enforcement, and Safety Act of 2006, or the PIPES Act,
Congress required mandatory inspections for certain U.S. crude oil
and natural gas transmission pipelines in HCAs and mandated that
regulations be issued for low-stress hazardous liquid pipelines and
pipeline control room management. We are also subject to the
Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011,
which reauthorized funding for federal pipeline safety programs
through 2015, increased penalties for safety violations,
established additional safety requirements for newly constructed
pipelines, and required studies of certain safety issues that could
result in the adoption of new regulatory requirements for existing
pipelines. The Protecting Our Infrastructure of Pipelines and
Enhancing Safety Act of 2016 reauthorized the federal pipeline
safety programs of PHMSA through September 2019. The Protecting Our
Infrastructure of Pipelines and Enhancing Safety Act of 2020 was
passed in December 2020 as part of the Consolidated Appropriations
Act, 2021, appropriating funds through 2023.
PHMSA administers compliance with these statutes and has
promulgated comprehensive safety standards and regulations for the
transportation of hazardous liquids by pipeline, including
regulations for the design and construction of new pipeline systems
or those that have been relocated, replaced or otherwise changed;
pressure testing of new pipelines; operation and maintenance of
pipeline systems, establishing programs for public awareness and
damage prevention, and managing the operation of pipeline control
rooms; protection of steel pipelines from the adverse effects of
internal and external corrosion; and integrity management
requirements for pipelines in HCAs. PHMSA published its final
safety standards for hazardous liquid pipelines, as well as rules
for gas transmission pipelines, including maximum allowable
operating pressure reconfirmation (for pipelines constructed before
1970) and records rules in October 2019, which became effective
July 1, 2020. Also in September 2019, PHMSA finalized enhanced
emergency order procedures allowing the agency to issue an
emergency order which may impose emergency restrictions,
prohibitions, or other safety measures on owners and operators of
gas or hazardous liquid pipeline facilities. In August 2022, PHMSA
issued a final rule revising the Federal Pipeline Safety
Regulations. The rule clarifies integrity management provisions,
increases gas transmission pipeline corrosion control
requirements,
requires operators to inspect pipelines following extreme weather
events, strengthens integrity management assessment requirements,
adjusts the repair criteria for high-consequence areas, creates new
repair criteria for non-high consequence areas, and revises related
definitions. The rule takes effect on May 23, 2023.
We monitor the structural integrity of our pipeline system through
a program of periodic internal assessments using high resolution
internal inspection tools, as well as hydrostatic testing and
direct assessment that conforms to federal standards. We accompany
these assessments with a review of the data and repair anomalies,
as required, to ensure the integrity of the pipeline. We then
utilize sophisticated risk algorithms and a comprehensive data
integration effort to ensure that the greatest risk areas receive
the highest priority for scheduling subsequent integrity
assessments. We use external coatings and impressed current
cathodic protection systems to protect against external corrosion.
We conduct all cathodic protection work in accordance with National
Association of Corrosion Engineers standards. We continually
monitor, test, and record the effectiveness of these corrosion
inhibiting systems.
Crude Oil Pipeline Rate Regulation
The rates we charge for use of our dedicated crude oil pipeline are
subject to regulation by various federal, state and local agencies.
FERC regulates the transportation of crude oil on our dedicated
Casper and Stroud pipelines under the Interstate Commerce Act, or
ICA, Energy Policy Act of 1992, or EPAct 1992, and the rules and
regulations promulgated under those laws. FERC regulations require
that rates charged by pipelines that provide transport services in
interstate or foreign commerce for crude oil and refined petroleum
products, or collectively referred to as petroleum pipelines, and
certain other liquids be just and reasonable, not unduly
discriminatory, and not confer any undue preference upon any
shipper. FERC regulations also require interstate common carrier
petroleum pipelines to file with FERC and publicly post tariffs
stating their transportation rates and terms and conditions of
service. Under the ICA, FERC or interested persons may challenge
existing or changed rates or services. FERC is authorized to
investigate such charges and may suspend the effectiveness of a new
rate for up to seven months. A successful rate challenge could
result in a common carrier paying refunds together with interest
for the period that the rate was in effect. FERC may also order a
pipeline to change its rates and may require a common carrier to
pay shippers reparations for damages sustained for a period up to
two years prior to the filing of a complaint.
EPAct 1992 required FERC to establish a simplified and generally
applicable methodology to adjust tariff rates for inflation for
interstate petroleum pipelines. As a result, FERC adopted an
indexing rate methodology which, as currently in effect, allows
common carriers to change their rates within prescribed ceiling
levels that are tied to changes in the Producer Price Index for
Finished Goods, or PPIFG. FERC’s indexing methodology is subject to
review every five years. In December 2020, FERC issued an order
setting the index level for the period beginning July 1, 2021 for
annual changes equal to the change in PPIFG plus 0.78%. Upon
rehearing, FERC issued an order on January 20, 2022 revising
downward this index level to PPIFG minus 0.21%. As a result,
pipelines that have adjusted their transportation rates on an
indexed basis upward since July 2021 were required to decrease
those rates to a level at or below the new, lower index ceiling by
March 1, 2022. The indexing methodology is applicable to existing
rates, including grandfathered rates, with the exclusion of
market-based rates. A pipeline is not required to raise its rates
up to the index ceiling, but it is permitted to do so and rate
increases made under the index ceiling are presumed to be just and
reasonable unless a protesting party can demonstrate that the
portion of the rate increase resulting from application of the
index is substantially in excess of the pipeline’s increase in
costs. Under the indexing rate methodology, in any year in which
the index is negative, pipelines must file to lower their rates if
those rates would otherwise be above the rate ceiling. While common
carriers often use the indexing methodology to change their rates,
common carriers may elect to support proposed rates by using other
methodologies such as cost-of-service ratemaking, market-based
rates, and settlement rates. A pipeline can follow a
cost-of-service approach when seeking to increase its rates above
the rate ceiling (or when seeking to avoid lowering rates to the
reduced rate ceiling). A common carrier can charge market-based
rates if it establishes that it lacks significant market power in
the affected markets. In addition, a common carrier can establish
rates under settlement if agreed upon by all current shippers. We
have used settlement rates for our dedicated crude oil pipelines.
If we used cost-of-service rate making to establish or support our
rates, the issue of the proper allowance for federal and state
income taxes could arise.
In July 2016, the United States Court of Appeals for the District
of Columbia Circuit decided in
United Airlines, Inc., et al. v. FERC,
finding that FERC had acted arbitrarily and capriciously when it
did not demonstrate
that permitting an interstate petroleum products pipeline organized
as a master limited partnership, or MLP, to include an income tax
allowance in the cost of service underlying its rates, in addition
to the discounted cash flow return on equity, would not result in
the pipeline partnership owners double-recovering their income
taxes. The court vacated FERC’s order and remanded to FERC for
reconsideration. On March 15, 2018, FERC issued a Revised Policy
Statement on Treatment of Income Taxes in which FERC found that
permitting an MLP to recover from such an arrangement would
constitute an impermissible double recovery. Accordingly, FERC,
stated that it would no longer permit an MLP pipeline to recover an
income tax allowance in its cost of service. FERC stated it will
address the application of the
United Airlines
decision to non-MLP partnership forms as those issues arise in
subsequent proceedings. Further, FERC stated that it will
incorporate the effects of the post-United Airlines policy changes
and the Tax Cuts and Jobs Act of 2017 on industry-wide crude oil
pipeline costs in the 2020 five-year review of the crude oil
pipeline index level. FERC will also apply the revised Policy
Statement and the Tax Cuts and Jobs Act of 2017 to initial crude
oil pipeline cost-of-service rates and cost-of-service rate changes
on a going-forward basis under FERC’s existing ratemaking policies,
including cost-of-service rate proceedings resulting from
shipper-initiated complaints. On July 18, 2018, FERC
dismissed requests for rehearing and clarification of the
March 15, 2018 Revised Policy Statement, but provided
further guidance, clarifying that a pass-through entity will not be
precluded in a future proceeding from arguing and providing
evidentiary support that it is entitled to an income tax allowance
and demonstrating that its recovery of an income tax allowance does
not result in a double recovery of investors’ income tax costs. In
connection with an appeal regarding the order, the United States
Court of Appeals for the District of Columbia Circuit upheld FERC’s
position.
Intrastate services provided by our pipeline are subject to
regulation by the Wyoming Public Service Commission. This state
commission uses a complaint-based system of regulation, both as to
matters involving rates and priority of access. The Wyoming Public
Service Commission could limit our ability to increase our rates or
to set rates based on our costs or order us to reduce our rates and
require the payment of refunds to shippers. FERC and state
regulatory commissions generally have not investigated rates,
unless the rates are the subject of a protest or a complaint.
However, FERC, or a state commission, could investigate our rates
on its own initiative or at the urging of a third
party.
If our rate levels were investigated by FERC or a state commission,
the inquiry could result in a comparison of our rates to those
charged by others or to an investigation of our costs,
including:
•the
overall cost of service, including operating costs and
overhead;
•the
allocation of overhead and other administrative and general
expenses to the regulated entity;
•the
appropriate capital structure to be utilized in calculating
rates;
•the
appropriate rate of return on equity and interest rates on
debt;
•the
rate base, including the proper starting rate base;
•the
throughput underlying the rate; and
•the
proper allowance for federal and state income taxes
If the FERC, or the Wyoming Public Service Commission, on their own
initiative or due to challenges by third parties, were to lower our
tariff rates or deny any rate increase or other material changes to
the types, or terms and conditions, of service we might propose,
the profitability of our pipeline and terminals located in Casper,
Wyoming and Stroud, Oklahoma, may suffer.
Security
While we are not currently subject to governmental standards for
the protection of computer-based systems and technology from cyber
threats and attacks, proposals to establish such standards are
being considered in the U.S. Congress and by U.S. Executive Branch
departments and agencies, including the U.S. Department of Homeland
Security, or DHS, and we may become subject to such standards in
the future. We have implemented our own cyber security programs and
protocols; however, we cannot guarantee their effectiveness. A
significant cyber-attack could have a material effect on our
operations and those of our customers.
Employee Safety
We are subject to the requirements of the U.S. federal Occupational
Safety and Health Act, or OSHA, and comparable state and Canadian
federal and provincial statutes that regulate the protection of the
health and safety of workers. In addition, the OSHA hazard
communication standard and the Canadian Workplace Hazardous
Materials Information System, or WHMIS, require that information be
maintained about hazardous materials used or produced in operations
and that this information be provided to employees, state and local
government authorities and citizens. We believe that our operations
are in substantial compliance with OSHA in the United States and
comparable state and Canadian federal and provincial requirements,
including general industry standards, record keeping requirements,
and monitoring of occupational exposure to regulated
substances.
HUMAN CAPITAL RESOURCES
We are managed and operated by the board of directors and executive
officers of USD Partners GP LLC, our general partner. Neither we
nor our subsidiaries have any employees. Our general partner has
the sole responsibility for providing the employees and other
personnel necessary to conduct our operations. All of the employees
that conduct our business are employed by affiliates of our general
partner. Our general partner and its affiliates have approximately
85 employees, approximately 55 of whom performed services for our
operations during 2022. We believe that our general partner and its
affiliates have a satisfactory relationship with those
employees.
Our general partner and its affiliates believe employees are among
their most important resources and are critical to the continued
success of their and our businesses. Our general partner and its
affiliates are focused on attracting and retaining high quality
talent by providing fair and market-competitive pay, which includes
base pay as well as both short and long-term incentives. Our
general partner and its affiliates also offer employees a
competitive benefits package, which includes among others, health
insurance, paid time off, and a 401(k) savings plan with employee
contribution matching. Our general partner and its affiliates
manage current and future leadership needs by employing a
succession planning process that is reviewed annually by the Board,
or its delegates. A review of progress in attracting and developing
diverse candidates at all levels is part of that process. During
fiscal years 2022 and 2021, the voluntary attrition rate for
employees that are employed by our general partner and its
affiliates was approximately 5% and 6%, respectively.
In addition, our general partner has a long-standing relationship
with Railserve, Inc., or Railserve, a Marmon/Berkshire Hathaway
company, to provide operating services for our terminals. Railserve
is responsible for providing operations services to the terminals
according to the specific contracts. Railserve is one of the
largest in-plant rail operating services company in North America.
Railserve operates over 80 switching and/or transloading locations
across Canada, the United States and Mexico in the agriculture/food
processing, chemical/plastics, energy/refining, intermodal,
manufacturing, and pulp and paper markets. Railserve has over 1,400
personnel and 180+ Railserve owned and maintained locomotives.
Railserve is responsible for attracting, retaining, supervising,
and compensating its employees who are located at our terminals. To
date, Railserve has successfully met our requirements for staffing
operations at our terminals.
INSURANCE
Our rail terminals, pipelines, storage tanks and railcars may
experience damage as a result of an accident or natural disaster.
These hazards can cause personal injury and loss of life, severe
damage to and destruction of property and equipment, pollution or
environmental damage and suspension of operations. We maintain
insurance and are insured under the property, business interruption
and liability policies of USD and certain of its subsidiaries,
subject to the deductibles and limits under those policies, which
we consider to be reasonable and prudent under the circumstances to
cover our operations and assets. However, such insurance does not
cover every potential risk associated with our assets, and we
cannot ensure that such insurance will be adequate to protect us
from all material expenses related to potential future claims for
personal and property damage, or that these levels of insurance
will be available in the future at commercially reasonable prices.
Although we believe that our assets are adequately covered by
insurance, a substantial uninsured loss could have a material
adverse effect on our financial position, results of operations and
cash flows. As we grow, we will continue to monitor our policy
limits and retentions as they relate to the overall cost and scope
of our insurance program.
AVAILABLE INFORMATION
We make available free of charge on or through our Internet website
at
www.usdpartners.com
our Annual Reports on Form 10-K, Quarterly Reports on
Form 10-Q, Current Reports on Form 8-K and other
information statements, and if applicable, amendments to those
reports filed or furnished pursuant to Section 13(a) of the
Securities Exchange Act of 1934, as amended, or the Exchange Act,
as soon as reasonably practicable after we electronically file such
material with the SEC. We intend to post information for public
disclosure, in accordance with Regulation FD, on our website.
Information contained on our website is not part of this
Report.
Item 1A. Risk Factors
You should carefully consider the risk factors below in connection
with the other sections of this Annual Report. Realization of one
or more of these risk factors could have an adverse effect on our
business, operating results, cash flows and financial condition, as
well as the value of an investment in our common units. These are
not all the risks that could impact our business, operating
results, cash flows and financial condition as there may be risks
that are unknown to us or known immaterial risks that become
material over time or when compounded with unpredictable
events.
Risks Related to our Business and Industry
We depend on a limited number of customers for a significant
portion of our revenues. The loss of, or material nonpayment or
nonperformance by, any one or more of these customers could
adversely affect our ability to make cash distributions to our
unitholders.
We generate the vast majority of our operating cash flow in
connection with providing terminalling services at our crude oil
terminals. All of the contracted capacity at our crude oil
terminals is contracted under multi-year, take-or-pay Terminal
Services Agreements.
A sustained reduction in the prices of crude oil and other
commodities could have a material adverse effect on our customers’
businesses. In particular, oil sands production in Canada is
particularly susceptible to decline as a result of long-term
reductions in the price of crude oil due to its relatively high
production costs.
As a result, some of our customers may have material financial or
liquidity issues or may, as a result of operational incidents or
other events, be disproportionately affected as compared to larger
or better-capitalized companies. Any material nonpayment or
nonperformance by any of our key customers could have a material
adverse effect on our business, financial condition, results of
operations, and ability to make quarterly distributions to our
unitholders. In addition, liquidity issues resulting from lower
crude oil prices could lead our customers to go into bankruptcy or
could encourage them to seek to repudiate, cancel, renegotiate or
fail to renew their agreements with us for various reasons. We
expect our exposure to concentrated risk of non-payment or
non-performance to continue as long as we remain substantially
dependent on a relatively limited number of customers for a
substantial portion of our revenue.
As discussed below, if we were unable to renew our contract with
one or more of our customers, including customers at our Hardisty,
Stroud or Casper terminals, on favorable terms, we may not be able
to replace this contracted cash flow in a timely fashion, on
favorable terms or at all. For example, to date we have been unable
to replace the revenue generated by the contracts that expired at
the Hardisty Terminal and Stroud Terminal on
June 30, 2022, as discussed below.
Our contracts are subject to termination at various times, which
creates renewal risks.
We provide terminalling services for liquid hydrocarbons and
biofuels under contracts with terms of various durations and
renewal. At the end of June 2022, contracts representing
approximately 26% of our Hardisty Terminal’s capacity and the
remaining contracted capacity at the Stroud Terminal expired.
Approximately 54% of the combined Hardisty Terminal’s capacity is
contracted through June 30, 2023; approximately 31% is contracted
through January 2024; and approximately 17% is contracted through
mid-2031. Of the two terminal agreements at our West Colton
Terminal, the ethanol agreement that represents approximately 35%
of the West Colton terminal’s capacity expires in December 2026,
and the renewable diesel agreement that represents approximately
46% of the West Colton terminal’s capacity expires in November
2026.
One of our Terminal Services Agreements with our Casper Terminal
customers expired in December 2022 and the other was renewed and
expires December 31, 2023.
As these contracts have expired or will expire, we will have to
negotiate extensions or renewals with existing customers or enter
into new contracts with other customers, which we might not be able
to do on favorable commercial terms, if at all. We have been unable
to enter into new contracts to replace the expired contracts at the
Casper Terminal, Stroud Terminal and Hardisty Terminal that are
described above. We also may be unable to maintain the economic
structure of a particular contract with an existing customer or
maintain the overall mix of our contract portfolio if, for example,
prevailing crude oil prices and the associated spreads between
different grades of crude oil remain at levels, or decline below
levels, where transportation of crude oil by rail is economic.
Depending
on prevailing market conditions at the time of a contract renewal,
customers with fee-based contracts may desire to enter into
contracts under different fee or term arrangements, including lower
rate structures, or may seek to purchase such capacity on an
uncommitted basis. To the extent we are unable to renew our
existing contracts on terms that are favorable to us or experience
a further delay in doing so, or are unable to successfully manage
our overall contract mix over time, or replace lost revenue upon
changes in contract terms (including those in connection with the
DRU project), our revenue and cash flows could decline and both our
ability to make cash distributions to our unitholders and our
ability to remain in compliance with the covenants under our Credit
Agreement could be materially and adversely affected. Our ability
to refinance our outstanding indebtedness or extend the maturity
date of our Credit Agreement may be negatively impacted to the
extent we are unable to renew, extend or replace the customer
agreements that have expired or will expire at the Hardisty and
Stroud Terminals in the near term.
The lack of diversification of our assets and geographic locations
could adversely affect our ability to make distributions to our
common unitholders.
We generate the vast majority of our operating cash flow in
connection with providing terminalling services at our crude oil
terminals, all of which receive the majority of their crude oil
from the Canadian oil sands through the Hardisty hub. Due to the
lack of diversification in our assets and geographic location, an
adverse development in our businesses or areas of operations,
especially to our crude oil terminals, including those due to
catastrophic events, natural disasters or adverse weather
conditions (including as a result of climate change), worldwide
health events including the recent coronavirus outbreak, regulatory
action or decreases in the price of, or demand for, crude oil,
could have a significantly greater impact on our results of
operations and distributable cash flow to our common unitholders
than if we maintained more diverse assets and locations. In
particular, due in part to relatively high production costs, oil
sands production in Canada may be particularly susceptible to
decline as a result of long-term declines in the price of crude oil
and was negatively impacted by the depressed pricing environment at
the height of the COVID-19 pandemic in 2020, which has impacted and
could in the future further impact our ability to secure additional
long-term customer contracts and renewals at our Hardisty Terminal
and our Casper Terminal, and the ability of USD Group LLC to
contract for and complete expansions. In addition, events that
impact the supply of crude oil in Western Canada, such as extreme
weather, forest fires, and facility downtime, and events that
increase the take-away capacity, such as the construction of new
pipelines would have a similar impact.
We may not be able to compete effectively and our business is
subject to the risk of a capacity overbuild of midstream
infrastructure and the entrance of new competitors in the areas
where we operate.
We face competition in all aspects of our business and can give no
assurances that we will be able to compete effectively. Our
terminals compete with existing and potential new hydrocarbon by
rail terminals, as well as alternative modes of transporting
hydrocarbons from production centers to refining or aggregation
centers, such as existing and potential new crude oil pipelines and
water-borne vessels.
Our competitors include other midstream companies, major integrated
energy companies, independent producers and refiners, as well as
commodity marketers and traders of widely varying sizes, financial
resources and experience. We compete on the basis of many factors,
including geographic proximity to production areas, market access,
rates, terms of service, connection costs and other factors. Many
of our competitors have access to capital resources significantly
greater than ours.
A significant driver of competition in some of the markets where we
operate is the risk of development of new midstream infrastructure
capacity driven by the combination of (i) significant increases in
oil and gas production and development in the particular production
areas, both actual and anticipated, (ii) low barriers to entry and
(iii) generally widespread access to relatively low cost capital.
This environment exposes us to the risk that these areas become
overbuilt, resulting in an excess of midstream infrastructure
capacity.
We face these risks in particular with respect to the potential
development of additional pipeline takeaway capacity from the
Canadian oil sands region, where our customers source the majority
of the crude oil handled at our terminals. Most midstream projects
require several years of “lead time” to develop and companies like
us that develop such projects are exposed (to varying degrees
depending on the contractual arrangements that underpin specific
projects) to the risk that expectations for oil and gas development
in the particular area may not be realized or that too much
capacity is developed relative to the demand for services that
ultimately materializes. If we experience a significant capacity
overbuild in one or more of the areas where we operate, it could
have a material adverse effect on our business, financial
condition, results of operations, and as a result, our ability to
make distributions to our unitholders.
Adverse developments affecting the oil and gas industry or drilling
activity, including low or reduced prices of crude oil or biofuels,
reduced demand for crude oil products and increased regulation of
drilling, production or transportation could cause a reduction of
volumes transported through our terminals.
Our business, including our ability to grow our business through
the contracting and development of new terminals, as well as our
ability to secure renewals or extensions of agreements with
customers at our existing terminals, depends on the continued
development, production and demand for crude oil and other liquid
hydrocarbons from our existing markets, as well as other areas
unserved or underserved by existing alternative transportation
solutions. The willingness of exploration and production companies
to develop and produce crude oil in particular producing regions in
Canada and the United States depends largely on their ability to
conduct these activities profitably, which in turn depends largely
upon the markets for and prices of crude oil and other commodities.
A sustained reduction in the prices of crude oil could have a
material adverse effect on our business. For example, our business
was negatively impacted by the depressed commodity pricing
environment at the height of the COVID-19 pandemic in 2020. The
factors impacting the prices of crude oil and other commodities
include the supply of and demand for these commodities, which
fluctuate with changes in market and economic conditions, and other
factors, including:
•worldwide
and regional economic conditions, including inflationary pressures,
further increases in interest rates or a general slowdown in the
global economy;
•worldwide
and regional political events, including actions taken by foreign
oil producing nations (including the invasion of Ukraine by Russia
and any related political or economic responses and
counter-responses or otherwise by various global actors or the
general effect on the global economy);
•political
or regulatory changes that could restrict development or production
of crude oil and other liquid hydrocarbons;
•the
nature and extent of governmental regulation and taxation,
including the amount of subsidies for ethanol and other alternative
sources of energy;
•development
and commercialization of energy alternatives to crude oil,
including by our customers;
•increased
demand for energy sources that compete with crude oil;
•the
price and availability of energy sources that compete with crude
oil;
•the
price and availability of the raw materials used to produce energy
sources that compete with crude oil, such as the price and
availability of corn used to produce ethanol;
•worldwide
and regional weather events and conditions, including natural
disasters and seasonal changes that could decrease supply or
demand;
•worldwide
health events such as the recent COVID-19 pandemic;
•the
levels of domestic and international production and consumer
demand;
•the
availability of transportation systems with adequate
capacity;
•fluctuations
in demand for crude oil, such as those caused by refinery downtime
or turnarounds;
•fluctuations
in the price of crude oil, which may have an impact on the spot
prices for the transportation of crude oil by pipeline or
railcar;
•increased
government regulation or prohibition of the transportation of
hydrocarbons by rail;
•the
volatility and uncertainty of world crude oil prices as well as
regional pricing differentials;
•fluctuations
in gasoline consumption;
•the
effect of energy conservation measures, such as more efficient fuel
economy standards for automobiles;
•fluctuations
in demand from electric power generators and industrial
customers;
•a
decline in investor sentiment regarding the oil and gas
industry;
•restrictions
on access to development capital by oil and gas companies;
and
•the
anticipated future prices of oil and other
commodities.
The prices of crude oil and related products remain volatile and
subject to the influence of many global factors, such as the
Organization of the Petroleum Exporting Countries, or OPEC, policy,
the balance of supply versus demand for those products in various
markets and geopolitical risks. For example, the ongoing conflict,
and the continuation of, or any increase in the severity of, the
conflict between Russia and Ukraine, has led and may continue to
lead to an increase in the volatility of global oil and gas prices.
Our terminals primarily transport crude oil produced from the
Canadian oil sands, which are considered to have relatively high
production costs. Exploration and production companies operating in
the Canadian oil sands have reduced, and may further reduce,
capital spending for expansion projects designed to increase crude
oil production. Declines in crude oil prices for a prolonged period
of time have resulted in and may in the future result in further
reductions in capital spending by our customers, which could
decrease the likelihood that our existing customers would renew
their contracts with us at current prices or at all, reduce the
opportunities for us to grow our assets and otherwise have a
material adverse impact on our business and results of
operations.
The dangers inherent in our operations could cause disruptions and
expose us to potentially significant losses, costs or liabilities
and reduce our liquidity. We are particularly vulnerable to
disruptions in our operations because most of our operations are
concentrated at our crude oil terminals.
Our operations are subject to significant hazards and risks
inherent in transporting and storing crude oil, intermediate
products and refined products. These hazards and risks include, but
are not limited to, natural disasters, (occurrences of which may
increase in frequency and severity as a result of climate change),
fires, explosions, pipeline or railcar ruptures and spills,
third-party interference and mechanical failure of equipment at our
terminals, any of which could result in disruptions, pollution,
personal injury or wrongful death claims and other damage to our
properties and the property of others. There is also risk of
mechanical failure and equipment shutdowns both in the normal
course of operations and following unforeseen events. Because the
vast majority of our cash flow is generated from operations
conducted at our crude oil terminals, any sustained disruption at
any of these terminals, the Gibson storage terminal, which is the
source of all of the crude oil handled by our Hardisty Terminal,
the Express pipeline, which is the primary source of the crude oil
handled by the Casper Terminal, or the Cushing hub and pipelines
feeding into or out of the Cushing hub, which is the destination of
the crude oil handled by the Stroud Terminal, would have a material
adverse effect on our business, financial condition, results of
operations and cash flows and, as a result, our ability to make
distributions to our unitholders.
Any reduction in our or our customers’ ability to utilize
third-party storage facilities, pipelines, railroads or trucks that
interconnect with our terminals or to continue utilizing them at
current costs could negatively impact customer volumes and renewal
rates at our terminals.
We and the customers of our terminals are dependent upon access to
third-party storage facilities, pipelines, railroads and truck
fleets to receive and deliver crude oil and other liquid
hydrocarbons to or from us. The continuing operation of such
third-party storage facilities, pipelines, railroads and other
midstream facilities or assets is not within our control. Any
interruptions or reduction in the capabilities of these third
parties due to testing, line repair, reduced operating pressures,
or other causes in the case of pipelines, or track repairs,
derailments or other causes, in the case of railroads, could result
in reduced volumes transported through our terminals.
We entered into a facilities connection agreement with Gibson
whereby Gibson constructed a pipeline to provide our Hardisty
Terminal with exclusive pipeline access to Gibson’s Hardisty
storage terminal, which is the source of all of the crude oil
handled by our Hardisty Terminal. In addition, substantially all of
the crude oil handled by our Casper Terminal has historically been
sourced from the Express pipeline.
Our customer base is accordingly constrained by customer access to
Gibson’s Hardisty storage terminal in the case of our Hardisty
Terminal, and the Express pipeline in the case of our Casper
Terminal.
If our existing customers don’t maintain their capacity with Gibson
or Express, or in the case of our Casper Terminal, our customers’
capacity allocations on the Express pipeline are reduced by
prorations due to the capacity demands of other shippers or other
reasons, the volume
shipped by our existing customers may be reduced or our customers
may choose not to renew their agreements with us at existing rates
and volumes, if at all, which would have a material adverse effect
on our results of operations and ability to make quarterly
distributions to our unitholders.
Similar issues could arise based on other capacity issues arising
before or after a customer’s products reach or leave our terminals,
including rail capacity constraints and constraints at receiving
terminals or other midstream facilities downstream of receiving
terminals. For example, in the past, increase in demand for
utilization of our Hardisty Terminal has been limited by the
ability of the railroads to increase staffing to meet this demand.
If the railroads are unwilling or unable to meet the existing and
potential future demand for our terminals, our ability to retain
customers or grow our terminal would be materially
impacted.
We do not own some of the land on which our terminals are located,
which could disrupt our operations.
We do not own all of the land on which our West Colton Terminal is
located, which land we obtained the right to use through a lease
from the Class I railroad servicing this terminal.
Our ability to provide comprehensive services to our customers on
the leased land depends in large part on our ability to maintain
and extend this lease, which are currently cancellable at will by
either party after November 2026. Accordingly, after November 2026,
we are subject to the possibility of lease cancellation, more
onerous terms and/or increased costs to retain the land necessary
to operate this terminal.
Our loss of these rights, through our inability to renew or the
unwillingness of the land owner to negotiate right-of-way contracts
or leases, or otherwise, could cause us to cease operations on the
affected land, incur costs to dismantle and remove existing
facilities, increase costs related to continuing operations
elsewhere and reduce our revenue.
The fees charged to customers under our agreements with them for
the transportation of crude oil may not escalate sufficiently or at
all to cover increases in costs, and the agreements may be
temporarily suspended or terminated in some circumstances, which
would affect our profitability.
We generate the vast majority of our operating cash flow in
connection with providing terminalling services at our crude oil
terminals. All of the contracted capacity at our crude oil
terminals is contracted under multi-year, take-or-pay Terminal
Services Agreements, which, in the case of our Hardisty Terminal,
some of the contracted capacity is subject to inflation-based rate
escalators. Our Terminal Services Agreement at our Casper Terminal
is not subject to inflation-based rate escalators.
Any inflation-based escalators in our Terminal Services Agreements
may be insufficient to compensate for increases in our costs. We
experienced higher costs in 2022 due to inflation, some of which
might not have been sufficiently covered by the inflation-based
rate escalators that exist in certain of our agreements.
Additionally, some customers’ obligations under their agreements
with us may be temporarily suspended upon the occurrence of certain
events, some of which are beyond our control, or may be terminated
in the case of uninterrupted force majeure events of over one year
wherein the supply of crude oil is curtailed or cut off. Force
majeure events may include (but are not limited to) revolutions,
wars, acts of enemies, embargoes, import or export restrictions,
strikes, lockouts, fires, storms, floods, acts of God, pandemics
(including the COVID-19 pandemic), explosions, mechanical or
physical failures of our equipment or facilities of our customers,
or any cause or causes of any kind or character (except financial)
reasonably beyond the control of the party failing to perform. If
either the escalation of fees under the Terminal Services
Agreements at our terminals is insufficient to cover increased
costs or if any customer suspends or terminates its contracts with
us, our profitability and ability to make quarterly distributions
to our unitholders could be materially and adversely
affected.
Exposure to currency exchange rate fluctuations will result in
fluctuations in our cash flows and operating results.
Currency exchange rate fluctuations have had and could continue to
have an adverse effect on our results of operations. A substantial
portion of the cash flows from our current assets are generated in
Canadian dollars, but we intend to make distributions to our
unitholders in U.S. dollars. As such, a portion of our
distributable cash flow will be subject to currency exchange rate
fluctuations between U.S. dollars and Canadian dollars. For
example, if the Canadian dollar weakens significantly, the
corresponding distributable cash flow in U.S. dollars could be less
than what is necessary to pay our minimum quarterly
distribution.
A significant strengthening of the U.S. dollar relative to other
currencies has resulted in, and could continue to result in an
increase in our financing expenses and could materially affect our
financial results under generally accepted accounting policies, or
GAAP. In addition, because we report our operating results in U.S.
dollars, changes in the value of the U.S. dollar also result in
fluctuations in our reported revenues and earnings. In addition,
under GAAP, all foreign currency-denominated monetary assets and
liabilities such as cash and cash equivalents, accounts receivable,
restricted cash, accounts payable and capital lease obligations are
revalued and reported based on the prevailing exchange rate at the
end of the reporting period. This revaluation may cause us to
report significant non-monetary foreign currency exchange gains and
losses in certain periods.
Increases in rail freight costs may adversely affect our results of
operations.
The largest component of a shipment of crude by rail is the rail
freight transportation costs. Unlike terminal services fees, which
are typically established by multi-year contracts, railroad freight
transportation has traditionally been purchased on a spot
basis.
Recently the railroads servicing some of our terminals have begun
to seek multi-year term agreements, which also increase costs to
our customers to the extent not utilized. High spot rail freight
costs from or to our terminals, or high term rates or long contract
terms, may make the shipment of crude or other liquid hydrocarbons
less attractive or unattractive to our customers and potential
customers. In addition, transporters of hydrocarbons by rail
compete with other parties, such as coal, grain and corn, which
ship their product by rail. Demand for transportation of crude or
other products by rail is currently and has previously caused
shortages in available locomotives and railroad crews. Such
shortages may ultimately increase the cost to transport
hydrocarbons by rail. Additionally, diesel fuel costs generally
fluctuate with increasing and decreasing world crude oil prices,
and accordingly are subject to political, economic and market
factors that are outside of our control. Diesel fuel prices are a
significant component of the costs to our customers of shipping
hydrocarbons by rail. Increased costs to ship hydrocarbons by rail
could curtail demand for shipment of hydrocarbons by rail which
would have an adverse effect on our results of operations and cash
flows and our ability to attract new customers and retain existing
customers.
The impact and effects of public health crises, pandemics and
epidemics, such as the COVID-19 pandemic, could have a material
adverse effect on our business, financial condition and results of
operations.
Public health crises, pandemics and epidemics, such as the COVID-19
pandemic, and fear of such events have adversely impacted and may
continue to adversely impact our operations, the operations of our
customers and the global economy, including the worldwide demand
for oil and natural gas and the level of demand for our services.
Other effects of the pandemic include and may continue to include,
significant volatility and disruption of the global financial
markets; continued volatility of crude oil prices and related
uncertainties around OPEC+ production; disruption of our
operations; impact to costs; loss of workers; labor shortages;
supply chain disruptions or equipment shortages; logistics
constraints; customer demand for our services and industry demand
generally; our liquidity; the price of our securities and trading
markets with respect thereto; our ability to access capital
markets; asset impairments and other accounting changes; certain of
our customers experiencing bankruptcy or otherwise becoming unable
to pay vendors, including us; and employee impacts from illness,
travel restrictions, including border closures and other community
response measures. The extent to which our business operations and
financial results continue to be affected depends on various
factors beyond our control, such as the duration, severity and
sustained geographic resurgence of the COVID-19 virus; the
emergence, severity and spread of new variants of the virus; the
impact and effectiveness of governmental actions to contain and
treat such outbreaks, including government policies and
restrictions; vaccine hesitancy, vaccine mandates, and voluntary or
mandatory quarantines; and the global response surrounding such
uncertainties.
Our business involves many hazards and operational risks, some of
which may not be fully covered by insurance. If a significant
accident or event occurs for which we are not adequately insured,
or if we fail to recover anticipated insurance proceeds for
significant accidents or events for which we are insured, our
operations and financial results could be adversely
affected.
Our operations are subject to all of the risks and hazards inherent
in the provision of terminalling services, including:
•damage
to railroads and terminals, related equipment and surrounding
properties caused by natural disasters or adverse weather
conditions (including as a result of climate change), acts of
terrorism and actions by third parties;
•damage
from construction, vehicles, farm and utility equipment or other
causes;
•leaks
of crude oil and other hydrocarbons or regulated substances or
losses of oil as a result of the malfunction of equipment or
facilities or operator error;
•blockades
of rail lines or other interruptions in service due to actions of
third parties;
•ruptures,
fires and explosions; and
•other
hazards that could also result in personal injury and loss of life,
pollution and suspension of operations.
These and similar risks could result in substantial costs due to
personal injury and/or loss of life, severe damage to and
destruction of property and equipment and pollution or other
damage. These risks may also result in curtailment or suspension of
our operations. A natural disaster or other hazard affecting the
areas in which we operate could also have a material adverse effect
on our operations. The projected severe effects of climate change
have the potential to directly affect our facilities and operations
and those of our customers, which could result in more frequent and
severe disruptions to our business and those of our customers,
increased costs to repair damaged facilities or maintain or resume
operations, and increased insurance costs. We are not fully insured
against all risks inherent in our business. In addition, although
we are insured for environmental pollution resulting from
environmental accidents that occur on a sudden and accidental
basis, we may not be insured against all environmental accidents
that might occur, some of which may result in claims for
remediation, damages to natural resources or injuries to personal
property or human health. If a significant accident or event occurs
for which we are not fully insured, it could adversely affect our
operations and financial condition. Furthermore, we may not be able
to maintain or obtain insurance of the type and amount we desire at
reasonable rates, particularly following a significant accident or
event for which we seek insurance. As a result of market
conditions, premiums and deductibles for certain of our insurance
policies may substantially increase. In some instances, certain
insurance could become unavailable or available only for reduced
amounts of coverage.
Risks Related to our Ability to Grow through Acquisitions or
Development of New Assets
If we are unable to make acquisitions on economically acceptable
terms from USD or third parties, our future growth would be
limited, and any acquisitions we may make could reduce, rather than
increase, our cash flows and ability to make distributions to
unitholders.
A portion of our strategy to grow our business and increase
distributions to unitholders is dependent on our ability to make
acquisitions that result in an increase in cash flow. If we are
unable to make acquisitions from USD or third parties, because we
are unable to identify attractive acquisition candidates or
negotiate acceptable purchase agreements, we are unable to obtain
financing for these acquisitions on economically acceptable terms,
we are outbid by competitors or we or the seller are unable to
obtain any necessary consents, our future growth and ability to
increase distributions to unitholders will be limited. Energy
Capital Partners must also approve the acquisition of the
securities of any entity by us if the acquisition exceeds specified
thresholds.
Furthermore, even if we do consummate acquisitions that we believe
will be accretive, we may not realize the intended benefits, and
the acquisition may in fact result in a decrease in cash flow,
including our acquisition of Hardisty South from USD in April 2022.
Any acquisition, including the integration of any such acquisition,
involves potential risks, including, among other
things:
•
mistaken assumptions about revenues and costs, including
synergies;
•
the assumption of unknown liabilities;
•
limitations on rights to indemnity from the seller;
•
mistaken assumptions about the overall costs of equity or
debt;
•
the diversion of management’s attention from other business
concerns;
•
unforeseen difficulties operating in new product areas or new
geographic areas; and
•
customer or key employee losses at the acquired
businesses.
If we consummate any future acquisitions, our capitalization and
results of operations may change significantly, and unitholders
will not have the opportunity to evaluate the economic, financial
and other relevant information that we will consider in determining
the application of these funds and other resources.
Our right of first offer to acquire certain of USD’s existing
assets and projects and certain projects that it may develop,
construct or acquire in the future is limited and subject to risks
and uncertainty, and ultimately we may not acquire any of those
assets or businesses.
The Omnibus Agreement provides us with a ROFO on certain of USD’s
existing assets and projects as well as any additional midstream
infrastructure that it may develop, construct or acquire, subject
to certain exceptions. This right expires on October 15, 2026. The
consummation and timing of any future acquisitions pursuant to this
right will depend upon, among other things, USD’s continued
development of midstream infrastructure projects and successful
execution of such projects, USD’s willingness to offer assets for
sale and obtain any necessary consents, our ability to negotiate
acceptable purchase agreements and commercial agreements with
respect to such assets and our ability to obtain financing on
acceptable terms. We can offer no assurance that we will be able to
successfully consummate any future acquisitions or successfully
integrate assets acquired pursuant to our ROFO. Furthermore, USD is
under no obligation to accept any offer that we may choose to make.
Additionally, the approval of Energy Capital Partners is required
for the sale of any assets by USD or its subsidiaries, including us
(other than sales in the ordinary course of business), acquisitions
of securities of other entities that exceed specified materiality
thresholds and any material unbudgeted expenditures or deviations
from our approved budgets. Energy Capital Partners may make these
decisions free of any duty to us and our unitholders. This approval
would be required for the potential acquisition by us of any of
USD’s projects, as well as any other projects or assets that USD
may develop or acquire in the future or any third-party acquisition
we may intend to pursue jointly or independently from USD. Energy
Capital Partners is under no obligation to approve any such
transaction. Please refer to the discussion under
Part III, Item 10.
Directors,
Executive Officers and Corporate Governance—
Special Approval Rights of Energy Capital Partners
in this Annual Report regarding the rights of Energy Capital
Partners.
In addition, we may decide not to exercise our ROFO if and when any
assets are offered for sale, and our decision will not be subject
to unitholder approval. Further, our ROFO may be terminated by USD
at any time in the event that it no longer controls our general
partner. Please refer to the discussion under
Part II, Item 8. Financial Statements and Supplementary
Data,
Note 13.
Transactions with Related Parties
in this Annual Report for additional information regarding the
Omnibus Agreement.
Growing our business by constructing new assets subjects us to
construction risks and risks that supplies for such facilities will
not be available upon completion thereof.
One of the ways we intend to grow our business is through the
construction of new assets. The construction of new assets requires
the expenditure of capital, some of which may exceed our resources,
and involve regulatory, environmental, political and legal
uncertainties. If we undertake the construction of new assets, we
may not be able to complete them on schedule or at all or at the
budgeted cost. Actions by third parties that we do not control may
cause delay in construction, which could result in lost revenue or
contract termination rights relating to the new asset. Moreover,
our revenues may not increase upon the expenditure of funds on a
particular project. For instance, if we build a new significant
asset, the construction will occur over a period of time, and we
will not receive any revenues until after completion of the
project, if at all. Moreover, we may construct assets to provide
services to capture revenue which does not materialize or for which
we are unable to acquire new customers. We may also rely on
estimates of potential demand for our services in our decision to
construct new assets, which may prove to be inaccurate because
there are numerous uncertainties inherent in estimating demand for
our services. As a result, new assets we construct may not be able
to attract sufficient demand to achieve our expected investment
return, which could materially and adversely affect our results of
operations, cash flows and financial condition.
We intend to distribute a significant portion of our available
cash, which could limit our ability to pursue growth projects and
make acquisitions.
Pursuant to our cash distribution policy we intend to distribute
most of our available cash, as that term is defined in our
partnership agreement, to our unitholders. As a result, we expect
to rely primarily upon external financing sources, including
commercial bank borrowings and the issuance of debt and equity
securities, to fund our acquisitions and expansion capital
expenditures. Therefore, to the extent we are unable to finance our
growth externally, our cash distribution policy will significantly
impair our ability to grow. In addition, because we intend to
distribute most of our available cash, our growth may not be as
fast as that of businesses that reinvest their available cash to
expand ongoing operations. To the extent we issue additional units
in connection with any acquisitions or expansion capital
expenditures, the payment of distributions on those additional
units may increase the risk that we will be unable to maintain or
increase our per unit distribution level. There are no limitations
in our partnership agreement or our Credit Agreement on our ability
to issue additional units, including units ranking senior to the
common units as to distribution or liquidation, and our unitholders
will have no preemptive or other rights (solely as a result of
their status as unitholders) to purchase any such additional units.
The incurrence of additional commercial borrowings or other debt to
finance our growth strategy would result in increased interest
expense, which, in turn, may reduce the amount of cash available to
distribute to our unitholders.
Risks Related to our Ability to Make Cash
Distributions
We may not have sufficient cash from operations following the
establishment of cash reserves and payment of fees and expenses,
including reimbursements to our general partner, to enable us to
pay distributions to holders of our common and general partner
units.
The amount of cash we can distribute on our units principally
depends upon the amount of cash we generate from our operations,
which will fluctuate from quarter to quarter based on, among other
things:
•our
entitlement to minimum monthly payments associated with our
take-or-pay Terminal Services Agreements and the impact of credits
for unutilized contractual capacity;
•our
ability to acquire new customers and retain existing customers,
including our ability to renew, extend or replace our customer
agreements at the Hardisty and Stroud Terminals;
•the
rates and terminalling fees we charge for the volumes we
handle;
•the
volume of crude oil and other liquid hydrocarbons we
handle;
•damage
to terminals, railroads, pipelines, facilities, related equipment
and surrounding properties caused by hurricanes, earthquakes,
floods, fires, severe weather, explosions and other natural
disasters and acts of terrorism including damage to third-party
pipelines, railroads or facilities upon which our customers rely
for transportation services;
•leaks
or accidental releases of products or other materials into the
environment, including explosions, chemical fumes or other similar
events, whether as a result of human error, natural disaster or
otherwise;
•prevailing
economic and market conditions; including low or volatile commodity
prices and their effect on our customers;
•our
desired levels of liquidity and reduction of debt;
•the
effects of worldwide health events, including the recent COVID-19
pandemic;
•the
level of our operating, maintenance and general and administrative
costs;
•regulatory
action affecting railcar design or the transportation of crude oil
by rail;
•delays
or increased costs caused by blockades or other interruptions in
rail services; and
•the
supply of, or demand for, crude oil and other liquid
hydrocarbons.
In addition, the actual amount of cash we will have available for
distribution will depend on other factors, some of which are beyond
our control, including:
•restrictions
on cash distributions to our partners contained in our debt
agreements, including increased restrictions in connection with
debt ratio covenant relief under our Credit Agreement obtained in
January 2023;
•the
level and timing of capital expenditures we make;
•the
cost of acquisitions, if any;
•our
debt service requirements and other liabilities;
•our
requirements to pay distribution equivalents on Phantom Units
pursuant to the terms of the awards granted under our First
Amendment to the USD Partners LP Amended and Restated 2014
Long-Term Incentive Plan, or the Amended LTIP Plan,
•fluctuations
in our working capital needs;
•fluctuations
in the values of foreign currencies in relation to the U.S. dollar,
including the Canadian dollar;
•our
ability to borrow funds and access capital markets;
•the
amount of cash reserves established by our general partner;
and
•other
business risks affecting our cash levels.
The amount of cash we have available for distribution to holders of
our common units and general partner units depends primarily on our
cash flow rather than on our profitability, which may prevent us
from making distributions, even during periods in which we record
net income.
The amount of cash we have available for distribution depends
primarily upon our cash flow and not solely on profitability, which
will be affected by non-cash items. As a result, we may make cash
distributions during periods when we record losses for financial
accounting purposes and may not be able to make cash distributions
during periods when we record net earnings for financial accounting
purposes.
The board of directors of our general partner may modify or revoke
our cash distribution policy at any time at its discretion and our
partnership agreement does not require us to pay any distributions
at all. Additionally, members of our general partner’s board of
directors appointed by Energy Capital Partners must approve any
distributions made by us.
The board of directors of our general partner has adopted a cash
distribution policy pursuant to which we intend to distribute
quarterly at least $0.2875 per unit on all of our units to the
extent we have sufficient cash after the establishment of cash
reserves and the payment of our expenses, including payments to our
general partner and its affiliates. However, the board may change
such policy at any time at its discretion and the board
re-evaluates our distribution policy on a quarterly basis, taking
into consideration updated commercial progress, including our
ability to renew, extend or replace our customer agreements at the
Hardisty and Stroud Terminals, and our compliance with the
covenants under the Credit Agreement, as well as recent changes to
the market.
Beginning in the first quarter of fiscal 2020, the board of
directors of our general partner reduced the quarterly dividend to
$0.111 per unit, or $0.444 per unit on an annualized basis, 70%
below the distribution with respect to the fourth quarter of 2019.
In 2022, the board of directors increased these amounts to $0.1235
per unit or $0.494 per unit on an annualized basis, still
substantially reduced from 2019.
Additionally, members of our general partner’s board of directors
appointed by Energy Capital Partners, if any, must approve any
distributions made by us. Our partnership agreement does not
require us to pay distributions at all and our general partner’s
board of directors has broad discretion in setting the amount of
cash reserves each quarter. Investors are cautioned not to place
undue reliance on the permanence of our cash distribution policy in
making an investment decision. Any modification or revocation of
our cash distribution policy could substantially reduce or
eliminate the amounts of distributions to our unitholders. The
amount of distributions we make and the decision to make any
distribution is determined by the board of directors of our general
partner as well as the members of our general partner’s board of
directors appointed by Energy Capital
Partners, whose interests may differ from those of our common
unitholders. Our general partner has limited duties to our
unitholders, which may permit it to favor its own interests or the
interests of our sponsor or its affiliates to the detriment of our
common unitholders.
Our general partner’s discretion in establishing cash reserves may
reduce the amount of distributable cash flow to
unitholders.
Our partnership agreement requires our general partner to deduct
from operating surplus cash reserves that it determines are
necessary to fund our future operating expenditures. In addition,
our partnership agreement permits the general partner to reduce
available cash by establishing cash reserves for the proper conduct
of our business, to comply with applicable law or agreements to
which we are a party (including our Credit Agreement), or to
provide funds for future distributions to partners. These cash
reserves will affect the amount of distributable cash flow to
unitholders.
Risks Related to our Indebtedness and Ability to Raise Additional
Capital
Restrictions in our Credit Agreement could adversely affect our
business, financial condition, results of operations, ability to
make distributions to unitholders and value of our common units and
our inability to maintain covenant compliance or refinance our
Credit Agreement before its maturity would have a material adverse
effect on our business.
We are dependent upon the earnings and cash flow generated by our
operations in order to meet our debt service obligations under our
Credit Agreement and to allow us to make cash distributions to our
unitholders. The operating and financial restrictions and covenants
in our Credit Agreement and any future financing agreements could
restrict our ability to finance future operations or capital needs
or to expand or pursue our business activities, which may, in turn,
limit our ability to make cash distributions to our unitholders.
Our Credit Agreement limits our ability to, among other
things:
•incur
or guarantee additional debt;
•make
distributions on or redeem or repurchase units;
•make
certain investments and acquisitions;
•incur
certain liens or permit them to exist;
•enter
into certain types of transactions with affiliates;
•merge
or consolidate with other affiliates;
•transfer,
sell or otherwise dispose of assets;
•engage
in a materially different line of business;
•enter
into certain burdensome agreements; and
•prepay
other indebtedness.
Our Credit Agreement also includes covenants requiring us to
maintain certain financial ratios. Our ability to meet those
financial ratios and tests can be affected by events beyond our
control, and we cannot assure you that we will meet those ratios
and tests.
Beginning January 31, 2023 and continuing through maturity, our
ability to make distributions, other restricted payments and
investments will be more limited than prior to closing the
amendment to our Credit Agreement if our Consolidated Net Leverage
Ratio (as defined in our Credit Agreement), pro forma for such
distribution, other restricted payment or investment, exceeds 4.5x,
or our pro forma liquidity is less than
$20 million.
In addition, if we are unable to maintain our existing revenues and
cash flows, particularly in connection with the potential renewal
or extension of our existing take or pay agreements, we may be
required to reduce our indebtedness or fall out of compliance with
one or more of the ratios or tests under our Credit Agreement,
which could result in a default or an event of default that could
enable our lenders to declare the outstanding principal of that
debt, together with accrued and unpaid interest, to be immediately
due and payable along with triggering the
exercise of other remedies. If the amounts outstanding under our
Credit Agreement were to be accelerated, we could face substantial
liquidity problems, might be required to dispose of material assets
or operations to meet our obligations and we could be forced into
bankruptcy or liquidation.
The provisions of our Credit Agreement may affect our ability to
obtain future financing and pursue attractive business
opportunities and our flexibility in planning for, and reacting to,
changes in business conditions.
Our ability to refinance our Credit Agreement before its maturity
in November 2023 is not certain and raises substantial doubt about
our ability to continue as a going concern. This ability depends
on, among other factors, our financial condition and operating
performance, which are subject to prevailing economic and
competitive conditions and certain financial, business and other
factors beyond our control.
Our ability to continue as a going concern is dependent on the
refinancing or extension of the maturity date of our Credit
Agreement, which is currently November 2, 2023. If we are unable to
refinance or extend our Credit Agreement, we would likely not have
sufficient cash on hand or available liquidity to repay the
principal amount owed on the Credit Agreement when it becomes due.
This condition raises substantial doubt about our ability to
continue as a going concern for the next 12 months.
Our ability to refinance our Credit Agreement or successfully
negotiate with our existing lenders for an extension of the
maturity date on our Credit Agreement will depend on the condition
of the capital markets and our financial condition and operating
performance between the date of this report and the maturity date
on the Credit Agreement. Specifically, our ability to refinance or
extend the maturity date of our Credit Agreement may be negatively
impacted if we are unable to renew, extend or replace our recently
expired customer agreements at the Hardisty and Stroud Terminals.
Any refinancing of our indebtedness could be at higher interest
rates, will involve incurrence of fees and expenses, and may
require us to comply with more onerous covenants than we are
currently subject to, which could further restrict our business
operations.
If we cannot refinance or extend the Credit Agreement before its
maturity, we could face substantial liquidity problems, might be
required to dispose of material assets or operations to meet our
obligations, issue equity and use the proceeds to pay down on our
Credit Agreement and we could be forced into bankruptcy or
liquidation.
Our ability to grow requires access to new capital. Tightened
capital markets or increased competition for investment
opportunities could impair our ability to grow.
We regularly consider and evaluate potential acquisitions and other
opportunities to grow our business. Any limitations on our access
to new capital will impair our ability to execute this strategy. If
the cost of such capital becomes too expensive, our ability to
develop or acquire strategic and accretive assets will be limited.
We may not be able to raise the necessary funds on satisfactory
terms, if at all. The primary factors that influence our initial
cost of equity include market conditions, including our then
current unit price, fees we pay to underwriters and other offering
costs, which include amounts we pay for legal and accounting
services. The primary factors influencing our cost of borrowing
include interest rates, credit spreads, covenants, underwriting or
loan origination fees and similar charges we pay to
lenders.
Weak economic conditions, more stringent lending standards, higher
interest rates and volatility in the financial markets have
increased, and could in the future increase, the cost of raising
money in the debt and equity capital markets, while diminishing the
availability of funds from those markets. These factors among
others may limit our ability to execute our growth
strategy.
In September 2014 Energy Capital Partners made a significant
investment in USD. However, to date, Energy Capital Partners has
not provided any additional direct or indirect financial assistance
to USD since its 2014 investment. Furthermore, Energy Capital
Partners must approve any issuances of additional equity by us, and
its determination may be made free of any duty to us or our
unitholders, and members of our general partner’s board of
directors appointed by Energy Capital Partners must approve the
incurrence by us or refinancing of our indebtedness outside of the
ordinary course of business, which may limit our flexibility to
obtain financing and to pursue other business
opportunities.
Our existing debt and any additional debt we incur in the future
may limit our flexibility to obtain financing and to pursue other
business opportunities.
As of December 31, 2022, we had $215.0 million of
outstanding borrowings under our Credit Agreement. We have the
ability to incur additional debt, including up to $275.0 million
under our existing Credit Agreement. Our level of indebtedness
could have important consequences for us, including the
following:
•our
ability to obtain additional financing, if necessary, for working
capital, capital expenditures, acquisitions, or other purposes, may
be impaired, or such financing may not be available on favorable
terms;
•our
funds available for operations, future business opportunities and
cash distributions to unitholders may be reduced by that portion of
our cash flow required to make interest payments on our
debt;
•we
may be more vulnerable to competitive pressures or a downturn in
our business or the economy generally; and
•our
flexibility in responding to changing business and economic
conditions may be limited.
Our ability to service our debt depends upon, among other things,
our financial and operating performance, which will be affected by
prevailing economic conditions and financial, business, regulatory
and other factors, some of which are beyond our control. If our
operating results are not sufficient to service indebtedness, we
will be forced to take actions such as reducing distributions,
reducing or delaying our business activities, acquisitions,
investments or capital expenditures, selling assets or seeking
additional equity capital. We may not be able to take any of these
actions on satisfactory terms or at all.
We may issue additional units without unitholder approval, which
would dilute unitholder interests.
At any time, we may issue an unlimited number of limited partner
interests of any type without the approval of our unitholders and
our unitholders will have no preemptive or other rights (solely as
a result of their status as unitholders) to purchase any such
limited partner interests. Further, neither our partnership
agreement nor our Credit Agreement prohibits the issuance of equity
securities that may effectively rank senior to our common units as
to distributions or liquidations. The issuance by us of additional
common units or other equity securities of equal or senior rank
will have the following effects:
•our
unitholders’ proportionate ownership interest in us will
decrease;
•the
amount of distributable cash flow on each unit may
decrease;
•the
ratio of taxable income to distributions may increase;
•the
relative voting strength of each previously outstanding unit may be
diminished; and
•the
market price of our common units may decline.
Legal and Regulatory Risks Inherent in Our Business
Some of our customers’ operations cross the U.S./Canada border and
are subject to cross-border regulation.
Our customers’ cross border activities subject them to regulatory
matters, including import and export licenses, tariffs, Canadian
and U.S. customs and tax issues and toxic substance certifications.
Such regulations include the Short Supply Controls of the Export
Administration Act, the U.S.-Mexico-Canada Agreement and the Toxic
Substances Control Act. Violations of these licensing, tariff and
tax reporting requirements could result in the imposition of
significant administrative, civil and criminal penalties on our
customers. Our revenue and cash flows could decline and our ability
to make cash distributions to our unitholders could be materially
and adversely affected should our customers fail to comply with
these cross-border regulations.
Changes in the provincial royalty rates and drilling incentive
programs in Canada could decrease the oil and gas exploration and
production activities in Canada, which could adversely affect the
demand for our terminalling services.
Certain provincial governments collect royalties on the production
from lands owned by the government of Canada. These fiscal royalty
regimes are reviewed and adjusted from time to time by the
respective provincial governments for appropriateness and
competitiveness. Any increase in the royalty rates assessed by, or
any decrease in the drilling incentive programs offered by, a
provincial government could negatively affect the drilling
activity, which could adversely affect the demand for our
terminalling services.
Government regulation of oil production could have an adverse
effect on our throughput volumes and distributable cash
flow.
On December 3, 2018, the Alberta Government announced a temporary
8.7% cut (or a decrease of 325,000 barrels per day) in the
production of raw crude oil and bitumen at facilities subject to
its jurisdiction, starting on January 1, 2019. In late August 2019,
the Alberta Government extended the curtailment end date to
December 31, 2020, with possible earlier termination.
During 2019, however, the Alberta Government increased the allowed
production levels. For example, in late October 2019, the Alberta
Government announced a special production allowance, whereby
effective November 8, 2019, new wells drilled for conventional oil
are exempt and, beginning with the December 2019 production month,
producers were allowed to apply to produce above their curtailment
order, as long as this extra production is shipped out of Alberta
through additional rail capacity.
In late October 2020, the Alberta Government announced that while
the government would extend its regulatory authority to curtail oil
production through December 2021, it would not set production
limits as of December 2020. The Alberta Government has stated that
the curtailment rules and production limits are not needed at this
time.
This and similar future actual or anticipated governmental
restrictions on the production of crude oil in the producing
regions served by our terminals may cause our customers to reduce
their production activities and delay or cancel new projects, which
could in turn reduce the demand for our terminalling services.
Except to the extent of our take-or-pay type arrangements,
reductions in demand for our terminalling services resulting from
governmentally imposed production cuts could reduce our cash flows
and results of operations, and limit our ability to execute new
terminalling services contracts, or extend existing terminalling
services contracts.
Implementation of the Renewable Fuels Standard Program under the
Clean Air Act, or the RFS, could affect oil and gas operations as
well as the renewable diesel project.
Under the RFS, EPA sets annual volume obligations, or RVOs, that
oil refiners must meet either by blending biofuels into
conventional transportation fuel or purchasing credits, known as
Renewable Identification Numbers or RINs, through a trading market
sufficient to satisfy their annual obligation. Among other factors,
supply and demand for transportation fuel as well as the levels of
renewable volumes set by EPA affect the market price of biofuel and
RINs. On July 1, 2022, EPA issued its final RVOs for compliance
years 2020, 2021 and 2022. On December 1, 2022, EPA
announced a proposed rule to established RVOs for 2023, 2024 and
2025. The proposed volume obligations increase over those three
years. EPA held a public hearing on January 10-11, 2023 for the
proposed rule, and the comment period closed on February 10, 2023.
EPA anticipates taking final action on the proposal by June 2023.
EPA also recently denied 69 pending exemption petitions submitted
by small refineries for economic hardship waivers from annual RVO
requirements. EPA’s continued implementation of the program along
with supply and demand for transportation fuel will continue to
affect the price of biofuel, including renewable diesel, and the
price RINs.
Our business could be adversely affected if service on the
railroads is interrupted or if more stringent regulations are
adopted regarding railcar design or the transportation of crude oil
by rail.
We do not own or operate the railroads on which crude oil carrying
railcars are transported; however, we do manage a railcar fleet
that is subject to regulations governing railcar design and
manufacture.
The volume of crude oil and liquid hydrocarbons transported in
North America by rail has increased substantially in prior years.
High-profile accidents involving crude oil carrying trains in
recent years, in conjunction with increased use of
rail
transportation, have raised concerns about the environmental and
safety risks associated with crude oil transport by rail and
railcar design.
Certain of the railroads serving our terminals have in the past and
are currently considering imposing tariffs, fees or other
limitations on the utilization of older railcar designs. These
tariffs, fees and limitations could have the effect of imposing
limits on the use of railcars that are more stringent than current
regulatory standards, and could reduce the size of the overall
railcar fleet available to be loaded at our terminals and increase
the costs of obtaining usable railcars. Similar to other industry
participants, compliance with existing and any additional
environmental laws and regulations, or the imposition of additional
tariffs, fees or limitations on the transportation of crude oil in
certain railcars or all railcars by the railroads, could increase
our overall cost of business, including our capital costs to
construct, maintain, operate and upgrade equipment and facilities,
or the costs of our customers, which may reduce the attractiveness
of rail transportation and limit our ability to extend existing
agreements or attract new customers.
DOT and Transport Canada have also required operators to take
certain precautions relating to rail routing, and mandated
reductions in train speed and the implementation of new braking
technology, to address rail safety concerns. The recent changes to
U.S. and Canadian regulations and the adoption of additional
federal, state, provincial or local laws or regulations, including
any additional voluntary measures by the rail industry regarding
railcar design or crude oil and liquid hydrocarbon rail transport
activities, or efforts by local communities to restrict or limit
rail traffic involving crude oil, could affect our business by
increasing compliance costs and decreasing demand for our services,
which could adversely affect our financial position and cash
flows.
Moreover, any disruptions in the operations of railroads, including
those due to shortages of railcars or qualified personnel,
weather-related problems, flooding, drought, accidents, worldwide
health events including the recent coronavirus outbreak, mechanical
difficulties, strikes, lockouts or bottlenecks, could adversely
impact our customers’ ability to move their products and, as a
result, could affect our business. For example, the recent contract
dispute between railroads and some of the industry’s major unions
threatened a rail shutdown with the potential for national economic
consequences. To avoid a strike, on November 30, 2022, the House
passed a bill that would force unions to adopt an earlier labor
agreement. On December 1, 2022, the Senate passed its version of
the bill. On December 2, 2022, President Biden signed the bill into
law, averting a strike.
Changes in, or challenges to, our pipeline rates and other terms
and conditions of service could have a material adverse effect on
our financial condition and results of operations.
Our dedicated crude oil pipelines, CCR Pipeline and SCT Pipeline,
are subject to regulation by various federal, state and local
agencies. FERC regulates the interstate transportation services
provided on these pipelines under the ICA, the EPAct 1992 and the
rules and regulations promulgated under those laws. FERC
regulations require that rates for interstate service on pipelines
that transport crude oil and refined petroleum products
(collectively referred to as “petroleum pipelines”) and certain
other liquids be just and reasonable, not be unduly discriminatory
and not confer any undue preference upon any shipper. FERC
regulations also require interstate common carrier petroleum
pipelines to file with FERC and publicly post tariffs stating their
interstate transportation rates and terms and conditions of
service. Under the ICA, FERC or interested persons may challenge
existing or changed rates or services. FERC is authorized to
investigate such changes and may suspend the effectiveness of a new
rate upon its filing for up to seven months. A successful rate
challenge could result in a common carrier paying refunds together
with interest for the period during which the challenged rate was
in effect. FERC may also order a pipeline to change its rates, and
may require a common carrier to pay shippers reparations for
damages sustained for a period up to two years prior to the filing
of a complaint.
Intrastate transportation services provided by CCR Pipeline, the
crude oil pipelines serving our Casper Terminal, are subject to
regulation by the Wyoming Public Service Commission. The Wyoming
Public Service Commission uses a complaint-based system of
regulation, both as to matters involving rates and priority of
access. In response to a complaint, the Wyoming Public Service
Commission could limit our ability to increase our rates or to set
rates based on our costs or order us to reduce our rates and
require the payment of refunds to shippers. If we were to provide
intrastate transportation services through our SCT Pipeline, the
crude oil pipeline serving our Stroud Terminal, we could elect to
file a tariff covering such services with the Oklahoma Corporation
Commission, which
does not require such filings and does not regulate intrastate
crude oil pipeline rates but does make filed pipeline tariffs
available for public viewing.
FERC and state regulatory commissions generally have not
investigated petroleum pipeline rates unless the rates are the
subject of a shipper protest or a complaint. However, FERC or the
Wyoming Public Service Commission could investigate our rates on
their own initiative or at the urging of a third party. If FERC or
the Wyoming Public Service Commission were to direct us to lower
our tariff rates or decline to permit any proposed rate increase or
other material changes to the types, or terms and conditions, of
service we might propose, the profitability of our CCR Pipeline and
terminal located in Casper, Wyoming, or of our SCT Pipeline and
terminal located in Stroud, Oklahoma, could suffer. In addition, if
we were permitted to raise our tariff rates for services provided
through the CCR Pipeline or SCT Pipeline but the rate increase was
suspended for the maximum statutory period, there might be a
significant delay between the time the tariff rate increase is
approved and the time that the rate increase actually goes into
effect, which could adversely affect our cash flow. Furthermore,
competition from other pipelines and terminals may prevent us from
raising our tariff rates even if FERC or the Wyoming Public Service
Commission permits us to do so.
FERC and the Wyoming Public Service Commission periodically
implement new rules, regulations and policies that can have a
bearing on petroleum pipeline rates and terms and conditions of
service. New initiatives or orders may adversely affect the rates
charged for our services or otherwise adversely affect our
financial condition, results of operations and cash flows and our
ability to make cash distributions to our unitholders.
We operate in a highly regulated industry and increased costs of
compliance with, or liability for violation of, existing or future
laws, regulations and other requirements could significantly
increase our costs of doing business, thereby adversely affecting
our profitability.
Our industry is subject to laws, regulations and other requirements
including, but not limited to, those relating to the environment,
safety, working conditions, public accessibility and other
requirements. These laws and regulations are enforced by federal
agencies including, but not limited to, the EPA, the DOT, PHMSA,
the FERC, the FRA, the Federal Motor Carrier Safety Administration,
or FMCSA, OSHA, state agencies such as the Texas Commission on
Environmental Quality, the Railroad Commission of Texas, the
California Environmental Protection Agency, or Cal/EPA, the
California Public Utilities Commission, or
CPUC, and Canadian agencies such as Environment Canada and
Transport Canada as well as numerous other state and federal
agencies. Ongoing compliance with, or a violation of, these laws,
regulations and other requirements could have a material adverse
effect on our business, financial condition, results of operations,
and ability to make quarterly distributions to our
unitholders.
In addition, these laws and regulations, and the interpretation or
enforcement thereof, are subject to frequent change by regulatory
authorities and we are unable to predict the ongoing cost to us of
complying with these laws and regulations or the future impact of
these laws and regulations on our operations. For example,
see
Item 1. Business—Impact of
Regulations—Climate
Change
in this Annual Report for information about certain actions the
Biden Administration has taken targeting greenhouse gas emissions.
Violation of environmental laws, regulations and permits can result
in the imposition of significant administrative, civil and criminal
penalties, injunctions and construction bans or
delays.
Under various federal, state, provincial and local environmental
requirements, as the owner or operator of terminals, we may be
liable for the costs of removal or remediation of contamination at
our existing locations, whether we knew of, or were responsible
for, the presence of such contamination. The failure to timely
report and properly remediate contamination may subject us to
liability to third parties and may adversely affect our ability to
sell or rent our property or to borrow money using our property as
collateral. Additionally, we may be liable for the costs of
remediating third-party sites where hazardous substances from our
operations have been transported for treatment or disposal,
regardless of whether we own or operate that site. In the future,
we may incur substantial expenditures for investigation or
remediation of contamination that has not yet been discovered at
our current or former locations or locations that we may
acquire.
A discharge of hydrocarbons or hazardous substances into the
environment could, to the extent the event is not insured or
insurance is not otherwise available, subject us to substantial
expense, including the cost to respond in compliance with
applicable laws and regulations, fines and penalties, natural
resource damages and claims made by employees, neighboring
landowners and other third parties for personal injury and property
damage. We may experience future catastrophic sudden or gradual
releases into the environment from our pipeline or terminals or
discover historical releases that were previously unidentified or
not assessed. Although our inspection and testing programs are
designed in compliance with applicable legal requirements to
prevent, detect and address these releases promptly, damages and
liabilities incurred due to any future environmental releases from
our assets have the potential to substantially affect our business.
Such discharges could also subject us to media and public scrutiny
that could have a negative effect on the value of our common
units.
Environmental, safety and other regulations are stringent.
Penalties for violations have increased and may increase further in
amount, and new environmental laws and regulations may be proposed
and enacted. Moreover, interpretations of existing requirements
change from time to time. While we cannot predict the impact that
future environmental, health and safety requirements or changed
interpretations of existing requirements may have on our
operations, such future activity may result in material
expenditures to ensure our continued compliance and material costs
if we are found not to be in compliance. Such future activity could
adversely affect our operations, cash flow and net
revenues.
We are subject to stringent environmental and safety laws and
regulations that may expose us to significant costs and
liabilities.
Our operations are subject to stringent and complex federal, state,
provincial and local environmental and safety laws and regulations
that govern the discharge of materials into the environment or
otherwise relate to environmental protection.
These laws and regulations may impose numerous obligations that are
applicable to our operations, including the acquisition of permits
to conduct regulated activities, the incurrence of capital or
operating expenditures to limit or prevent releases of materials
from pipelines, railcars and terminals, and the imposition of
substantial liabilities and remedial obligations for pollution
resulting from our operations or at locations currently or
previously owned or operated by us. Numerous governmental
authorities, such as the EPA, the DOT, Environment Canada,
Transport Canada and analogous state and provincial agencies, have
the power to enforce compliance with these laws and regulations and
the permits issued under them, oftentimes requiring difficult and
costly corrective actions or costly pollution control measures.
Failure to comply with these laws, regulations and permits may
result in the assessment of administrative, civil and criminal
penalties, the imposition of remedial obligations and the issuance
of injunctions limiting or preventing some or all of our
operations. In addition, we may experience a delay in obtaining or
be unable to obtain required permits or regulatory authorizations,
which may cause us to lose potential and current customers,
interrupt our operations and limit our growth and
revenue.
We may incur significant environmental costs and liabilities in
connection with our operations due to historical industry
operations and waste disposal practices, our handling of
hydrocarbon and other wastes and potential emissions and discharges
related to our operations. Joint and several, strict liability may
be incurred, without regard to fault, under certain of these
environmental laws and regulations in connection with discharges or
releases of hydrocarbon wastes on, under, or from our properties
and terminals. In addition, changes in environmental laws occur
frequently, and any such changes that result in additional
permitting obligations or more stringent and costly waste handling,
storage, transport, disposal or remediation requirements could have
a material adverse effect on our operations or financial position.
We may not be able to recover all or any of these costs from
insurance.
Also, some states have adopted, and other states are considering
adopting, legal requirements that could impose more stringent
permitting, public disclosure, or well construction requirements on
oil and gas production. States or localities could also elect to
prohibit hydraulic fracturing altogether, as the State of New York
announced in 2014, and the federal government could limit
development, generally, on federal lands. While our operations are
not directly affected by these actions, their impact on our oil and
natural gas exploration and production customers could result in a
decreased demand for the services that we provide.
We could incur substantial costs or disruptions in our business if
we cannot obtain or maintain necessary permits and authorizations
or otherwise comply with health, safety, environmental and other
laws and regulations.
Our operations require authorizations and permits that are subject
to revocation, renewal or modification and can require operational
changes to limit the effect or potential effect on the environment
and/or health and safety. A violation of authorization or permit
conditions or other legal or regulatory requirements could result
in substantial fines, criminal sanctions, permit revocations,
injunctions, and/or facility shutdowns. In addition, major
modifications of our operations could require modifications to our
existing permits or upgrades to our existing pollution control and
safety-related equipment. Any or all of these matters could have a
material adverse effect on our business, financial condition,
results of operations, and ability to make quarterly distributions
to our unitholders.
Legislation, regulatory initiatives, litigation and investor
sentiment relating to climate change could result in increased
operating costs, reduced demand for the services we provide and
limits on our access to capital.
In response to studies suggesting that emissions of carbon dioxide,
methane and certain other gases may be contributing to warming of
the Earth’s atmosphere, over 190 countries, including the United
States and Canada, reached an agreement to reduce GHG emissions at
the Paris climate conference in December 2015. The terms of the
Paris treaty to reduce GHG emissions were to become effective in
2020. The United States formally rejoined the agreement in February
2021.
In addition, the U.S. Congress has considered legislation to
restrict or regulate emissions of GHGs. Comprehensive climate
legislation appears unlikely to be passed by either house of
Congress in the near future, although additional energy legislation
and other initiatives may be proposed that address GHGs and related
issues.
In 2022, Congress passed the Inflation Reduction Act, which focused
significantly on reducing GHG emissions. The IRA seeks to achieve
these reductions by encouraging a shift towards the manufacturing
and consumption of renewable energy across all sectors of the
economy—especially in the industrial and transportation sectors.
The IRA allocated: $161 billion for clean energy tax credits; $40
billion for air pollution, hazardous materials, transportation and
infrastructure; $37 billion for individual clean energy incentives;
$37 billion for clean manufacturing tax credits; $36 billion for
clean fuel and vehicle tax credits; $35 billion for conservation,
rural development, and forestry; $27 billion for building
efficiency, electrification, transmission, industrial, and DOE
grants and loans; and $14 billion for other energy and climate
spending programs. The IRA authorized EPA to administer additional
voluntary, incentive based programs to achieve GHG emissions
reductions; it did not grant EPA additional regulatory authority to
impose GHG emissions limits beyond EPA’s existing authority under
the Clean Air Act.
In addition, almost half of the states (including California and
Texas, in which we operate), either individually or through
multi-state regional initiatives, have begun to address GHG
emissions, primarily through the planned development of emission
inventories or regional GHG cap and trade programs. Although most
of the state-level initiatives have to date been focused on large
sources of GHG emissions, such as electric power plants, it is
possible that smaller sources could become subject to GHG-related
regulation. Depending on the particular program, we could be
required to control emissions or to purchase and surrender
allowances for GHG emissions resulting from our operations, and to
the extent federal or state measures are successful in reaching
hydrocarbon fuel usage, they could have an indirect effect on our
business.
Independent of Congress, the EPA has adopted regulations to address
GHG emissions under its existing CAA authority. For example, in
2012, EPA issued performance standards governing emissions of
Volatile Organic Compounds (VOCs) from new sources in the oil and
gas sector. EPA revised these regulations in 2016 to govern
methane. In 2020, EPA repealed key components of the 2016 rule, but
those revisions were reversed by Congress in 2021 through the
passage of a Congressional Review Act Resolution of Disapproval
that was signed by President Biden in June 2021. EPA has continued
to implement the 2016 rule and has recently proposed updated
regulations governing methane emissions from new and existing
sources in the oil and gas sector. In 2021, EPA proposed updated
Clean Air Act performance standards governing methane emissions
from new and existing sources in the oil and gas sector. In 2022,
EPA issued a supplemental notice proposing to increase emissions
standards beyond the
2021 proposal and proposing requirements for additional sources not
covered by the 2021 notice. The notice specifically identifies oil
and natural gas operations as the nation’s largest industrial
source of methane, as well as a leading source for other air
pollutants such as smog-forming VOCs and benzene. EPA estimates
that, in 2030, the standards in its supplemental proposal (if
finalized) would reduce methane emissions from covered sources by
87 percent below 2005 levels. Additionally, DOI recently
announced a proposed rule from the Bureau of Land Management to
reduce methane releases from venting, flaring, and leaks from oil
and gas production on public and tribal land.
EPA has also regulated GHG emissions from motor vehicles. In 2009,
the EPA adopted rules regarding regulation of GHG emissions from
new light duty motor vehicles, which it later made more stringent
in 2012 and maintained in 2016. In 2020, EPA finalized GHG
standards for model years 2021-26 that were less stringent than
those finalized in 2012 and 2016. In December 2021, EPA finalized
revised GHG standards for model years 2023-26 to make them more
stringent. In parallel, the National Highway Traffic Safety
Administration, or NHTSA, has proposed more stringent Corporate
Average Fuel Economy, or CAFE, standards for model years 2024-26.
On March 14, 2022, EPA also reversed a prior decision and
allowed California to once again set its own, more-stringent GHG
standards for new motor vehicles under section 209 of the Clean Air
Act, which would apply in California and roughly a dozen other
states that have adopted California’s standards. Similarly, on
December 31, 2021, NHTSA issued a final rule withdrawing
regulations issued during the Trump Administration that preempted
California’s authority to set more-stringent GHG standards for new
motor vehicles.
In addition, in September 2009, the EPA issued a final rule
requiring the monitoring and reporting of GHG emissions from
specified large GHG emission sources in the United States. In
November 2010, EPA expanded this existing GHG emissions reporting
rule to petroleum facilities, requiring reporting of GHG emissions
by regulated petroleum facilities to the EPA beginning in 2012 and
annually thereafter. In October 2015, EPA further expanded its GHG
emissions reporting program to include onshore petroleum and
natural gas gathering and boosting activities, as well as natural
gas transmission pipelines. We monitor and report our facilities’
GHG emissions. However, operational or regulatory changes or
stakeholder demands could require additional monitoring and
reporting at some or all of our other facilities at a future date.
In 2010, the EPA also issued a final rule, known as the “Tailoring
Rule,” that makes certain large stationary sources and modification
projects subject to permitting requirements for GHG emissions under
the CAA.
EPA has attempted to regulate GHGs from the coal and gas-fired
electric generating sector. In October 2015, the EPA finalized the
Clean Power Plan, or CPP, which imposed additional obligations on
the coal and gas-fired electric generating sector to reduce GHG
emissions and which generally promoted a reduction in the demand
for fossil fuels. CPP was challenged and was stayed by the U.S.
Supreme Court before its effective date. Subsequently, the EPA
concluded it lacked legal authority to issue CPP, repealed it, and
replaced it with the Affordable Clean Energy rule, or ACE. In
January 2021, the U.S. Court of Appeals for the D.C. Circuit
vacated the EPA’s repeal and replacement of the CPP. The Supreme
Court agreed to hear an appeal of this decision and issued its
opinion in West Virginia v. EPA in June 2022. The decision
curtailed agency authority to enact sweeping regulations without
clear statutory authorization. The issue in West Virginia was
whether the Clean Air Act empowered EPA to transform the electric
generation sector through the Clean Power Plan. The Court held that
Congress had not delegated broad authority to EPA under the Clean
Air Act to restructure the energy industry by requiring existing
power plants to shift to different forms of energy production. In
doing so, the Court reaffirmed the principle that agency action
with vast economic and political significance requires a clear
delegation from Congress. The Court’s application of the “major
questions doctrine” indicates its commitment to limiting executive
agencies’ regulation of particularly significant matters to
circumstances where Congress clearly delegated such regulatory
authority to the agency.
The Court’s decision makes it much more difficult for agencies to
justify extraordinary and far-reaching regulatory
initiatives.
Although it is not possible at this time to predict exactly how
potential future laws or regulations addressing GHG emissions or
oil and gas development in Canada or the United States would impact
our business, any future federal, state or provincial laws or
implementing regulations that may be adopted to address GHG
emissions could require us to incur increased operating costs,
could adversely affect demand for the crude oil and other liquid
hydrocarbons we handle in connection with our services, and could
adversely affect demand for our services by restricting or
prohibiting our customers from conducting oil and gas production in
certain areas. Moreover, the
change in a regulation landscape means we may incur additional
expenses that would not be applicable in a steady set of
regulations. The potential increase in the costs of our operations
resulting from any legislation or regulation to restrict emissions
of GHGs could include new or increased costs to operate and
maintain our facilities, install new emission controls on our
facilities, acquire allowances to authorize our GHG emissions, pay
any taxes related to our GHG emissions and administer and manage a
GHG emissions program. While we may be able to include some or all
of such increased costs in the rates charged by our terminals, such
recovery of costs is uncertain. Moreover, incentives to conserve
energy or use alternative energy sources could reduce demand for
oil, resulting in a decrease in demand for our services. We cannot
predict with any certainty at this time how these possibilities may
affect our operations.
Scientists have concluded that increasing concentrations of GHGs in
the earth’s atmosphere may produce climate changes that have
significant physical effects, such as increased frequency and
severity of storms, floods and other climatic events; if any such
effects were to occur, they could have an adverse effect on our
operations. For example, the projected severe effects of climate
change have the potential to directly affect our facilities and
operations and those of our customers, which could result in more
frequent and severe disruptions to our business and those of our
customers, increased costs to repair damaged facilities or maintain
or resume operations, and increased insurance costs. In addition,
there have been increasing efforts in recent years to influence the
investment community, including investment advisors and certain
sovereign wealth, pension and endowment funds promoting divestment
of fossil fuel equities and pressuring lenders to limit funding to
companies engaged in the extraction of fossil fuel reserves. Such
environmental activism and initiatives aimed at limiting climate
change and reducing air pollution could interfere with our business
activities, operations and ability to access capital. Finally,
increasing attention to the risks of climate change has resulted in
an increased possibility of lawsuits or investigations brought by
public and private entities against oil and natural gas
companies.
Should we be targeted by any such litigation or investigations, we
may incur liability, which, to the extent that societal pressures
or political or other factors are involved, could be imposed
without regard to the causation of or contribution to the asserted
damage, or to other mitigating factors.
The implementation of derivative regulations could have an adverse
effect on our ability to use derivative contracts to reduce the
effect of foreign exchange, interest rate and other risks
associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act
(“Dodd-Frank Act”), establishes federal oversight and regulation of
the over-the-counter derivatives market and entities that
participate in that market. Although the U.S. Commodity Futures
Trading Commission and the other relevant regulators have finalized
most of the regulations under the Dodd-Frank Act, they continue to
review and refine initial rulemakings through additional
interpretations and supplemental rulemakings.
As a result, it is not possible at this time to predict the
ultimate effect of the rules and regulations on our business and
while most of the regulations have been adopted, any new
regulations or modifications to existing regulations may increase
the cost of derivative contracts, materially alter the terms of
derivative contracts, reduce the availability of derivatives to
protect against risks we encounter and reduce our ability to
monetize or restructure our existing derivative contracts. If we
reduce our use of derivatives as a result of the legislation and
regulations, our results of operations may become more volatile and
our cash flows may be less predictable, which could adversely
affect our ability to plan for and fund capital expenditures. Any
of these consequences could have a material adverse effect on us,
our financial condition, our results of operations and our cash
flows.
Risks Inherent in Our Master Limited Partnership Ownership
Structure
The credit and risk profile of our general partner and its owner,
USD Group LLC, could adversely affect our credit ratings and risk
profile, which could increase our borrowing costs or hinder our
ability to raise capital and additionally have a direct impact on
our ability to pay our minimum quarterly distribution.
The credit and business risk profiles of our general partner and
USD Group LLC, neither of which has a rating from any credit
agency, may be factors considered in credit evaluations of us. This
is because our general partner, which is owned by USD Group LLC,
controls our business activities, including our cash distribution
policy and growth strategy. Any adverse change in the financial
condition of USD Group LLC, including the degree of its financial
leverage and its dependence on cash flow from us to service its
indebtedness, if any, may adversely affect
our credit ratings and risk profile. If we were to seek a credit
rating in the future, our credit rating may be adversely affected
by the leverage of our general partner or USD Group LLC, as credit
rating agencies such as Standard & Poor’s Ratings Services and
Moody’s Investors Service may consider the leverage and credit
profile of USD Group LLC and its affiliates because of their
ownership interest in and control of us. Any adverse effect on our
credit rating would increase our cost of borrowing or hinder our
ability to raise financing in the capital markets, which would
impair our ability to grow our business and make distributions to
common unitholders.
Our general partner and its affiliates, including USD, have
conflicts of interest with us and limited duties to us and our
unitholders, and they may favor their own interests to our
detriment and that of our unitholders.
USD indirectly owns a 51.9% limited partner interest as of
December 31, 2022, and indirectly owns and controls our
general partner, which owns a non-economic general partner interest
in us. Although our general partner has a duty to manage us in a
manner that is not adverse to the best interests of our partnership
and our unitholders, the directors and officers of our general
partner also have a duty to manage our general partner in a manner
that is not adverse to the best interests of its owner, USD.
Conflicts of interest may arise between USD and its affiliates,
including our general partner, on the one hand, and us and our
unitholders, on the other hand. In resolving these conflicts, the
general partner may favor its own interests and the interests of
its affiliates, including USD, over the interests of our common
unitholders. These conflicts include, among others, the following
situations:
•neither
our Third Amended and Restated Agreement of Limited Partnership of
USD Partners LP, or our partnership agreement, nor any other
agreement requires USD to pursue a business strategy that favors
us, and the directors and officers of USD have a fiduciary duty to
make these decisions in the best interests of the members of USD.
USD may choose to shift the focus of its investment and growth to
areas not served by our assets;
•USD
may be constrained by the terms of its debt instruments, if any,
from taking actions, or refraining from taking actions, that may be
in our best interests;
•our
partnership agreement replaces the fiduciary duties that would
otherwise be owed by our general partner with contractual standards
governing its duties, limiting our general partner’s liabilities
and restricting the remedies available to our unitholders for
actions that, without the limitations, might constitute breaches of
fiduciary duty;
•except
in limited circumstances, our general partner has the power and
authority to conduct our business without unitholder
approval;
•our
general partner will determine the amount and timing of asset
purchases and sales, borrowings, issuance of additional partnership
securities and the creation, reduction or increase of cash
reserves, each of which can affect the amount of cash that is
distributed to our unitholders;
•our
general partner will determine the amount and timing of many of our
cash expenditures and whether a cash expenditure is classified as
an expansion capital expenditure, which would not reduce operating
surplus, or a maintenance capital expenditure, which would reduce
our operating surplus. This determination can affect the amount of
cash that is distributed to our unitholders and to our general
partner, and the amount of adjusted operating surplus generated in
any given period;
•our
general partner will determine which costs incurred by it are
reimbursable by us;
•our
general partner may cause us to borrow funds in order to permit the
payment of cash distributions;
•our
partnership agreement does not restrict our general partner from
causing us to pay it or its affiliates for any services rendered to
us or entering into additional contractual arrangements with any of
these entities on our behalf;
•our
general partner intends to limit its liability regarding our
contractual and other obligations;
•our
general partner may exercise its right to call and purchase all of
the common units not owned by it and its affiliates if it and its
affiliates own more than 80.0% of the common units;
•our
general partner controls the enforcement of obligations owed to us
by our general partner and its affiliates; and
•our
general partner decides whether to retain separate counsel,
accountants or others to perform services for us.
Under the terms of our partnership agreement, the doctrine of
corporate opportunity, or any analogous doctrine, does not apply to
our general partner or any of its affiliates, including its
executive officers, directors and owners. Any such person or entity
that becomes aware of a potential transaction, agreement,
arrangement or other matter that may be an opportunity for us will
not have any duty to communicate or offer such opportunity to us.
Any such person or entity will not be liable to us or to any
limited partner for breach of any fiduciary duty or other duty by
reason of the fact that such person or entity pursues or acquires
such opportunity for itself, directs such opportunity to another
person or entity or does not communicate such opportunity or
information to us. This may create actual and potential conflicts
of interest between us and affiliates of our general partner and
result in less than favorable treatment of us and our unitholders.
Please refer to the discussion under
Part III, Item 13.
Certain
Relationships and Related Transactions, and Director
Independence
in this Annual Report
regarding conflicts of interests and fiduciary duties of our
general partner.
Affiliates of our general partner, including USD, and Energy
Capital Partners and its affiliates may compete with us, and none
of Energy Capital Partners, our general partner or any of their
respective affiliates have any obligation to present business
opportunities to us.
Neither our partnership agreement nor the Omnibus Agreement
prohibits USD or any other affiliates of our general partner or
Energy Capital Partners or its affiliates from owning assets or
engaging in businesses that compete directly or indirectly with us.
In addition, USD and other affiliates of our general partner, and
Energy Capital Partners and its affiliates may acquire, construct
or dispose of additional midstream infrastructure in the future
without any obligation to offer us the opportunity to purchase any
of those assets. For example, USD Group LLC currently owns the
right to construct and further develop the West Colton Terminal as
it relates to renewable diesel opportunities as well as the Stroud
Terminal as it relates to all future terminalling services
opportunities. If we are unable to acquire these facilities from
USD Group LLC, these expansions may compete directly with our West
Colton and Stroud Terminals for future throughput volumes, which
may impact our ability to enter into new Terminal Services
Agreements, including with our existing customers, following the
termination of our existing agreements or the terms thereof and our
ability to compete for future spot volumes. As a result,
competition from USD and other affiliates of our general partner
could materially adversely impact our results of operations and
distributable cash flow to unitholders.
Energy Capital Partners has substantial influence over USD and our
general partner, and its interests may differ from those of USD, us
and our public unitholders.
Energy Capital Partners currently has the right to appoint three of
seven members of USD’s board of directors and three of nine members
of our general partner’s board of directors and may in the future
have the right to appoint the majority of USD’s board of directors
if it invests a specified amount in USD, or certain other
conditions are met. For so long as Energy Capital Partners is able
to appoint more than one member to USD’s board of directors, USD
will not, and will not permit its subsidiaries, including us and
our general partner, to take or agree to take certain actions
without the affirmative vote of Energy Capital Partners, including,
among others, any acquisitions or dispositions and any issuances of
additional equity interests in us. Energy Capital Partners may make
these decisions free of any duty to us and our unitholders.
Additionally, members of our general partner’s board of directors
appointed by Energy Capital Partners, if any, must approve any
distributions made by us, any incurrence of debt by us and the
approval, modification or revocation of our budget. As a result,
Energy Capital Partners is able to significantly influence the
management and affairs of USD and our general partner, including
the amount of distributions we make, if any, our policies and
operations, the appointment of management, future issuances of
securities, amendments to our organizational documents and the
entering into of extraordinary transactions. The
interests of Energy Capital Partners may not in all cases be
aligned with the interests of our common unitholders and, in
certain situations, they have no duty to us or our
unitholders.
Energy Capital Partners may have an interest in pursuing
acquisitions, divestitures and other transactions that, in its
judgment, could enhance its equity investment, even though such
transactions might involve risks to our common unitholders, or
Energy Capital Partners may have an interest in not pursuing
transactions that would otherwise benefit us. For example, Energy
Capital Partners could influence us to make acquisitions,
investments and capital expenditures that increase our indebtedness
or to sell revenue-generating assets or to not make such
acquisitions, investments or capital expenditures. In addition,
Energy Capital Partners may have different tax considerations that
could influence its position, including regarding whether and when
to dispose of assets and whether and when to incur new or refinance
existing indebtedness. In addition, the structuring of future
transactions by our general partner may take into consideration
these tax or other considerations even where no similar benefit
would accrue to our common unitholders or us. Energy Capital
Partners may make the decisions to approve any acquisition or
disposition by us free of any duty to us and our
unitholders.
Energy Capital Partners’ influence on USD and our general partner
may have the effect of delaying, preventing or deterring a change
of control of our company. Energy Capital Partners and its
affiliates and affiliated funds are in the business of making
investments in companies in the energy industry and may from time
to time acquire and hold interests in businesses that compete
directly or indirectly with us. USD’s limited liability company
agreement provides that Energy Capital Partners shall not have any
duty to refrain from engaging directly or indirectly in the same or
similar business activities or lines of business as us or any of
our subsidiaries, and that in the event that Energy Capital
Partners acquires knowledge of a potential transaction or matter
which may be a corporate opportunity for itself and us or any of
our subsidiaries, neither we nor any of our subsidiaries shall, to
the fullest extent permitted by law, have any expectancy in such
corporate opportunity, and Energy Capital Partners shall not, to
the fullest extent permitted by law, have any duty to communicate
or offer such corporate opportunity to us or any of our
subsidiaries and may pursue or acquire such corporate opportunity
for itself or direct such corporate opportunity to another person.
Energy Capital Partners and its affiliates may also pursue
acquisition opportunities that are complementary to our business
and, as a result, those acquisition opportunities may not be
available to us. Please refer to the discussion under
Part III, Item 10.
Directors,
Executive Officers and Corporate Governance—Special
Approval Rights of Energy Capital Partners
in this Annual Report regarding the rights of Energy Capital
Partners.
Energy Capital Partners, upon giving written notice, shall have the
right to compel USD to effect the total sale of Energy Capital
Partners’ interests in USD, which we refer to as an ECP Exit. Such
a sale could include an acquisition by the remaining owners of USD
of Energy Capital Partners’ interests in USD or an initial public
offering of USD. If the ECP Exit has not been completed within 180
days of the date USD receives notice of Energy Capital Partners’
desire to sell, Energy Capital Partners shall have the right to
compel USD to effect a total sale of USD pursuant to an auction
process on terms and conditions determined by, and in a process
managed by, the members of USD’s board of directors that are
appointed by Energy Capital Partners, provided that certain
conditions in connection with the sale are met.
Our partnership agreement replaces our general partner’s fiduciary
duties to holders of our common units with contractual standards
governing its duties.
Our partnership agreement contains provisions that eliminate the
fiduciary standards to which our general partner would otherwise be
held by state fiduciary duty law and replaces those duties with
several different contractual standards. For example, our
partnership agreement permits our general partner to make a number
of decisions in its individual capacity, as opposed to in its
capacity as our general partner, free of any duties to us and our
unitholders. This provision entitles our general partner to
consider only the interests and factors that it desires and
relieves it of any duty or obligation to give any consideration to
any interest of, or factors affecting, us, our affiliates or our
limited partners. By purchasing a common unit, a unitholder is
treated as having consented to the provisions in our partnership
agreement, including the provisions discussed above. Please refer
to the discussion under
Part III, Item 13.
Certain
Relationships and Related Transactions, and Director
Independence
in this Annual Report regarding conflicts of interests and
fiduciary duties of our general partner.
Our partnership agreement restricts the remedies available to
holders of our common units for actions taken by our general
partner that might otherwise constitute breaches of fiduciary
duty.
Our partnership agreement contains provisions that restrict the
remedies available to unitholders for actions taken by our general
partner that might otherwise constitute breaches of fiduciary duty
under state fiduciary duty law. For example, our partnership
agreement:
•provides
that whenever our general partner makes a determination or takes,
or declines to take, any other action in its capacity as our
general partner, our general partner is required to make such
determination, or take or decline to take such other action, in
good faith and will not be subject to any higher standard imposed
by our partnership agreement, Delaware law, or any other law, rule
or regulation, or at equity;
•provides
that our general partner and its officers and directors will not be
liable for monetary damages to us or our limited partners resulting
from any act or omission unless there has been a final and
non-appealable judgment entered by a court of competent
jurisdiction determining that our general partner or its officers
and directors, as the case may be, acted in bad faith or engaged in
fraud or willful misconduct or, in the case of a criminal matter,
acted with knowledge that the conduct was criminal;
and
•provides
that our general partner will not be in breach of its obligations
under our partnership agreement or its fiduciary duties to us or
our limited partners if a transaction with an affiliate or the
resolution of a conflict of interest is approved in accordance
with, or otherwise meets the standards set forth in, our
partnership agreement.
In connection with a situation involving a transaction with an
affiliate or a conflict of interest, our partnership agreement
provides that any determination by our general partner must be made
in good faith, and that our conflicts committee and the board of
directors of our general partner are entitled to a presumption that
they acted in good faith. In any proceeding brought by or on behalf
of any limited partner of the partnership, the person bringing or
prosecuting such proceeding will have the burden of overcoming such
presumption. Please refer to the discussion under
Part III, Item 13.
Certain
Relationships and Related Transactions, and Director
Independence
in this Annual Report regarding conflicts of interests and
fiduciary duties of our general partner.
Our general partner has limited liability regarding our
obligations.
Our general partner has limited liability under our contractual
arrangements so that the counterparties to such arrangements have
recourse only against our assets, and not against our general
partner or its assets. Our general partner may therefore cause us
to incur indebtedness or other obligations that are nonrecourse to
our general partner. Our partnership agreement provides that any
action taken by our general partner to limit its liability is not a
breach of our general partner’s fiduciary duties, even if we could
have obtained more favorable terms without the limitation on
liability. In addition, we are obligated to reimburse or indemnify
our general partner to the extent that it incurs obligations on our
behalf. Any such reimbursement or indemnification payments would
reduce the amount of cash otherwise available for distribution to
our unitholders.
If you are not both a citizenship eligible holder and a rate
eligible holder, your common units may be subject to
redemption.
In order to avoid (1) any material adverse effect on the maximum
applicable rates that can be charged to customers by our
subsidiaries on assets that are subject to rate regulation by the
FERC or analogous regulatory body, and (2) any substantial risk of
cancellation or forfeiture of any property, including any
governmental permit, endorsement or other authorization, in which
we have an interest, we have adopted certain requirements regarding
those investors who may own our common units. Citizenship eligible
holders are individuals or entities whose nationality, citizenship
or other related status does not create a substantial risk of
cancellation or forfeiture of any property, including any
governmental permit, endorsement or authorization, in which we have
an interest, and will generally include individuals and entities
who are U.S. citizens. Rate eligible holders are individuals or
entities subject to U.S. federal income taxation on the income
generated by us or entities not subject to U.S. federal income
taxation on the income generated by us, so long as all of the
entity’s owners are subject to U.S. federal income
taxation. If you are not a person who meets the requirements to be
a citizenship eligible holder and a rate eligible holder, you run
the risk of having your units redeemed by us at the market price as
of the date three days before the date the notice of redemption is
mailed. The redemption price will be paid in cash or by delivery of
a promissory note, as determined by our general partner. In
addition, if you are not a person who meets the requirements to be
a citizenship eligible holder, you will not be entitled to voting
rights.
Cost reimbursements, which are determined in our general partner’s
sole discretion, and fees due to our general partner and its
affiliates for services provided are substantial and reduce our
distributable cash flow to you.
Under our partnership agreement, we are required to reimburse our
general partner and its affiliates for all costs and expenses that
they incur on our behalf for managing and controlling our business
and operations. Except to the extent specified under the Omnibus
Agreement, our general partner determines the amount of these
expenses. Under the terms of the Omnibus Agreement we are required
to reimburse USD for providing certain general and administrative
services to us. Our general partner and its affiliates also may
provide us other services for which we will be charged fees.
Payments to our general partner and its affiliates are substantial
and reduce the amount of distributable cash flow to unitholders.
For the twelve months ending December 31, 2023, we estimate that
the fixed fee portion of these expenses will be approximately $3.5
million, which includes, among other items, compensation expense
for all employees required to manage and operate our business. For
a description of the cost reimbursements to our general partner,
please read the discussion under
Part II, Item 8. Financial Statements and Supplementary
Data,
Note 13.
Transactions with Related Parties
in this Annual Report regarding reimbursements to our general
partner under the Omnibus Agreement.
Unitholders have very limited voting rights and, even if they are
dissatisfied, they cannot remove our general partner without its
consent.
Unlike the holders of common stock in a corporation, unitholders
have only limited voting rights on matters affecting our business
and, therefore, limited ability to influence management’s decisions
regarding our business. Unitholders do not elect our general
partner or the board of directors of our general partner and have
no right to elect our general partner or the board of directors of
our general partner on an annual or other continuing basis. The
board of directors of our general partner is chosen by the members
of our general partner, which is indirectly owned by USD.
Furthermore, if the unitholders are dissatisfied with the
performance of our general partner, they will have little ability
to remove our general partner. As a result of these limitations,
the price at which our common units trade could be diminished
because of the absence or reduction of a takeover premium in the
trading price.
The unitholders are unable initially to remove our general partner
without its consent because our general partner and its affiliates
own sufficient units to prevent its removal. The vote of the
holders of at least 66
2/3%
of all outstanding units voting together as a single class is
required to remove our general partner. At
December 31, 2022, our general partner and its affiliates
own
51.9% of the limited partnership interests entitled to vote in this
matter (excluding any common units held by our officers, directors,
employees and certain other persons affiliated with
us).
Furthermore, unitholders’ voting rights are further restricted by
the partnership agreement provision providing that any units held
by a person that owns 20.0% or more of any class of units then
outstanding, other than our general partner, its affiliates, their
transferees, and persons who acquired such units with the prior
approval of the board of directors of our general partner, cannot
vote on any matter.
Our partnership agreement also contains provisions limiting the
ability of unitholders to call meetings or to acquire information
about our operations, as well as other provisions limiting the
unitholders’ ability to influence the manner or direction of
management.
Our general partner interest or the control of our general partner
may be transferred to a third party without unitholder
consent.
Our general partner may transfer its general partner interest to a
third party at any time without the consent of the unitholders.
Furthermore, there is no restriction in our partnership agreement
on the ability of USD Group LLC to transfer its membership interest
in our general partner to a third party. The new owners of our
general partner
would then be in a position to replace the board of directors and
officers of our general partner with their own choices and to
control the decisions taken by the board of directors and
officers.
USD Group LLC may sell or transfer our units in the public or
private markets, and such sales could have an adverse impact on the
trading price of the common units.
USD Group LLC held 17,308,226 common units at
December 31, 2022. We have agreed to provide USD Group
LLC with certain registration rights. USD Group LLC and its
affiliates may sell, transfer or pledge as security all or some of
the units held by them without any duty to us. Such sale of units
in the public or private markets, or pledging or transfer of units,
could have an adverse impact on the price of the common units. At
December 31, 2022, a value of up to $10.0 million of
these common units were subject to a negative pledge supporting
USDG’s revolving line of credit for working capital.
Your liability may not be limited if a court finds that unitholder
action constitutes control of our business.
A general partner of a partnership generally has unlimited
liability for the obligations of the partnership, except for those
contractual obligations of the partnership that are expressly made
non-recourse to the general partner. Our partnership is organized
under Delaware law, and we conduct business in a number of other
states. The limitations on the liability of holders of limited
partner interests for the obligations of a limited partnership have
not been clearly established in some jurisdictions. You could be
liable for our obligations as if you were a general partner if a
court or government agency were to determine that:
•we
were conducting business in a state but had not complied with that
particular state’s partnership statute; or
•your
right to act with other unitholders to remove or replace the
general partner, to approve some amendments to our partnership
agreement or to take other actions under our partnership agreement
constitute “control” of our business.
Unitholders may have to repay distributions that were wrongfully
distributed to them.
Under certain circumstances, unitholders may have to repay amounts
wrongfully distributed to them. Under Section 17-607 of the
Delaware Revised Uniform Limited Partnership Act, we may not make a
distribution to you if the distribution would cause our liabilities
to exceed the fair value of our assets. Delaware law provides that
for a period of three years from the date of the impermissible
distribution, limited partners who received the distribution and
who knew at the time of the distribution that it violated Delaware
law will be liable to the limited partnership for the distribution
amount. Transferees of common units are liable for the obligations
of the transferor to make contributions to the partnership that are
known to the transferee at the time of the transfer and for unknown
obligations if the liabilities could be determined from our
partnership agreement. Liabilities to partners on account of their
partnership interest and liabilities that are non-recourse to the
partnership are not counted for purposes of determining whether a
distribution is permitted.
The New York Stock Exchange, or NYSE, does not require a publicly
traded limited partnership like us to comply with certain of its
corporate governance requirements.
Our common units are listed on the NYSE. Because we are a publicly
traded limited partnership, the NYSE does not require us to have a
majority of independent directors on our general partner’s board of
directors or to establish a compensation committee or a nominating
and corporate governance committee. Accordingly, unitholders will
not have the same protections afforded to shareholders of
corporations that are subject to all of the NYSE corporate
governance requirements.
Tax Risks Inherent in an Investment in Us
Our tax treatment depends on our status as a partnership for U.S.
federal income tax purposes. If the Internal Revenue Service, or
IRS, were to treat us as a corporation for U.S. federal income tax
purposes, which would subject us to entity-level taxation, then our
distributable cash flow to our unitholders would be substantially
reduced.
The anticipated after-tax economic benefit of an investment in our
common units depends largely on our being treated as a partnership
for U.S. federal income tax purposes.
Despite the fact that we are a limited partnership under Delaware
law, it is possible in certain circumstances for a partnership such
as ours to be treated as a corporation for U.S. federal income tax
purposes. Although we do not believe based upon our current
operations that we are so treated, the IRS could disagree with the
positions we take or a change in our business or a change in
current law could cause us to be treated as a corporation for U.S.
federal income tax purposes or otherwise subject us to taxation as
an entity.
If we were treated as a corporation for U.S. federal income tax
purposes, we would pay U.S. federal income tax on our taxable
income at the corporate tax rate, which is currently a maximum of
21%, and would likely pay state and local income tax at varying
rates. Distributions would generally be taxed again as corporate
dividends (to the extent of our current and accumulated earnings
and profits), and no income, gains, losses, deductions, or credits
would flow through to you. Because a tax would be imposed upon us
as a corporation, our distributable cash flow would be
substantially reduced. Therefore, if we were treated as a
corporation for U.S. federal income tax purposes, there would be a
material reduction in the anticipated cash flow and after-tax
return to our unitholders, likely causing a substantial reduction
in the value of our common units.
Notwithstanding our treatment for U.S. federal income tax purposes,
we are subject to certain non-U.S. taxes. If a taxing authority
were to successfully assert that we have more tax liability than we
anticipate or legislation were enacted that increased the taxes to
which we are subject, the distributable cash flow to our
unitholders could be further reduced.
Some of our business operations and subsidiaries are subject to
income, withholding and other taxes in the non-U.S. jurisdictions
in which they are organized or from which they receive income,
reducing the amount of distributable cash flow. In computing our
tax obligation in these non-U.S. jurisdictions, we are required to
take various tax accounting and reporting positions on matters that
are not entirely free from doubt and for which we have not received
rulings from the governing tax authorities, such as whether
withholding taxes will be reduced by the application of certain tax
treaties. Upon review of these positions the applicable authorities
may not agree with our positions. A successful challenge by a
taxing authority could result in additional tax being imposed on
us, reducing the distributable cash flow to our unitholders. In
addition, changes in our operations or ownership could result in
higher than anticipated tax being imposed in jurisdictions in which
we are organized or from which we receive income and further reduce
the distributable cash flow. Although these taxes may be properly
characterized as foreign income taxes, you may not be able to
credit them against your liability for U.S. federal income taxes on
your share of our earnings.
If we were subjected to a material amount of additional
entity-level taxation by individual states, counties or cities, it
would reduce our distributable cash flow to our
unitholders.
Changes in current state, county or city law may subject us to
additional entity-level taxation by individual states, counties or
cities. Several states have subjected, or are evaluating ways to
subject partnerships to entity-level taxation through the
imposition of state income, franchise and other forms of taxation.
Imposition of any such taxes may substantially reduce the
distributable cash flow to you and the value of our common units
could be negatively impacted.
The tax treatment of publicly traded partnerships, companies with
multinational operations or an investment in our common units could
be subject to potential legislative, judicial or administrative
changes and differing interpretations, possibly on a retroactive
basis.
The present U.S. federal income tax treatment of publicly traded
partnerships, companies with multinational operations, or an
investment in our common units may be modified by administrative,
legislative or judicial interpretation at any time. From time to
time, members of Congress and the Department of Treasury have
proposed and considered substantive changes to the existing U.S.
federal income tax laws that affect publicly traded partnerships,
including a prior legislative proposal that would have eliminated
the qualifying income exception to the treatment of all
publicly-traded partnerships as corporations upon which we rely for
our treatment as a partnership for U.S. federal income tax
purposes. In addition, the Treasury Department has issued, and in
the future may issue, regulations interpreting those laws that
affect publicly traded partnerships. Although there are no current
legislative or administrative proposals, there can be no assurance
that there will not be further changes to the U.S. federal income
tax laws or the Treasury Department’s interpretation of the
qualifying income rules in a manner that could impair our ability
to qualify as a publicly traded partnership in the
future.
Any modification to the U.S. federal income tax laws and
interpretations thereof may or may not be retroactively applied and
could make it more difficult or impossible to meet the exception
for us to be treated as a partnership for U.S. federal income tax
purposes. We are unable to predict whether any changes or other
proposals will ultimately be enacted.
Any future legislative changes could negatively impact the value of
an investment in our common units. You are urged to consult your
own tax advisor with respect to the status of regulatory or
administrative developments and proposals and their potential
effect on your investment in our common units.
Our unitholders’ share of our income will be taxable to them for
U.S. federal income tax purposes even if they do not receive any
cash distributions from us. A unitholder’s share of our taxable
income, and its relationship to any distributions we make, may be
affected by a variety of factors, including our economic
performance, transactions in which we engage or changes in
law.
Because a unitholder is treated as a partner to whom we will
allocate taxable income that could be different in amount than the
cash we distribute, a unitholder’s allocable share of our taxable
income will be taxable to the unitholder, which may require the
payment of U.S. federal income taxes and, in some cases, state and
local income taxes, on the unitholder’s share of our taxable income
even if the unitholder receives no cash distributions from us. Our
unitholders may not receive cash distributions from us equal to
their share of our taxable income or even equal to the actual tax
liability that results from that income.
A unitholder’s share of our taxable income, and its relationship to
any distributions we make, may be affected by a variety of factors,
including our economic performance, which may be affected by
numerous business, economic, regulatory, legislative, competitive
and political uncertainties beyond our control, and certain
transactions in which we might engage. For example, we may engage
in transactions that produce substantial taxable income allocations
to some or all of our unitholders without a corresponding increase
in cash distributions to our unitholders, such as a sale or
exchange of assets, the proceeds of which are reinvested in our
business or used to reduce our debt. A unitholder’s ratio of its
share of taxable income to the cash received by it may also be
affected by changes in law. For instance, under the federal tax
reform enacted in 2017, the net interest expense deductions of
certain business entities, including us, are limited to 30% of such
entity’s “adjusted taxable income,” which is generally taxable
income with certain modifications. If the limit applies, a
unitholder’s taxable income allocations will be more (or its net
loss allocations will be less) than would have been the case absent
the limitation.
If the IRS contests the U.S. federal income tax positions we take,
the market for our common units may be adversely impacted and the
cost of any IRS contest will reduce our distributable cash flow to
our unitholders.
We have not requested a ruling from the IRS with respect to our
treatment as a partnership for U.S. federal income tax purposes.
The IRS may adopt positions that differ from the positions we take,
and the IRS’s positions may ultimately be sustained. It may be
necessary to resort to administrative or court proceedings to
sustain some or all of the positions we take and such positions may
not ultimately be sustained. Any contest with the IRS, and the
outcome of any IRS contest, may have a materially adverse impact on
the market for our common units and the
price at which they trade. In addition, our costs for any contest
with the IRS will be borne indirectly by our unitholders and our
general partner because the costs will reduce our distributable
cash flow.
Some of our activities may not generate qualifying income, and we
conduct these activities in a separate subsidiary that is treated
as a corporation for U.S. federal income tax purposes.
Corporate U.S. federal income tax paid by this subsidiary reduces
our cash available for distribution.
In order to maintain our status as a partnership for U.S. federal
income tax purposes, 90% or more of our gross income in each tax
year must be qualifying income under Section 7704 of the Internal
Revenue Code.
To ensure that 90% or more of our gross income in each tax year is
qualifying income, we currently conduct a portion of our business,
relating to railcar fleet services, in a separate subsidiary that
is treated as a corporation for U.S. federal income tax
purposes.
Such corporate subsidiary is subject to corporate-level federal
income tax on its taxable income at the corporate tax rate, which
is currently a maximum of 21%, and will also likely pay state (and
possibly local) income tax at varying rates, on its taxable income.
If the IRS were to successfully assert that such corporate
subsidiary has more tax liability than we anticipate or legislation
were enacted that increased the corporate tax rate, our cash
available for distribution to our unitholders would be further
reduced.
If the IRS makes audit adjustments to our income tax returns, it
(and some states) may assess and collect any taxes (including any
applicable penalties and interest) resulting from such audit
adjustments directly from us, in which case our cash available for
distribution to our unitholders might be substantially reduced and
our current and former unitholders may be required to indemnify us
for any taxes (including any applicable penalties and interest)
resulting from such audit adjustments that were paid on such
unitholders’ behalf.
For tax years beginning after December 31, 2017, if the IRS makes
audit adjustments to our income tax returns, it (and some states)
may assess and collect any taxes (including any applicable
penalties and interest) resulting from such audit adjustments
directly from us. To the extent possible under the new rules, our
general partner may elect to either pay the taxes (including any
applicable penalties and interest) directly to the IRS or, if we
are eligible, issue a revised information statement to each
unitholder and former unitholder with respect to an audited and
adjusted return. Although our general partner may elect to have our
unitholders and former unitholders take such audit adjustments into
account and pay any resulting taxes (including applicable penalties
or interest) in accordance with their interests in us during the
tax year under audit, there can be no assurance that such election
will be practicable, permissible or effective in all
circumstances.
As a result, our current unitholders may bear some or all of the
tax liability resulting from such audit adjustment, even if such
unitholders did not own units in us during the tax year under
audit.
If, as a result of any such audit adjustment, we are required to
make payments of taxes, penalties and interest, our cash available
for distribution to our unitholders might be substantially reduced
and our current and former unitholders may be required to indemnify
us for any taxes (including any applicable penalties and interest)
resulting from such audit adjustments that were paid on such
unitholders behalf.
Tax gain or loss on the disposition of our common units could be
more or less than expected.
If our unitholders sell common units, they will recognize a gain or
loss for U.S. federal income tax purposes equal to the difference
between the amount realized and their tax basis in those common
units. Because distributions in excess of their allocable share of
our net taxable income decrease their tax basis in their common
units, the amount, if any, of such prior excess distributions with
respect to the common units a unitholder sells will, in effect,
become taxable income to the unitholder if it sells such common
units at a price greater than its tax basis in those common units,
even if the price received is less than its original cost.
Furthermore, a substantial portion of the amount realized on a sale
of common units, whether or not representing gain, may be taxed as
ordinary income due to potential recapture of depreciation
deductions. Thus, selling unitholders may recognize both ordinary
income and capital loss from the sale of their units if the amount
realized on a sale of their units is less than their adjusted basis
in the units. Net capital loss may only offset capital gains and,
in the case of individuals, up to $3,000 of ordinary income per
year. In the taxable period in which a selling unitholder sells
their units, they may recognize ordinary income from our
allocations of income and gain to them prior to the sale and from
recapture items that generally cannot be offset by any capital loss
recognized upon the sale of units. In addition, because the amount
realized
includes a unitholder’s share of our nonrecourse liabilities, a
unitholder that sells common units, may incur a tax liability in
excess of the amount of cash received from the sale.
Certain actions that we may take, such as issuing additional units,
may increase the U.S. federal income tax liability of
unitholders.
In the event we issue additional units or engage in certain other
transactions in the future, the allocable share of nonrecourse
liabilities allocated to the unitholders will be recalculated to
take into account our issuance of any additional units. Any
reduction in a unitholder’s share of our nonrecourse liabilities
will be treated as a distribution of cash to that unitholder and
will result in a corresponding tax basis reduction in a
unitholder’s units. A deemed cash distribution may, under certain
circumstances, result in the recognition of taxable gain by a
unitholder, to the extent that the deemed cash distribution exceeds
such unitholder’s tax basis in its units. In addition, the U.S.
federal income tax liability of a unitholder could be increased if
we take advantage of debt reduction opportunities (e.g., debt
exchanges, debt repurchases or modifications of existing debt),
dispose of assets or make a future offering of units and use the
proceeds in a manner that does not produce substantial additional
deductions, such as (i) to repay indebtedness currently outstanding
or (ii) to acquire property that is not eligible for depreciation
or amortization for U.S. federal income tax purposes or that is
depreciable or amortizable at a rate significantly slower than the
rate currently applicable to our existing assets.
There are limits on the deductibility of losses that may adversely
affect unitholders.
In the case of taxpayers subject to the passive loss rules
(generally, individuals, closely-held corporations and regulated
investment companies), any losses generated by us will only be
available to offset our future income and cannot be used to offset
income from other activities, including other passive activities or
investments. Unused losses may be deducted when the unitholder
disposes of the unitholder’s entire investment in us in a fully
taxable transaction with an unrelated party. A unitholder’s share
of our net passive income may be offset by unused losses from us
carried over from prior years, but not by losses from other passive
activities, including losses from other publicly traded
partnerships. Further, excluding the temporary impact of the CARES
Act, in addition to the other limitations described above,
non-corporate taxpayers may only deduct business losses up to the
gross income or gain attributable to such trade or business plus
$250,000 ($500,000 for unitholders filing jointly). Amounts that
may not be deducted in a taxable year may be carried forward into
the following taxable year. This limitation shall be applied after
the passive loss limitations and, unless amended, applies only to
taxable years beginning prior to
December 31, 2025.
Tax-exempt entities and non-U.S. persons face unique tax issues
from owning our common units that may result in adverse tax
consequences to them.
Investment in common units by tax-exempt entities, such as employee
benefit plans and individual retirement accounts, or IRAs, and
non-U.S. persons raises issues unique to them. For example,
virtually all of our income allocated to organizations that are
exempt from U.S. federal income tax, including IRAs and other
retirement plans, will be unrelated business taxable income and
will be taxable to them. Further, subject to the proposed
aggregation rules for certain similarly situated businesses or
activities issued by the Treasury Department, a tax-exempt entity
with more than one unrelated trade or business (including by
attribution from investment in a partnership such as ours) is
required to compute the unrelated business taxable income of such
tax-exempt entity separately with respect to each such trade or
business (including for purposes of determining any net operating
loss deduction). As a result, it may not be possible for tax-exempt
entities to utilize losses from an investment in our partnership to
offset unrelated business taxable income from another unrelated
trade or business and vice versa. If you are a tax-exempt entity,
you should consult a tax advisor before investing in our common
units.
Non-U.S. unitholders are generally taxed and subject to income tax
filing requirements by the United States on income effectively
connected with a U.S. trade or business (“effectively connected
income”). Income allocated to our unitholders and any gain from the
sale of our units will generally be considered to be “effectively
connected” with a U.S. trade or business. As a result,
distributions to non-U.S. persons will be reduced by withholding
taxes at the highest applicable effective tax rate, and non-U.S.
persons will be required to file U.S. federal income tax
returns
and pay tax on their share of our taxable income. If you are a
non-U.S. person, you should consult a tax advisor before investing
in our common units.
We may be required to deduct and withhold amounts from
distributions to foreign unitholders related to withholding tax
obligations arising from the sale or disposition of our units by
foreign unitholders.
Upon the sale, exchange or other disposition of a unit by a foreign
unitholder, the transferee is generally required to withhold 10% of
the amount realized on such sale, exchange or other disposition if
any portion of the gain on such sale, exchange or other disposition
would be treated as effectively connected with a U.S. trade or
business. If the transferee fails to satisfy this withholding
requirement, we will be required to deduct and withhold such amount
(plus interest) from future distributions to the transferee.
Because the “amount realized” would include a unitholder’s share of
our nonrecourse liabilities, 10% of the amount realized could
exceed the total cash purchase price for such disposed
units.
For transfers of publicly traded partnership interests involving
brokers acting as a “qualified intermediary” (as such term is
defined in the applicable U.S. treasury regulations), the
withholding obligation is generally imposed on the broker rather
than the transferee. There are also a number of exceptions to the
withholding obligation that may apply depending on the transferor’s
particular tax and circumstances. If you are a non-U.S. person, you
should consult a tax advisor before investing in our common
units.
We treat each purchaser of common units as having the same tax
benefits without regard to the actual common units purchased. The
IRS may challenge this treatment, which could adversely affect the
value of the common units.
Because we cannot match transferors and transferees of common units
and because of other reasons, we have adopted depreciation and
amortization positions that may not conform to all aspects of
existing Treasury regulations promulgated under the Internal
Revenue Code and referred to as “Treasury Regulations.” A
successful IRS challenge to those positions could adversely affect
the amount of tax benefits available to you. A successful IRS
challenge could also affect the timing of these tax benefits or the
amount of gain from your sale of common units and could have a
negative impact on the value of our common units or result in audit
adjustments to your tax returns.
We prorate our items of income, gain, loss and deduction for U.S.
federal income tax purposes between transferors and transferees of
our units each month based upon the ownership of our units on the
first business day of each month, instead of on the basis of the
date a particular unit is transferred. The IRS may challenge
aspects of our proration method, which could change the allocation
of items of income, gain, loss and deduction among our
unitholders.
We prorate our items of income, gain, loss and deduction between
transferors and transferees of our units each month based upon the
ownership of our units on the first day of each month, instead of
on the basis of the date a particular unit is transferred. The U.S.
Department of Treasury and the IRS have issued Treasury Regulations
that permit publicly traded partnerships to use a monthly
simplifying convention that is similar to ours, but they do not
specifically authorize all aspects of the proration method we have
adopted. If the IRS were to successfully challenge this method, we
could be required to change the allocation of items of income,
gain, loss and deduction among our unitholders.
A unitholder whose common units are loaned to a “short seller” to
effect a short sale of common units may be considered as having
disposed of those common units. If so, he would no longer be
treated for U.S. federal income tax purposes as a partner with
respect to those common units during the period of the loan and may
be required to recognize gain or loss from the
disposition.
Because a unitholder whose common units are loaned to a “short
seller” to effect a short sale of common units may be considered as
having disposed of the loaned common units, he may no longer be
treated for federal income tax purposes as a partner with respect
to those common units during the period of the loan to the short
seller and the unitholder may be required to recognize gain or loss
from such disposition. Moreover, during the period of the loan to
the short seller, any of our income, gain, loss or deduction with
respect to those common units may not be reportable by the
unitholder and any cash distributions received by the unitholder as
to those common units could be fully taxable as ordinary income.
Unitholders desiring to assure their status as partners and avoid
the risk of gain
recognition from a loan to a short seller are urged to modify any
applicable brokerage account agreements to prohibit their brokers
from loaning their common units.
We have adopted certain valuation methodologies in determining a
unitholder’s
allocations of income, gain, loss and deduction. The IRS may
challenge these methodologies or the resulting allocations, and
such a challenge could adversely affect the value of our common
units.
In determining the items of income, gain, loss and deduction
allocable to our unitholders, in certain circumstances, including
when we issue additional units, we must determine the fair market
value of our assets. Although we may from time to time consult with
professional appraisers regarding valuation matters, we make many
fair value estimates using a methodology based on the market value
of our common units as a means to measure the fair market value of
our assets.
The IRS may challenge these valuation methods and the resulting
allocations of income, gain, loss and deduction. For example, our
methodology may be viewed as understating the value of our assets.
In that case, there may be a shift of income, gain, loss and
deduction between certain unitholders and our general partner,
which may be unfavorable to such unitholders.
A successful IRS challenge to these methods or allocations could
adversely affect the amount, character and timing of taxable income
or loss allocated to our unitholders. It also could affect the
amount of gain from our unitholders’ sale of common units and could
have a negative impact on the value of our common units or result
in audit adjustments to our unitholders’ tax returns without the
benefit of additional deductions.
As a result of investing in our common units, you may become
subject to state, local and foreign taxes and return filing
requirements in jurisdictions where we operate or own or acquire
properties.
In addition to U.S. federal income taxes, our unitholders are
likely subject to other taxes, including state, local and foreign
taxes, unincorporated business taxes and estate, inheritance or
intangible taxes that are imposed by the various jurisdictions in
which we conduct business or control property now or in the future,
even if they do not live in any of those jurisdictions. Our
unitholders are likely required to file state, local and foreign
income tax returns and pay state and local income taxes in some or
all of these various jurisdictions. Further, our unitholders may be
subject to penalties for failure to comply with those requirements.
We currently own assets and conduct business in Alberta, Canada,
California, Texas, Wyoming and Oklahoma. Some of these
jurisdictions currently impose a personal income tax on
individuals. As we make acquisitions or expand our business, we may
control assets or conduct business in additional states that impose
a personal income tax. Our unitholders bear responsibility for
filing all federal, state, local and foreign tax returns and pay
any taxes due in these jurisdictions. Unitholders should consult
with their own tax advisors regarding the filing of such tax
returns, the payment of such taxes, and the deductibility of any
taxes paid.
General Risks Inherent in an Investment in Us
The price of our common units may fluctuate significantly, and you
could lose all or part of your investment.
The market price of our common units may also be influenced by many
factors, some of which are beyond our control,
including:
•our
quarterly distributions;
•our
quarterly or annual earnings or those of other companies in our
industry;
•announcements
by us or our competitors of significant contracts or
acquisitions;
•changes
in accounting standards, policies, guidance, interpretations or
principles;
•general
economic conditions, including inflationary pressures, further
increases in interest rates, or a general slowdown in the global
economy;
•the
failure of securities analysts to cover our common units or changes
in financial estimates by analysts;
•future
sales of our common units; and
•other
factors described in these “Risk Factors.”
Because our common units are yield-oriented securities, increases
in interest rates could adversely impact our unit price, our
distributable cash flow, our ability to issue equity or incur debt
for acquisitions or other purposes and our ability to make cash
distributions at our intended levels.
Interest rates could continue to increase in the future. As a
result, interest rates on our future indebtedness could be higher
than current levels, causing our financing costs to increase
accordingly. As with other yield-oriented securities, our unit
price is affected by the level of our cash distributions and
implied distribution yield. The distribution yield is often used by
investors to compare and rank yield-oriented securities for
investment decision-making purposes. Therefore, changes in interest
rates, either positive or negative, may affect our interest expense
and distributable cash flow, the yield requirements of investors
who invest in our units, and a rising interest rate environment
could have an adverse impact on our unit price, our ability to
issue equity or incur debt for acquisitions or other purposes and
our ability to make cash distributions at our intended
levels.
We may recognize impairment on long-lived assets and intangible
assets.
Periodically, we review our long-lived assets for impairment
whenever economic events or changes in circumstances indicate that
the carrying value of an asset may not be recoverable. We also
review our amortizable intangible assets for indicators of
impairment in accordance with applicable accounting standards.
Significant negative industry or general economic trends,
disruptions to our business and unexpected significant changes or
planned changes in our use of the assets may result in impairments
to our amortizable intangible assets and other long-lived assets.
For example, we evaluated our Casper Terminal asset group for
impairment in the third quarter of 2022 due to recurring periods
where cash flow projections were not met due to adverse market
conditions. Based on our assessment using primarily a cost
approach, as discussed under
Part II, Item 8. Financial Statements and Supplementary
Data,
Note 8.
Property and Equipment
and
Note 10.
Goodwill and Intangible Assets
in this Annual Report, we determined that the carrying amount of
our Casper Terminal reporting unit exceeded its fair value at
September 30, 2022. Accordingly, we recognized an impairment of
$36.0 million to the property and equipment and
$35.6 million to the intangible assets to write down the
assets of the terminal to its fair value at September 30, 2022.
However, to the extent that our assessment of our current market
value or future changes in financial performance occurs, which are
inherently uncertain and difficult to predict, there may be
additional charges against earnings in the future, which could have
a material adverse impact on our reported results of operations and
financial condition.
Our ability to operate our business effectively could be impaired
if we fail to attract and retain key management
personnel.
We are managed and operated by the board of directors and executive
officers of our general partner. All of the personnel that conduct
our business are employed by affiliates of our general partner, but
we sometimes refer to these individuals as our employees. Our
ability to operate our business and implement our strategies
depends on our continued ability and the ability of affiliates of
our general partner to attract and retain highly skilled management
personnel. Competition for these persons is intense. Given our
size, we may be at a disadvantage, relative to our larger
competitors, in the competition for these personnel. Additionally,
sustained declines in our unit price, or lower unit price
performance relative to competitors, can reduce the retention value
of our unit-based awards. We or affiliates of our general partner
may not be able to attract and retain qualified personnel in the
future, and the failure to retain or attract senior executives and
key personnel could have a material adverse effect on our ability
to effectively operate our business. Neither we nor our general
partner maintains key person life insurance policies for any of our
senior management team.
Terrorist or cyber-attacks and threats, escalation of military
activity in response to these attacks or acts of war could have a
material adverse effect on our business, financial condition,
results of operations and ability to make quarterly distributions
to our unitholders.
Terrorist attacks and threats, cyber-attacks, escalation of
military activity, acts of war or other civil unrest may have
significant effects on general economic conditions, fluctuations in
consumer confidence and spending and market liquidity, each of
which could materially and adversely affect our business. Future
terrorist or cyber-attacks, rumors or threats of war, actual
conflicts involving the United States, Canada or their respective
allies, or military or trade disruptions may significantly affect
our operations and those of our customers. Strategic targets, such
as energy-related assets and transportation assets, may be at
greater risk of future terrorist or cyber-attacks than
other
targets in the United States and Canada. The disruption or a
significant increase in energy prices could result in
government-imposed price controls. It is possible that any of these
occurrences, or a combination of them, could have a material
adverse effect on our business, financial condition, results of
operations, and ability to make quarterly distributions to our
unitholders.
We rely on information technology in all aspects of our
business.
A cyber-attack involving our information systems and related
infrastructure could negatively impact our operations in a variety
of ways, including, but not limited to, the following:
•data
corruption, communication interruption, or other operational
disruption during transporting crude oil;
•a
cyber-attack on a communications network or power grid could cause
operational disruption resulting in loss of revenues;
•a
cyber-attack on our automated and surveillance systems could cause
a loss in crude oil and potential environmental
hazards;
•a
deliberate corruption of our financial or operating data could
result in events of non-compliance which could then lead to
regulatory fines or penalties; and
•a
cyber-attack resulting in the loss, disruption or disclosure of, or
damage or denial of access to, our or any of our customer’s or
supplier’s data or confidential information could harm our business
by damaging our reputation, subjecting us to potential financial or
legal liability, and requiring us to incur significant costs,
including costs to repair or restore our systems and data or to
take other remedial steps.
Furthermore, geopolitical tensions or conflicts, such as Russia’s
invasion of Ukraine, may further heighten the risk of
cyber-attacks.
Additionally, we do not maintain specialized insurance for possible
liability resulting from a cyber-attack on our assets that may shut
down all or part of our business. There can be no assurance that a
system failure or data security breach will not have a material
adverse effect on our financial condition, results of operations or
cash flows. Furthermore, the growth of cyber-attacks has resulted
in evolving legal and compliance matters which impose significant
costs that are likely to increase over time and expose us to
reputational damage or litigation, monetary damages, regulatory
enforcement actions or fines.
If we fail to maintain an effective system of internal controls, we
may not be able to report our financial results timely and
accurately or prevent fraud, which would likely have a negative
impact on the market price of our common units.
We are subject to the public reporting requirements of the Exchange
Act. We prepare our financial statements in accordance with U.S.
generally accepted accounting principles, or GAAP.
Effective internal controls are necessary for us to provide
reliable financial reports, prevent fraud and to operate
successfully as a publicly traded partnership. We may be
unsuccessful in maintaining our internal controls, and we may be
unable to maintain effective controls over our financial processes
and reporting in the future or to comply with our obligations under
Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as
Section 404. For example, Section 404 requires us, among other
things, to annually review and report on, and our independent
registered public accounting firm to assess, the effectiveness of
our internal controls over financial reporting.
Any failure to maintain effective internal controls or to improve
our internal controls could harm our operating results or cause us
to fail to meet our reporting obligations. Given the difficulties
inherent in the design and operation of internal controls over
financial reporting, we can provide no assurance as to our, or our
independent registered public accounting firm’s conclusions about
the effectiveness of our internal controls, and we may incur
significant costs in our efforts to comply with Section 404.
Ineffective internal controls will subject us to regulatory
scrutiny and a loss of confidence in our reported financial
information, which could have an adverse effect on our business and
would likely have a material adverse effect on the trading price of
our common units.
For as long as we are a smaller reporting company, we will not be
required to comply with certain disclosure requirements that apply
to other public companies.
We are currently a “smaller reporting company” as defined by Rule
12b-2 of the Exchange Act. “Smaller reporting companies” are able
to provide simplified executive compensation disclosures in their
filings, and have certain other scaled disclosure obligations in
their SEC filings, including, among other things, being required to
provide only two years of audited financial statements in annual
reports. The scaled disclosures we provide in our SEC filings due
to our status as a “smaller reporting company” may make it harder
for investors to analyze our results of operations and financial
prospects. If some investors find our common units to be less
attractive as a result of the scaled disclosures, there also may be
a less active trading market for our common units and our trading
price may be more volatile.
Item 1B. Unresolved Staff Comments
Not Applicable.
Item 2. Properties
A description of our properties is included in
Item 1.
Business
in this Annual Report, which is incorporated herein by
reference.
Our Hardisty Terminal is located on land we own. Our Stroud
Terminal, including the Stroud Pipeline, and our Casper Terminal,
including the Casper pipeline, are located on land we own, as well
as land owned by others, but operated by us under licenses,
rights-of-way or leases with private land owners, public
authorities, railways, or public utilities. Our West Colton
Terminal is located on land owned by others and is operated by us
under easements and rights-of-way, licenses, leases or permits that
have been granted by private land owners, public authorities,
railways or public utilities.
We have satisfactory title and other rights to our real estate
assets.
Obligations under our Credit Agreement are secured by a first
priority lien on our assets and those of our restricted
subsidiaries (as such term is defined in our Credit Agreement),
other than certain excluded assets. Title to the real property
necessary for us to operate our business may also be subject to
encumbrances in some cases, such as customary interests generally
retained in connection with the acquisition of real property, liens
that can be imposed in some jurisdictions for government-initiated
action to clean up environmental contamination, liens for current
taxes and other burdens, and easements, restrictions, and other
encumbrances to which the underlying properties were subject at the
time of lease or acquisition by us. However, we do not believe that
any of these burdens would materially detract from the value of
these properties or from our interest in these properties or would
materially interfere with their use in the operation of our
business.
Item 3. Legal Proceedings
Although we may, from time to time, be involved in litigation and
claims arising out of our operations in the normal course of
business, we are not currently a party to any litigation or
governmental or other proceeding that we believe will have a
material adverse impact on our consolidated financial condition or
results of operations. In addition, under the Omnibus Agreement,
USD has agreed to indemnify us for certain liabilities attributable
to the ownership or operation of the assets contributed by them to
us.
Item 4. Mine Safety Disclosures
Not Applicable.
PART II
Item 5. Market for Registrant’s Common Equity, Related
Unitholder Matters and Issuer Purchase of Equity
Securities
Our common units are listed and traded on the NYSE, under the
ticker symbol “USDP”.
On February 21, 2023, there were approximately 6,600 common
unitholders, ten of which were registered common unitholders
of record.
The board of directors of our general partner has adopted a cash
distribution policy pursuant to which we intend to distribute at
least the minimum quarterly distribution of $0.2875 per unit, or
$1.15 per unit on an annualized basis on all of our units to the
extent we have sufficient available cash after the establishment of
cash reserves and the payment of our expenses, including payments
to our general partner and its affiliates. The amount of
distributions we pay under our cash distribution policy and the
decision to make any distribution are determined by the board of
directors of our general partner. 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 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 $0.1235 per
unit for each of the 2022 quarters ended March 31, June 30,
September 30 and December 31. USDG waived its distribution on all
of its 17,308,226 common units with respect to the fourth
quarter 2022 distribution. We expect that the board of directors of
our general partner will revisit the amount of any distributions we
make on a quarterly basis and will take into consideration updated
commercial progress, including our ability to renew, extend or
replace our customer agreements at the Hardisty and Stroud
Terminals, and our compliance with the covenants under the Credit
agreement, as well as recent changes to the market.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION
PLANS
UNREGISTERED SALES OF EQUITY SECURITIES
Except as previously disclosed in a Quarterly Report on Form 10-Q
or Current Report on Form 8-K, no unregistered sales of our common
units were made during the fiscal year ended
December 31, 2022.
ISSUER PURCHASES OF EQUITY SECURITIES
None.
Item 6. [Reserved]
Item
7. 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 our consolidated financial statements and the
accompanying notes included in Item 8.
Financial
Statements and Supplementary Data
in this Annual Report. Unless the context otherwise requires,
references in this discussion to USD Partners, USDP, the
Partnership, we, our, us or like terms refer to USD Partners and
the following subsidiaries, collectively: Casper Crude to Rail LLC,
CCR Pipeline LLC, Stroud Crude Terminal LLC, SCT Pipeline LLC, USD
Logistics Operations GP LLC, USD Logistics Operations LP, USD Rail
LP, USD Rail Canada ULC, USD Terminals Canada ULC, USD Terminals
Canada II ULC, USD Terminals II S.A.R.L., USD Terminals LLC and
West Colton Rail Terminal LLC. 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 Part I, Item 1A.
Risk
Factors
included in this Annual Report. Please also read the
“Cautionary
Note Regarding Forward-Looking Statements”
following the table of contents in this Annual Report.
We denote amounts denominated in Canadian dollars with “C$”
immediately prior to the stated amount.
The financial information for the years ended
December 31, 2021 and 2020 has been retrospectively
recast to
include the pre-acquisition results of the Hardisty South Terminal
because the acquisition represented a business combination between
entities under common control.
Refer to Item 8. Financial Statements and Supplementary
Data,
Note 3.Hardisty
South Acquisition
in this Annual Report for further information.
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 one of our
customers with leased railcars and fleet services to facilitate the
transportation of liquid hydrocarbons by rail.
We generally do not take ownership of the products that we handle
nor do we receive any payments from our customers based on the
value of such products. We may on occasion enter into buy-sell
arrangements in which we take temporary title to commodities while
in our terminals. We expect any such arrangements to be at fixed
prices where we do not take any exposure to changes in commodity
prices.
We believe rail will continue as an important transportation option
for energy producers, refiners and marketers due to its unique
advantages relative to other transportation means. Specifically,
rail transportation of energy-related products provides flexible
access to key demand centers on a relatively low fixed-cost basis
with faster physical delivery, while preserving the specific
quality of customer products over long distances.
USDG, a wholly-owned subsidiary of USD, and the sole owner of our
general partner, is engaged in designing, developing, owning, and
managing large-scale multi-modal logistics centers and
energy-related infrastructure across North America. USDG’s
solutions create flexible market access for customers in
significant growth areas and key demand centers, including Western
Canada, the U.S. Gulf Coast and Mexico. Among other projects, USDG
is currently pursuing the development of a premier energy logistics
terminal on the Houston Ship Channel with capacity for substantial
tank storage, multiple docks (including barge and deepwater),
inbound and outbound pipeline connectivity, as well as a rail
terminal with unit train capabilities.
USDG completed an expansion project in January 2019 at the
Partnership’s Hardisty Terminal, referred to herein as Hardisty
South, which added one and one-half 120-railcar unit trains of
transloading capacity per day, or approximately 112,500 barrels per
day, or bpd. In April 2022, we acquired 100% of the entities owning
the Hardisty South Terminal assets from USDG, exchanged our
sponsor’s economic general partner interest in us for a
non-
economic general partner interest and eliminated our sponsor’s IDRs
for a total consideration of $75.0 million in cash and
5,751,136 common units, that was made effective as of April 1,
2022. The acquisition of the Hardisty South Terminal increases the
size, scale and growth capacity of the Partnership’s asset base,
while optimizing operational and commercial synergies of the
Hardisty Terminal in order to capitalize on the growth benefits
associated with our sponsor’s Diluent Recovery Unit, or DRU,
program. For more information on our drop down acquisition of the
Hardisty South Terminal, refer to
Item 8. Financial Statements and Supplementary Data,
Note 3.
Hardisty South Terminal Acquisition
in this Annual Report.
USD’s Diluent Recovery Unit and Port Arthur Terminal
Projects
During 2021, USD, along with its joint venture partner, Gibson,
successfully completed construction on and placed into service a
diluent recovery unit, or DRU, at the Hardisty Terminal, as a part
of a long-term solution to transport heavier grades of crude oil
produced in Western Canada by rail. USD also placed into service a
new destination terminal in Port Arthur, Texas, or PAT. Refer to
the
Growth Opportunities for our Operations
section below for further information.
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.
Impact of Current Market Events
Given that crude oil prices have recovered and are higher than
pre-COVID levels, Canadian production that was temporarily shut-in
due to COVID-19 has also returned to pre-COVID levels. According to
the Canadian Energy Regulator, or CER, the Canadian production
forecast for 2023 is projected to grow which indicates another year
of growth for Canadian production.
In the first quarter of 2022, Canadian crude oil inventories
reached historically low levels due to a combination of specific
supply disruptions and one-time line fill demand events from new
pipeline capacity. Canadian crude oil inventory levels have
steadily recovered from historical lows and returned to normal
levels in the second quarter of 2022. During the third quarter of
2022, U.S. Mid-Continent (PADD II) and U.S. Gulf Coast (PADD III)
unplanned refinery maintenance led to a decrease in demand and in
turn slightly increased inventory levels. In the fourth quarter of
2022, TC Energy had a pipeline outage on the entire Keystone
pipeline system. The entire pipeline was offline for a significant
amount of time, which lead to inventory builds in Canada. Given
this event, Canadian crude oil inventory levels increased in the
fourth quarter of 2022 and were at the higher end of the five year
average.
Additionally, the U.S. government released approximately 260
million barrels of crude oil from the U.S. Strategic Petroleum
Reserve, or SPR, which started in October 2021 and ended in January
2023. The impact of these emergency releases weakened replacement
costs in the U.S. Gulf Coast for all sour crude oil alternatives.
As replacement costs have weakened, WCS Houston crude prices have
done the same, which has driven WCS Hardisty prices at origin to
weaken in response. There are no further emergency SPR releases
planned in the near term, however regular releases may continue.
The U.S government has announced plans to replenish the reserves by
implementing a three-part strategy to refill the reserve in the
long term, which includes repurchases, returns from previous
exchanges and working with congress to avoid unnecessary
sales.
Given the supply and demand events discussed above, and based on
the forecasted production increases in Canada we expect that
inventory levels in 2023 will remain at the higher end of the five
year average. At these levels
and as inventories continue to build, expectations are that
pipeline apportionment levels will grow which will potentially lead
to higher demand for a crude by rail egress solution. However, the
extent and duration of any increases in apportionment or inventory
levels are difficult to predict, if such increases occur at
all.
Another factor that may contribute to the demand for a crude by
rail egress solution is the significant regulatory and legal
obstacles that pipeline projects and existing pipelines experience
in the U.S and Canada. For example, it was previously announced by
Trans Mountain Corporation, or TMC, that the cost of the Trans
Mountain Pipeline expansion project has nearly doubled and the
timeline for completing the project has now been extended out
further into 2023. This prompted the Canadian Government to
announce that it is cutting off funding for the project and advised
TMC to secure the necessary funding from public debt markets or
financial institutions. The Canadian government does not plan to be
the long-term owner of the pipeline and expects to launch a sale
process in due course. As environmental, regulatory and political
challenges to increase pipeline export capacity remain, we believe
crude by rail exports will remain a valuable egress
solution.
In the long-term, as stated above, we expect demand for rail
capacity at our terminals to continue to increase over the next
several years and potentially longer if proposed pipeline
developments do not meet currently planned timelines and regulatory
or other challenges to pipeline projects persist. Our Hardisty and
Casper terminals, with established capacity and scalable designs,
are well-positioned as strategic outlets to meet takeaway needs as
Western Canadian crude oil supplies continue to exceed available
pipeline takeaway capacity. Also, as previously discussed, USD
along with its partner, successfully completed construction of and
placed into service a diluent recovery unit, or DRU, at the
Hardisty Terminal, as a part of a long-term solution to transport
heavier grades of crude oil produced in Western Canada by rail.
Additionally, we believe our Stroud Terminal provides an
advantageous rail destination for Western Canadian crude oil given
the optionality provided by its connectivity to the Cushing hub and
multiple refining centers across the United States. Rail also
generally provides a greater ability to preserve the specific
quality of a customer’s product relative to pipelines, providing
value to a producer or refiner. We expect these advantages,
including our origin-to-destination capabilities, to result in
long-term contract extensions and expansion opportunities across
our terminal network.
Growth Opportunities for our Operations
We apply a disciplined approach to pursuing our growth strategy,
which may include organic growth initiatives as well as
acquisitions of energy-related logistics assets. Potential
acquisitions may include assets developed by our sponsor or by
third-party logistics providers. We believe these represent
attractive opportunities to leverage our established and scalable
network footprint to enhance and extend our currently-contracted
cash flows.
USD is currently pursuing several development projects related to
long-term solutions to transport heavier grades of crude oil
produced in Western Canada, as well as projects related to the
storage and the transportation of liquid hydrocarbons and biofuels.
As the role of biofuels continues to expand in the clean energy
transition, we and USD are committed to offering new capabilities
and services across growing demand in clean fuels to include
ethanol, renewable diesel and biodiesel. These development projects
are expected to be supported by multi-year, take-or-pay agreements
with strategic customers which would generate stable and
predictable cash flows, as discussed in further detail
below.
Opportunities Related to USD’s Diluent Recovery Unit and Port
Arthur Terminal Projects
In December 2019, USD and Gibson jointly announced an agreement and
formed a 50%/50% joint venture to construct and operate a diluent
recovery unit, or DRU, located adjacent to the Partnership’s
Hardisty Terminal. A subsidiary of ConocoPhillips contracted to
process 50,000 barrels per day of dilbit through the DRU to produce
and ultimately ship bitumen by rail to USD’s newly constructed Port
Arthur Terminal, or PAT, on the U.S. Gulf Coast.
In December 2021, USD and Gibson jointly announced that the DRU has
been declared fully operational and the shipment of DRUbit™ by
Rail™, or DBR, has commenced. The DBR network creates a
first-of-its-kind separation technology and network that safely and
sustainably moves heavy Canadian crude oil, also known as bitumen,
from Canada to the U.S. Gulf Coast at a cost that is competitive
with pipeline alternatives. The DBR network is highly scalable and
is well-positioned for future commercial expansions. USD and Gibson
continue to
pursue commercial discussions with current and potential producer
and refiner customers to secure additional long-term agreements to
support future expansions at both the DRU and the PAT.
USD’s patented DRU technology separates the diluent that is added
to raw bitumen in the production process, which meets two important
market needs. It creates DRUbit™, a proprietary heavy Canadian
crude oil or bitumen that ships by rail and does not meet any of
the defined categories of hazardous materials by U.S. DOT Hazardous
Materials regulations and Canada’s Transport of Dangerous Goods
regulations, creating safety and environmental benefits.
Additionally, it returns the recovered diluent for reuse in the
Western Canadian market, which reduces delivered costs for diluent.
The DBR network provides meaningful safety, economic and
environmental benefits relative to conventional crude by rail. The
DBR network is supported by Canadian Pacific and Kansas City
Southern Railway Company. As the initial destination terminal, PAT
is unloading DRUbit™, blending it to customers’ specifications, and
is currently delivering it downstream through pipe or barge at or
above current contractual requirements. PAT has significant marine,
pipeline, rail and tank expansion capabilities and it is pipeline
connected to Phillips 66’s Beaumont Terminal, providing customers
access to a large network of refining and marine facilities. We
believe PAT has the infrastructure and ability to support growth,
including allowing for efficient rail movements along mainlines
from Canada and into the growing Mexico market, as discussed
below.
Port Arthur Terminal
PAT has the capability for rail unloading, barge dock loading and
unloading, tank storage and blending and is pipeline connected to
Phillips 66’s Beaumont Terminal, providing customers access to a
large network of refining and marine facilities. The facility can
handle DRUbit™, Dilbit and a heavy Canadian conventional barrel and
manage the blending of DRUbit™ into a marketable product for
shippers. The marine and pipeline delivery options for blended
products at the terminal allows customers to enhance market
flexibility and take advantage of cost advantaged delivery options.
PAT is served by the Kansas City Southern railroad and sits on
exclusive rail infrastructure, providing seamless scheduling,
operations, and communications resulting in ratable and reliable
service. Within the 233-acre terminal footprint, there is ample
waterfront and upland acreage that allows PAT expansion
capabilities to accommodate any foreseeable demand.
We believe the PAT project is well positioned in a market poised
for growth. The Port Arthur market is home to over 1.6 million
barrels of refining capacity per the EIA and a growing
petrochemical market. With ExxonMobil’s 250,000 barrel per day
refinery expansion which is expected to be in service sometime in
the first half of 2023, and Motiva’s acquisition of the Flint Hills
ethane cracker dovetailing into planned downstream expansions into
the petrochemical market, Port Arthur’s heavily utilized midstream
infrastructure can expect liquid volumes to increase.
Within the Port Arthur market, PAT will be well positioned to take
advantage of these opportunities and other organic growth projects.
Pipeline connectivity to the hub of Port Arthur’s liquids business
provides an advantage through reduced costs to deliver crude
locally relative to a barge alternative and will extend the market
reach for customers of PAT. Customers of PAT are able to deliver
barrels by pipeline and water into the Houston and Louisiana
markets.
Benefits to the Partnership
The successful completion of USD’s Hardisty DRU project enhanced
the sustainability and quality of the Partnership’s cash flows by
significantly increasing the average tenor of Terminal Services
Agreements at our Hardisty Terminal. The average remaining terms of
our three Terminal Services Agreements with ConocoPhillips at the
combined Hardisty Terminal were extended through mid-2031,
representing approximately 17% of the combined Hardisty Terminal’s
capacity. We expect that future customers of the Hardisty DRU
project will enter into similar long-term, more sustainable
commitments for terminalling services at the Partnership’s Hardisty
Terminal. USD’s interest in the Hardisty DRU and PAT projects would
also be available for possible acquisition by the Partnership, and
would be subject to the terms and conditions of the Partnership’s
ROFO on USD’s assets pursuant to the Omnibus Agreement between USD
and the Partnership, which extends through October 15,
2026.
Other Opportunities Related to Our Crude Oil Terminal
Network
As previously discussed, Western Canadian crude oil production is
projected to increase, driven primarily by developments in
Alberta’s oil sands region. Additionally, certain end users,
including refineries across North America, have made substantial
investments in recent years in order to efficiently process heavy
grades of crude oil, such as those from Western Canada. Given the
forecasted increases in Western Canadian crude oil production,
supply is expected to exceed current pipeline egress out of Western
Canada in the near term. which we believe will drive demand for a
crude by rail egress solution. Our strategically-located crude oil
terminal network, with established capacity and scalable design, is
well-positioned to meet these expected growing takeaway
needs.
Hardisty Terminal
We have contracted approximately 54% of the capacity at our
combined Hardisty Terminal through June 30, 2023 and
approximately 31% through January 2024. As previously discussed,
due to the successful commencement of USD’s DRU and PAT projects
discussed above, approximately 17% of the combined Hardisty
Terminal’s capacity was automatically extended through mid-2031. We
remain focused on renewing, extending or replacing our Hardisty
agreements that expired June 30, 2022 and expire June 30, 2023 on a
multi-year take-or-pay basis. Additionally, if USD and Gibson are
successful in securing an additional customer at the DRU, the
capacity associated with such commitment will likely be contracted
for transloading at the Hardisty Terminal on a long-term
basis.
Stroud Terminal
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. Our Stroud Terminal is the only rail
facility connected to the Cushing storage hub, which provides for
strategic and competitive advantages. The benchmark price in the
domestic spot market for U.S. crude oil known as West Texas
Intermediate, or WTI, is set at the Cushing hub. According to the
EIA, the Cushing storage hub has approximately 78 million barrels
of working storage capacity. There is also an expansive pipeline
infrastructure that connects into and out of the Cushing hub.
Because of the vast connectivity that Cushing offers, crude oil
that is delivered into Cushing can then be delivered to either
local refineries or it can be shipped to other markets such as the
United States Gulf Coast, which is the largest refinery complex in
the U.S. As such, 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.
We own 50% of the Stroud Terminal’s current capacity, which is
currently not under any contracted agreements. USDM owns the rights
to the other 50% of the Stroud Terminal’s current capacity pursuant
to the Marketing Services Agreement, or MSA, that was established
at the time of the acquisition of the Stroud Terminal. Per the MSA,
we granted USDM the right to market the capacity at the Stroud
Terminal in excess of the capacity of our initial customer in
exchange for a nominal per barrel fee. The capacity attributable to
USDM is also not currently under any contracted
agreements.
To facilitate marketing the capacity that is currently available at
the Stroud Terminal, USDM added a pipeline connection to a second
storage tank at a third-party facility at the Cushing, Oklahoma
crude oil hub, or the Cushing Hub. The expanded connectivity is
expected to facilitate incremental rail-to-pipeline shipments of
crude oil to the Cushing Hub by giving the Stroud Terminal better
capability to service multiple customers and/or grades of crude oil
simultaneously including the unloading of multiple grades of
dilbit. We remain focused on renewing and extending our Stroud
agreement that expired in mid-2022. Additionally, this development
project which is wholly-owned by USDG as well as 50% of the Stroud
Terminal capacity that USDM owns the rights to are subject to our
existing ROFO, should USDG propose to sell or transfer the
asset.
Casper Terminal
Our Casper Terminal currently includes approximately 100,000 bpd of
loading capacity and 900,000 barrels of tank storage capacity. The
Casper Terminal receives inbound crude oil primarily through our
dedicated direct pipeline connection from Enbridge’s Express
pipeline, which is subsequently loaded onto unit or manifest
trains.
Additionally, in December 2019, the Partnership completed
construction of and placed into service an outbound pipeline
connection from the Casper Terminal to the nearby Platte Terminal
located at the termination point of the Express
pipeline.
In December 2022, an existing customer of our Casper Terminal
extended its Terminal Services Agreement that was to expire on
December 31, 2022 for an additional year. The agreement contains
take-or-pay terms for storage services and variable fees associated
with actual throughput volumes and other services. Additionally, we
are currently utilizing our available storage and throughput
capacity to support our customers’ spot activity through buy-sell
agreements that generate cash flows in addition to those provided
by our customer agreements.
Opportunities Related to Clean Energy Transportation
Fuels
West Colton Terminal
We receive fixed fees per gallon of ethanol transloaded at our
terminal pursuant to a Terminal Services Agreement with one of the
world’s largest producers of biofuels. Effective January 2022, we
entered into a new five-year agreement with the existing West
Colton ethanol customer that has a minimum monthly throughput
commitment. This new agreement replaced the previous short-term
agreement at the terminal that had been in place since July 2009
and is expected to add incremental “Net
Cash from Operating Activities”
over the previous agreement, subject to changes in expected
throughput. Refer to
Factors
Affecting the Comparability of Our Financial Results
below for further information.
Additionally, in June 2021, we entered into a new Terminal Services
Agreement with USD Clean Fuels LLC, or USDCF, a subsidiary of USD,
that is supported by a minimum throughput commitment to USDCF from
an investment-grade rated, refining customer as well as a
performance guaranty from USD. The Terminal Services Agreement
provides for the inbound shipment of renewable diesel on rail at
our West Colton Terminal and the outbound shipment of the product
on tank trucks to local consumers. The new Terminal Services
Agreement has an initial term of five years and commenced December
1, 2021. We completed the process of modifying our existing West
Colton Terminal so that it now has capability to transload
renewable diesel in addition to the ethanol that it has been
transloading.
In exchange for the new Terminal Services Agreement at our West
Colton Terminal with USDCF discussed above, we also entered into a
Marketing Services Agreement with USDCF in June 2021, or the West
Colton MSA, pursuant to which we agreed to grant USDCF marketing
and development rights pertaining to future renewable diesel
opportunities associated with the West Colton Terminal in excess of
the Terminal Services Agreement with USDCF discussed above. Refer
to
Item 8. Financial Statements and Supplementary Data,
Note 13.
Transactions with Related Parties
in this Annual Report for further information.
USD Clean Fuels
USDCF was organized by USD for the purpose of providing production
and logistics solutions to the growing market for clean energy
transportation fuels. The policy for clean energy transportation
fuels in the United States continues to evolve and grow at both the
federal and state levels. As the role of advanced biofuels
continues to expand in the clean energy transition, we believe the
magnitude of change and challenges throughout the entire value
chain represent opportunities for USDCF in the areas of feedstock
gathering and handling, production and processing and downstream
distribution. To complement the Partnership’s existing ethanol
business, USDCF will focus on renewable diesel and sustainable
aviation fuel as it looks to build a growth platform across new
commodities, markets and partnerships. USDCF is focused on the
markets that have adopted Low Carbon Fuel Standards, as they
represent the greatest potential for accelerated growth in the U.S.
West Coast states and in Canada.
In January 2023, USDCF announced its intention to build a new
biofuels terminal in National City, California that will have the
capability to transload renewable diesel, biodiesel, ethanol and
sustainable aviation fuel, or SAF. The terminal will be served by
the BNSF Railway and will provide efficient transportation of clean
fuels to the area from the Midwest and US Gulf Coast. Pending
receipt of all local and state permits, the terminal is expected to
be operational by early 2024. The terminal development is supported
by two investment-grade rated parties that signed
long-term Terminal Service Agreements. The Terminal Services
Agreements provide for the inbound shipment of renewable diesel,
biodiesel, ethanol and SAF on rail, self-switching of the rail rack
and four truck loading spots that are equipped with in-line
injection capabilities to provide quality finished products to
customers. In addition to our West Colton Terminal, this terminal
will be the second terminal of a growing network of clean fuels
terminals that USDCF anticipates will ultimately include
California, Oregon, Washington, Canada and the Texas Gulf Coast
based on strong customer and railroad interest. These terminals are
expected to provide needed infrastructure that will make the
downstream logistics of biofuel production and feedstocks more
efficient. Any such development project pursued by USDCF would be
wholly-owned by USDCF, financed by USDCF, and subject to the terms
and conditions of our existing ROFO, should USDCF propose to sell
or transfer the asset.
Opportunities Related to Our Sponsor’s Texas Deepwater Development
on U.S. Gulf Coast
In October 2015, our sponsor entered into a joint venture to
develop a premier U.S. Gulf Coast logistics terminal on a 988-acre
parcel of property on the Houston Ship Channel. Its strategic
location and vast capability is uniquely positioned to provide
customers with flexible market access to key demand centers, both
domestic and abroad. Current master planning and permitting efforts
have positioned the property footprint to support development of a
wide variety of terminal infrastructure, marine docks (including
barge and deep water), inbound and outbound pipeline connectivity,
and a rail terminal with capacity to unload multiple unit trains
per day as well as provide ample railcar storage. The property is
in proximity to substantially all major inbound and outbound
pipelines, all of Houston’s refineries and petrochemical producers,
the Mont Belvieu hub, the Port of Houston and can be directly
accessed by multiple Class 1 railroads.
Recent market and industry developments highlight the Gulf Coast’s
strategic importance within global energy markets and overall
commodity supply chains. As an example, since the ban on exports of
crude oil was lifted in 2015, exports of crude oil and petroleum
products from PADD III on the Gulf Coast have increased from
approximately 3.5 million bpd to approximately 7.3 million bpd in
2021, which represented approximately 86% of the total crude oil
and petroleum products exported out of the U.S. during 2021. The
EIA’s Annual Energy Outlook continues to publish base case
forecasts that show, in the long-term, the U.S. is expected to
remain a net exporter of crude oil, natural gas, liquified natural
gas, petroleum and chemical products. These forecasts indicate that
the U.S., and specifically the Gulf Coast, will continue to be an
integral part of global energy supply and logistics, despite
uncertainty surrounding post-pandemic expectations for oil and
natural gas demand. Our sponsor’s Texas Deepwater development will
continue to pursue projects that position the terminal to take
advantage of this macro trend, and participate heavily in export
markets.
The unique attributes that favorably position the development of
Texas Deepwater in the traditional energy space also advantage its
role in the increasingly important renewable fuels transition. Our
sponsor is in active discussions with a wide range of renewable
energy participants that have strong interest in Texas Deepwater.
More efficient aggregation of renewable feedstocks, production of
globally exported renewable fuels, carbon capture and sequestration
as well as localized renewable fuels bunkering and storage are
potential opportunities currently being considered at the sponsor
level.
Our sponsor expects that these industry dynamics will contribute to
growing demand for multi-modal terminalling infrastructure and
other logistics services along the Gulf Coast, including at its
Houston Ship Channel property. Accordingly, our sponsor is actively
engaged in commercial development with potential customers to
provide terminalling and logistics solutions for crude oil
export/import, refined products export, petrochemicals and natural
gas liquids export as well as production, processing, logistics and
import/export of renewable fuels. Any such development project
would be wholly-owned by USD and its joint venture partner, and
USD’s interest in the Texas Deepwater development joint venture
would be subject to the terms and conditions of our existing ROFO
should USD propose to sell or transfer its ownership. If
successfully commercialized and developed, and subsequently
acquired by us, the Texas Deepwater development represents a
meaningful opportunity to add complementary logistics assets that
diversify our current network and have the potential to add
additional high-quality take-or-pay agreements with terms beyond
those related to our existing network.
Right of First Offer
In October 2014, we entered into the Omnibus Agreement with USD and
USDG, pursuant to which we were granted a ROFO on any midstream
infrastructure assets that they may develop, construct, or acquire
for a period of seven years. In June 2021, we entered into an
Amended and Restated Omnibus Agreement with USD, USDG and certain
other of their subsidiaries, which amends and restates the Omnibus
Agreement, dated October 15, 2014, to extend the termination date
of the ROFO period, as defined in the Omnibus Agreement, by an
additional five years such that the ROFO Period will terminate on
October 15, 2026 unless a Partnership Change of Control,
as defined in the Omnibus Agreement, occurs prior to such date.
Additional information about the Omnibus Agreement and the ROFO are
included in
Note 13.
Transactions with Related Parties
of our consolidated financial statements in
Item 8. Financial Statements and Supplementary Data
of this Annual Report.
USD has not engaged in any transactions that trigger our ROFO. We
cannot assure you that USD will be able to develop or construct, or
that we or USD will be able to acquire, any additional midstream
infrastructure projects. Among other things, the ability of USD or
the Partnership to further develop the Stroud Terminal, the DRU
project, or any other project, and our ability to acquire such
projects, will depend upon USD’s or our ability to raise additional
capital, including through equity and debt financing. We are under
no obligation to make any offer, and USD and USDG are under no
obligation to accept any offer we make, with respect to any asset
subject to our ROFO. Additionally, the approval of Energy Capital
Partners is required for the sale of any assets by USD or its
subsidiaries, including us (other than sales in the ordinary course
of business), acquisitions of securities of other entities that
exceed specified materiality thresholds and any material unbudgeted
expenditures or deviations from our approved budgets. Energy
Capital Partners may make these decisions free of any duty to us
and our unitholders. This approval would be required for the
potential acquisition by us of any project to expand the Stroud
Terminal, as well as any other projects or assets that USD may
develop or acquire in the future or any third-party acquisition we
may pursue independently or jointly with USD. Energy Capital
Partners is under no obligation to approve any such transaction.
Please refer to the discussion under
Part III, Item 10.
Directors,
Executive Officers and Corporate Governance—Special
Approval Rights of Energy Capital Partners
in this Annual Report regarding the rights of Energy Capital
Partners. If we are unable to acquire any projects to expand the
Stroud Terminal from USD, such expansions may compete directly with
our existing business for future throughput volumes, which may
impact our ability to enter into new Terminal Services Agreements,
including with our existing customers, following the expiration of
our existing agreements, or the terms thereof, and our ability to
compete for future spot volumes. Furthermore, cyclical changes in
the demand for crude oil and other liquid hydrocarbons may cause
USD, or us, to further re-evaluate any future expansion projects,
including expansion of the Stroud Terminal.
How We Generate Revenue
We conduct our business through two distinct reporting segments:
Terminalling services and Fleet services. We have established these
reporting segments as strategic business units to facilitate the
achievement of our long-term objectives, to assist in resource
allocation decisions and to assess operational
performance.
Terminalling Services
The Terminalling services segment includes a network of
strategically-located terminals that provide customers with railcar
loading and/or unloading capacity, as well as related logistics
services, for crude oil and biofuels. Substantially all of our cash
flows are generated under multi-year, take-or-pay Terminal Services
Agreements that include minimum monthly commitment fees. 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.
Hardisty Terminal Services Agreements. We
have Terminal Services Agreements with four high-quality, primarily
investment grade counterparties or their subsidiaries: Cenovus
Energy, Gibson, PBF Energy, and ConocoPhillips. Previous customers
whose Terminal Services Agreements expired during 2022 include
Suncor Energy and Teck Resources. The terminalling capacity at our
Hardisty Terminal is contracted under multi-year, take-or-pay
Terminal Services Agreements some of which are subject to
inflation-based escalators with a volume-
weighted average remaining contract life of 7.4 years as of
December 31, 2022. The successful completion of USD’s DRU
project, as previously discussed, automatically extended
approximately 17% of the combined Hardisty Terminal’s capacity
through mid-2031. All of our counterparties are obligated to pay a
minimum monthly commitment fee for the capacity to load an allotted
number of unit trains, representing a specified number of barrels
per month. If a customer loads fewer unit trains than its allotted
amount in any given month, that customer will receive a credit for
up to 12 months. This credit may be used to offset fees on
throughput volumes in excess of the customer’s minimum monthly
commitments in future periods to the extent capacity is available
for the excess volume. We will receive a per-barrel fee on any
volumes handled in excess of the customers’ allowed amount, to the
extent the additional volume is not subject to the credit discussed
above. If a force majeure event occurs, a
customer’s
obligation to pay us may be suspended, in which case the length of
the contract term will be extended by the same duration as the
force majeure event.
Stroud Terminal Services Agreements. We
own 50% of the Stroud Terminal’s current capacity. USDM owns the
rights to the other 50% of the Stroud Terminal’s current capacity
pursuant to the Marketing Services Agreement, or MSA, that was
established at the time of the acquisition of the Stroud Terminal.
Pursuant to the terms of the MSA, we granted USDM the right to
market the capacity at the Stroud Terminal in excess of the
capacity of our initial customer in exchange for a nominal per
barrel fee. The capacity attributable to USDM is currently not
under any contracted agreements. 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.
Casper
Terminal Services Agreements. Our
Casper Terminal includes a Terminal Services Agreement with a
midstream customer. The agreement with the midstream customer
contains take-or-pay terms for storage services and variable fees
associated with actual throughput volumes and other
services.
Additionally, we are currently utilizing our available storage and
throughput capacity to support our customers’ spot activity through
buy-sell agreements that generate cash flows in addition to those
provided by our terminalling services agreement.
West Colton Terminal Services Agreements. Our
West Colton Terminal receives fixed fees per gallon of ethanol
transloaded at our terminal pursuant to a Terminal Services
Agreement with one of the world’s largest producers of biofuels.
Effective January 2022, we entered into a new five-year agreement
with the existing West Colton ethanol customer that has a minimum
monthly throughput commitment. This new agreement replaced the
previous short-term agreement at the terminal that had been in
place since July 2009. Under this new agreement, our customer is
obligated to pay the greater of a minimum monthly commitment fee or
a throughput fee based on the actual volume of ethanol loaded at
our West Colton Terminal. Under the new agreement, if the customer
loads fewer volumes than its allotted amount in any given month,
that customer will receive a credit for up to six months, which may
be used to offset fees on throughput volumes in excess of its
minimum monthly commitments in future periods, to the extent
capacity is available for the excess volume.
Additionally, in June 2021, we entered into a new Terminal Services
Agreement with USD Clean Fuels LLC, or USDCF, a subsidiary of USD,
that is supported by a minimum throughput commitment to USDCF from
an investment-grade rated, refining customer as well as a
performance guaranty from USD. The Terminal Services Agreement
provides for the inbound shipment of renewable diesel on rail at
our West Colton Terminal and the outbound shipment of the product
on tank trucks to local consumers. The new Terminal Services
Agreement has an initial term of five years and commenced on
December 1, 2021. We have modified our existing West Colton
Terminal so that it now has the capability to transload renewable
diesel in addition to the ethanol that it has been
transloading.
In exchange for the new Terminal Services Agreement at our West
Colton Terminal with USDCF discussed above, we also entered into an
MSA with USDCF in June 2021, or the West Colton MSA, pursuant to
which we agreed to grant USDCF marketing and development rights
pertaining to future renewable diesel opportunities associated with
the West Colton Terminal in excess of the Terminal Services
Agreement with USDCF discussed
Fleet Services
We provide one of our customers with leased railcars and fleet
services related to the transportation of liquid hydrocarbons by
rail on take-or-pay terms under a master fleet services agreement.
We do not own any railcars. As of December 31, 2022, our
railcar fleet consisted of 200 railcars, which we lease from a
railcar manufacturer all of which are C&I railcars. The
remaining contract life on our railcar fleet is six months as of
December 31, 2022.
Under the master fleet services agreement, we provide our customer
with railcar-specific fleet services, which may include, among
other things, the provision of relevant administrative and billing
services, the repairs and maintenance of railcars in accordance
with standard industry practice and applicable law, the management
and tracking of the movement of railcars, the regulatory and
administrative reporting and compliance as required in connection
with the movement of railcars, and the negotiation for and sourcing
of railcars. Our customer typically pays us and our assignees
monthly fees per railcar for these services, which include a
component for fleet services.
Historically, we contracted with railroads on behalf of some of our
customers to arrange for the movement of railcars from our
terminals to the destinations selected by our customers. We were
the contracting party with the railroads for those shipments and
were responsible to the railroads for the related fees charged by
the railroads, for which we were reimbursed by our customers. Both
the fees charged by the railroads to us and the reimbursement of
these fees by our customers are included in our consolidated
statements of operations in the revenues and operating costs line
items entitled “Freight
and other reimbursables.”
Also, we have historically assisted our customers with procuring
railcars to facilitate their use of our terminalling services. Our
wholly-owned subsidiary USD Rail LP has historically entered into
leases with third-party manufacturers of railcars and financial
firms, which it has then leased to customers. Although we expect to
continue to assist our customers in obtaining railcars for their
use transporting crude oil to or from our terminals, we do not
intend to continue to act as an intermediary between railcar
lessors and our customers as our existing lease agreements expire,
are otherwise terminated, or are assigned to our existing
customers. Should market conditions change, we could potentially
act as an intermediary with railcar lessors on behalf of our
customers again in the future.
How We Evaluate Our Operations
Our management uses a variety of financial and operating metrics to
evaluate our operations. When we evaluate our consolidated
operations and related liquidity, we consider these metrics to be
significant factors in assessing our ability to generate cash and
pay distributions and include: (i) Adjusted EBITDA and DCF;
(ii) operating costs; and (iii) volumes. We define Adjusted
EBITDA and DCF below. When evaluating our operations at the segment
level, we evaluate using Segment Adjusted EBITDA. Refer to
Item 8. Financial Statements and Supplementary Data,
Note 15.
Segment Reporting
of this Annual Report.
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 flows 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 flows being retained for use in enhancing our existing
business; and
•the
sustainability of our current distribution rate per
unit.
We believe that the presentation of Adjusted EBITDA and DCF in this
Report provides information that enhances an investor’s
understanding of our ability to generate cash for payment of
distributions and other purposes. The GAAP measure most directly
comparable to Adjusted EBITDA and DCF is “Net
cash provided by operating activities.”
Adjusted EBITDA and DCF should not be considered alternatives to
“Net
cash provided by operating activities”
or any other measure of liquidity presented in accordance with
GAAP. Adjusted EBITDA and DCF exclude some, but not all, items that
affect “Net
cash provided by operating activities,”
and these measures may vary among other companies. As a result,
Adjusted EBITDA and DCF may not be comparable to similarly titled
measures of other companies.
The following table sets forth a reconciliation of
“Net
cash provided by operating activities,”
the most directly comparable financial measure calculated and
presented in accordance with GAAP, to Adjusted EBITDA and
DCF:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2022 |
|
2021
(1)
|
|
2020
(1)
|
|
(in thousands) |
|
Reconciliation of Net cash provided by operating activities to
Adjusted EBITDA and Distributable cash flow: |
|
|
|
|
|
|
Net cash provided by operating activities |
$ |
37,241 |
|
|
$ |
57,886 |
|
|
$ |
50,571 |
|
|
Add (deduct): |
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of deferred financing costs |
(1,170) |
|
|
(1,232) |
|
|
(1,109) |
|
|
Deferred income taxes |
(90) |
|
|
78 |
|
|
752 |
|
|
Changes in accounts receivable and other assets |
(11,923) |
|
|
(235) |
|
|
1,183 |
|
|
Changes in accounts payable and accrued expenses |
5,211 |
|
|
(13,429) |
|
|
1,974 |
|
|
Changes in deferred revenue and other liabilities |
9,099 |
|
|
3,396 |
|
|
(7,045) |
|
|
|
|
|
|
|
|
Interest expense, net |
10,604 |
|
|
6,986 |
|
|
10,049 |
|
|
Provision for income taxes |
1,293 |
|
|
933 |
|
|
337 |
|
|
Foreign currency transaction loss (gain)
(2)
|
2,055 |
|
|
(707) |
|
|
170 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash deferred amounts
(3)
|
(4,878) |
|
|
2,960 |
|
|
3,954 |
|
|
Adjusted EBITDA attributable to Hardisty South entities prior to
acquisition
(4)
|
(258) |
|
|
(1,529) |
|
|
(5,240) |
|
|
Adjusted EBITDA |
47,184 |
|
|
55,107 |
|
|
55,596 |
|
|
Add (deduct): |
|
|
|
|
|
|
Cash paid for income taxes, net
(5)
|
(1,064) |
|
|
(906) |
|
|
(303) |
|
|
Cash paid for interest |
(8,374) |
|
|
(5,912) |
|
|
(9,508) |
|
|
Maintenance capital expenditures, net |
(56) |
|
|
(541) |
|
|
(403) |
|
|
Cash paid for income taxes, interest and maintenance capital
expenditures attributable to Hardisty South entities prior to
acquisition
(6)
|
59 |
|
|
534 |
|
|
1,126 |
|
|
Distributable cash flow
|
$ |
37,749 |
|
|
$ |
48,282 |
|
|
$ |
46,508 |
|
(1) As
discussed in
Item 8. Financial Statements and Supplementary
Data,
Note 2.
Summary of Significant Accounting Policies
of this Annual Report, our consolidated financial statements have
been retrospectively recast to include the pre-acquisition results
of the Hardisty South Terminal, which we acquired effective
April 1, 2022, because the transaction was between
entities under common control.
(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.
(4) Adjusted
EBITDA attributable to the Hardisty South entities for the three
months ended March 31, 2022 and the years ended
December 31, 2021 and 2020, was excluded from the
Partnership’s Adjusted EBITDA, as these amounts were generated by
the Hardisty South entities prior to the Partnership’s acquisition
and therefore, they were not amounts that could be distributed to
the Partnership’s unitholders. Refer to the table provided below
for a reconciliation of
“Net cash provided by operating activities”
to Adjusted EBITDA for the Hardisty South entities prior to
acquisition.
(5) Includes
the net effect of tax refunds of $84 thousand received in the
second quarter of 2022 and $480 thousand received in the third
quarter of 2020 associated with carrying back U.S. net operating
losses incurred during 2020 and prior periods allowed for by the
provisions of the CARES Act. Also includes the net effects of tax
refunds of $31 thousand received in the third quarter of 2022
and $21 thousand received in the fourth quarter of 2020
associated with prior period Canadian taxes.
(6) Cash
payments made for income taxes, interest and maintenance capital
expenditures attributable to the Hardisty South entities for the
three months ended March 31, 2022 and the years ended December 31,
2021 and 2020 were excluded from the Partnership’s DCF
calculations, as these amounts were generated by the Hardisty South
entities prior to the Partnership’s acquisition. Included for the
three months ended March 31, 2022 was $59 thousand of
cash paid for interest. Included for the year ended December 31,
2021 was $165 thousand of cash paid for income taxes, $440 thousand
of cash paid for interest, partially offset by a net refund of $71
thousand related to maintenance capital expenditures. Included for
the year ended December 31, 2020 was $915 thousand of cash paid for
interest, $232 thousand of cash paid for maintenance capital
expenditures, partially offset by a refund of $21 thousand related
to income taxes.
Adjusted EBITDA and DCF presented above for the year ended December
31, 2022 include the impact of $3.2 million of expenses
incurred during the period associated with our recent drop down
acquisition of the Hardisty South Terminal assets from our Sponsor,
respectively. Refer to
Item 8. Financial Statements and Supplementary Data,
Note
3.Hardisty South Acquisition
of this Annual Report for more information.
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 attributable
to the Hardisty South entities prior to our acquisition of the
entities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2022 |
|
For the Year Ended December 31, 2021 |
|
For the Year Ended December 31, 2020 |
|
(in thousands) |
|
Reconciliation of Net cash provided by operating activities to
Adjusted EBITDA: |
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities |
|
$ |
(1,475) |
|
|
$ |
10,761 |
|
|
$ |
4,757 |
|
|
Add (deduct): |
|
|
|
|
|
|
|
Amortization of deferred financing costs |
|
(84) |
|
|
(101) |
|
|
(280) |
|
|
Deferred income taxes |
|
(53) |
|
|
(238) |
|
|
(221) |
|
|
Changes in accounts receivable and other assets |
|
(217) |
|
|
(5,510) |
|
|
(1,869) |
|
|
Changes in accounts payable and accrued expenses |
|
155 |
|
|
(6,714) |
|
|
929 |
|
|
Changes in deferred revenue and other liabilities |
|
488 |
|
|
4,265 |
|
|
(1,828) |
|
|
Interest expense, net |
|
117 |
|
|
499 |
|
|
1,154 |
|
|
Provision for income taxes |
|
59 |
|
|
233 |
|
|
378 |
|
|
Foreign currency transaction loss (gain) |
|
1,600 |
|
|
(1,020) |
|
|
(97) |
|
|
Non-cash deferred amounts
(1)
|
|
(332) |
|
|
(646) |
|
|
2,317 |
|
|
Adjusted EBITDA
(2)
|
|
$ |
258 |
|
|
$ |
1,529 |
|
|
$ |
5,240 |
|
(1) Represents
the change in non-cash contract assets and liabilities associated
with revenue recognized at blended rates based on tiered rate
structures in certain of the customer contracts.
(2) Adjusted
EBITDA associated with the Hardisty South entities prior to our
acquisition includes the impact of expenses pursuant to a services
agreement with USD for the provision of services related to the
management and operation of transloading assets. These expenses
totaled $52.2 million and $28.8 million for the years ended
December 31, 2021 and 2020, respectively, and $3.2 million for the
three months ended March 31, 2022. Upon our acquisition of the
entities effective April 1, 2022, the services agreement with USD
was cancelled and a similar agreement was established with us.
Refer to
Item 8. Financial Statements and Supplementary Data,
Note 13.
Transactions with Related Party
of this Annual Report for more information.
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. In addition,
we have experienced an increase in certain costs during the current
year associated with the increased inflation rate, primarily
relating to higher utilities costs for electricity and higher fuel
costs including natural gas and diesel, and expect such costs to
remain at elevated levels for at least the near future. We expect
to incur additional operating costs, including subcontracted rail
services and pipeline fees, when we handle additional volumes at
our terminals.
Our management seeks to maximize the profitability of our
operations by effectively managing both our operating and
maintenance expenses. As our terminal facilities and related
equipment age, we expect to incur regular maintenance expenditures
to maintain the operating capabilities of our facilities and
equipment in compliance with sound business practices, our
contractual relationships and regulatory requirements for operating
these assets. We record these maintenance and other expenses
associated with operating our assets in “Operating
and maintenance”
costs in our consolidated statements of operations.
Volumes
The amount of Terminalling services revenue we generate depends on
minimum customer commitment fees and the throughput volume that we
handle at our terminals in excess of those minimum commitments.
These volumes are primarily affected by the supply of and demand
for crude oil, refined products and biofuels in the markets served
directly or indirectly by our assets. Additionally, these volumes
are affected by the spreads between the benchmark prices for these
products, which are influenced by, among other things, the
available takeaway capacity in those markets. Although customers at
our terminals have committed to minimum monthly fees under their
Terminal Services Agreements with us, which will generate the
majority of our Terminalling services revenue, our results of
operations will also be affected by:
•our
customers’ utilization of our terminals in excess of their minimum
monthly volume commitments;
•our
ability to identify and execute accretive acquisitions and
commercialize organic expansion projects to capture incremental
volumes; and
•our
ability to renew contracts with existing customers, enter into
contracts with new customers, increase customer commitments and
throughput volumes at our terminals, and provide additional
ancillary services at those terminals.
General Trends and Outlook
In
addition to the discussion provided below, refer also to the
Overview
and Recent Developments—
Market Update
section above. 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, as well as the
ongoing situation in Ukraine and their impact on world economic
conditions, along with inflationary pressures and the volatility in
the oil and natural gas markets have created increased uncertainty
with respect to future conditions and our ability to accurately
predict future results.
Hardisty and Stroud Terminals Customer Contract Renewals and
Expirations
In early April 2022, we completed the acquisition of 100% of the
entities owning the Hardisty South Terminal assets from USDG. The
new combined Hardisty Terminal, which includes our legacy Hardisty
Terminal and the newly acquired Hardisty South Terminal, now has
the designed takeaway capacity of three and one-half unit trains
per day, or approximately 262,500 barrels per day. Contracts
representing approximately 26% of the combined Hardisty Terminal’s
capacity expired in June 2022 and, as a result, approximately 54%
is contracted through June 30, 2023; approximately 31% is
contracted through January 2024; and approximately 17% is
contracted through mid-2031.
Impacts on Customer Contracts From 2021 DRU Conversion
As previously discussed, construction of USD’s DRU project was
completed in July 2021 and was declared fully operational in
December 2021. Effective August 2021, the maturity date of three
terminalling services
agreements that are with the existing DRU customer at our Hardisty
Terminal were extended through mid-2031, representing approximately
17% of the combined Hardisty Terminal’s capacity. Due to the
significantly longer contract tenor of the terminalling services
agreements associated with the DRU volumes, contracted rates on an
annual basis are lower as compared to the contracted rates
associated with the historical, shorter-term, agreements, which
results in lower cash flows to the Partnership on an annual basis,
but support a higher net present value to the Partnership and
provide a more predictable cash flow profile.
Also, effective August 2021, the existing DRU customer elected to
reduce its volume commitments at the Stroud Terminal attributable
to the Partnership by one-third of the previous commitment through
June 2022, at which point the agreement terminated. This agreement
represented our sole third-party customer contract for our Stroud
Terminal and as such none of the capacity of the Stroud Terminal is
contracted as of July 1, 2022.
Hardisty and Stroud Contract Expirations
At the end of June 2022, contracts representing approximately 26%
of the combined Hardisty Terminal’s capacity expired. In addition,
the remaining contracted capacity at the Stroud Terminal also
expired at the end of June 2022. The expired contracted capacity at
the combined Hardisty and Stroud Terminals represented
approximately $24.7 million and $54.2 million of our terminalling
services revenues for the year ended December 31, 2022
and 2021, respectively, which represents approximately 23% and 27%
of terminalling services revenues for the respective periods. Also,
certain of the terminalling services agreements at our Hardisty
Terminal that expire June 30, 2023 include a tiered rate structure
that includes rate decreases that occur annually on July 1st of
each year throughout the term of the agreement.
Management is focused on renewing, extending or replacing the
agreements that have expired or are set to expire at the Hardisty
and Stroud Terminals with new, multi-year take or pay commitments
and is actively engaging with current and new customers. Given
current and expected market conditions, management believes that we
will have the opportunity to renew and extend or replace the
agreements that expired at the end of the second quarter of 2022,
sometime during the second half of 2023. Additionally, management
is marketing terminalling services at the Stroud Terminal to
potential customers that may be in need of access to the numerous
markets connected to the Cushing oil hub, and management believes
that we will have the opportunity to increase utilization at the
terminal sometime during the second half of 2023. However, the
timing of such renewals or replacements, as well as the expected
contracted rates are uncertain and difficult to predict, if such
renewals or replacements occur at all. If and to the extent we are
unable to renew, extend or replace our customer agreements at the
Hardisty and Stroud Terminals or experience a delay in doing so
beyond mid-2023, our revenue, cash flows from operating activities
and Adjusted EBITDA would be materially adversely impacted. This
may adversely impact our ability to make distributions to our
unitholders or our ability to comply with financial covenants in
our Credit Agreement. Moreover, our ability to refinance our
outstanding indebtedness or extend the maturity date of, or get a
covenant waiver under, our Credit Agreement may be negatively
impacted. Refer to the discussion in
Liquidity and Capital Resources
below for further information. Refer to
Part I. Item 1A.
Risk
Factors
in this Annual Report on Form 10-K for further discussion of
certain risks relating to our customer contract
renewals.
Potential Impact of Hardisty and West Colton Deficiency Credit
Usage by Our Customers
As previously discussed, customers of our Hardisty and West Colton
Terminals are obligated to pay a minimum monthly commitment fee for
the capacity to load an allotted number of unit trains,
representing a specified number of barrels per month. If a customer
loads fewer unit trains than its allotted amount in any given
month, that customer will receive a credit for up to 12 months,
also referred to as a deficiency credit. This credit may be used to
offset fees on throughput volumes in excess of the customer’s
minimum monthly commitments in future periods to the extent
capacity is available for the excess volume. Additionally, we could
incur incremental costs associated with loading the additional
trains for our customers if they have and use their accrued
deficiency credits, but such costs are not expected to be material.
Based on current circumstances and conversations with our
customers, as of December 31, 2022, we deferred revenues
of $0.4 million associated with the expected future usage of
deficiency credits. As of December 31, 2021, we deferred revenues
of $1.4 million that were associated with the expected usage of the
deficiency credits during 2022.
Going Concern
We evaluate at each annual and interim period whether there are
conditions or events, considered in the aggregate, that raise
substantial doubt about our ability to continue as a going concern
within one year after the date that the consolidated financial
statements are issued. Our evaluation is based on relevant
conditions and events that are known and reasonably knowable at the
date that the consolidated financial statements are issued. The
maturity date of our Credit Agreement is November 2, 2023. As a
result of the maturity date being within 12 months after the date
that these financial statements were issued, the amounts due under
our Credit Agreement have been included in our going concern
assessment. Our ability to continue as a going concern is dependent
on the refinancing or the extension of the maturity date of our
Credit Agreement. If we are unable to refinance or extend the
maturity date of our Credit Agreement, we likely would not have
sufficient cash on hand or available liquidity to repay the
maturing Credit Agreement debt as it becomes due.
The conditions described above raise substantial doubt about our
ability to continue as a going concern for the next 12
months.
In addition to the above, there was previous uncertainty in our
ability to remain in compliance with the covenants contained in our
Credit Agreement for a period of 12 months after we issued our
third quarter 2022 financial statements. As discussed further
in
Item 8. Financial Statements and Supplementary Data,
Note 22.
Subsequent Events,
of this Annual Report, in January 2023 we entered into an amendment
to our Credit Agreement that among other items increases the total
leverage ratio covenant allowed for by the Credit Agreement through
September 2023. The Credit Agreement Amendment alleviates the
previous uncertainty in our ability to remain in compliance with
the covenants contained in our Credit Agreement through the current
maturity date of the Credit Agreement.
Refer to
Part I. Item 1A.
Risk
Factors
in this Annual Report on Form 10-K for a discussion of risks
associated with a default under our Credit Agreement.
In addition to the relief we were granted in our amendment to our
Credit Agreement as discussed above we are also pursuing plans to
refinance our Credit Agreement or extend and amend the current
obligations under the Credit Agreement; however, we cannot make
assurances that we will be successful in these efforts, or that any
refinancing or extension would be on terms favorable to us.
Moreover, our ability to refinance our outstanding indebtedness or
extend the maturity date of our Credit Agreement may be negatively
impacted to the extent we are unable to renew, extend or replace
our customer agreements at the Hardisty and Stroud Terminals or
experience prolonged delays in doing so. We recorded our Credit
Agreement as a current liability in our consolidated balance sheet
as of December 31, 2022.
Due to the substantial doubt about our ability to continue as a
going concern discussed above, as of December 31, 2022,
we have recorded a valuation allowance against our deferred tax
asset that is associated with our Canadian entities. The
consolidated financial statements contained herein do not include
any other adjustments that might result from the outcome of this
uncertainty, nor do they include adjustments to reflect the
possible future effects of the recoverability and classification of
recorded asset amounts and classifications of liabilities that
might be necessary should we be unable to continue as a going
concern.
Factors That May Impact Future Results of Operations
Demand for Rail Transportation of Crude Oil and
Biofuels
High-growth crude oil production areas in North America are often
located at significant distances from refining centers, creating
constantly evolving regional imbalances, which require the
expedited development of flexible and sustainable transportation
solutions. The extensive existing rail network, combined with rail
transportation’s relatively low capital and fixed costs compared to
other transportation alternatives, has strategically positioned
rail as a long-term transportation solution for growing and
evolving energy infrastructure needs. In the event that additional
pipeline capacity is constructed, or crude oil production decreases
significantly, demand for transportation of crude oil by rail may
be adversely impacted. Please also refer to the
Overview
and Recent Developments—
Market Update
section above.
Changes in environmental and gasoline blending regulations may
affect the use of ethanol in the market for transportation fuel.
Due to corrosion concerns unique to biofuels, such as ethanol, the
long-haul transportation of biofuels via multi-product pipelines is
less efficient and less economical than rail. Rail also helps
aggregate fragmented ethanol production across the country. In the
event that dedicated pipelines are constructed, or additional
technologies are developed to allow for more economical
transportation of biofuels on multi-product pipelines, demand for
transportation of biofuels by rail may be affected.
Supply and Demand for Crude Oil and Refined Products
The volume of crude oil and biofuels that we handle at our
terminals ultimately depends on refining and blending margins.
Refining and blending margins are dependent mostly upon the price
of crude oil or other refinery feedstocks and the price of refined
products. These prices are affected by numerous factors beyond our
control, including the global supply and demand for crude oil and
gasoline and other refined products. The supply of crude oil will
depend on numerous factors, including commodity pricing,
improvements in extractive technology, environmental regulation and
other factors. Our ability to grow through expansion or
acquisitions and our ability to renew or extend our Terminal
Services Agreements could be affected by a long-term reduction in
supply or demand.
Customer Contracts
Our business is subject to the risk that we may not be able to
renew, extend or replace our customer contracts as their terms
expire. Refer to the discussion above under the heading
General
Trends and Outlook
for information regarding customer contract renewals and
expirations and changes in fee structures. For a discussion of the
risks associated with our ability to renew, extend or replace
customer contracts, see
Part I. Item 1A.
Risk
Factors—Our
contracts are subject to termination at various times which creates
renewal risks
of this Annual Report.
Regulatory Environment
Our operations are subject to federal, state, and local laws and
regulations relating to the protection of health and the
environment, including laws and regulations that govern the
handling of liquid hydrocarbons and biofuels. Additionally, we are
subject to regulations governing railcar design and evolving
regulations pertaining to the shipment of liquid hydrocarbons and
biofuels by rail as discussed in greater detail in
Part I, Item 1.
Business—Impact
of Regulation
in this Annual Report. Similar to other industry participants,
compliance with existing environmental laws and regulations, as
well as those that may be added in the future, could increase our
overall cost of doing business. Such costs, include the costs we
incur to construct, maintain, operate and upgrade equipment and
facilities, or the costs of our customers, which may reduce the
attractiveness of rail transportation. While changes in these laws
and regulations could indirectly affect our results of operations,
financial condition and cash flows, we believe that consumers of
our services place additional value on utilizing established and
reputable third-party providers to satisfy their rail terminal and
logistics needs, which may allow us to increase market share
relative to customer-owned operations or smaller operators that
lack an established track record of safety and regulatory
compliance. Additionally, our master fleet services agreement
generally obligate our customer to pay for modifications and other
required repairs to our leased and managed railcar fleet. However,
we cannot assure that we will be able to successfully pass all such
regulatory costs on to our customer. Our one fleet service
agreement expires at June 30, 2023 and we do not expect
to renew or further extend the agreement.
Acquisition Opportunities
We plan to continue to pursue strategic acquisitions of
energy-related logistics assets from both USD and third parties
that will provide attractive returns to our unitholders, including
facilities that provide for storage and transportation of liquid
hydrocarbons and biofuels. We intend to leverage our industry
relationships and market knowledge to successfully execute on such
opportunities, which we may pursue independently or jointly with
USD. We have entered into the Omnibus Agreement with USD and USDG,
pursuant to which USDG has granted us a ROFO on any midstream
infrastructure assets that they may develop, construct, or acquire
until October 15, 2026. Additional information regarding our
growth opportunities is discussed in
Growth
Opportunities for our Operations
above and information regarding the Omnibus Agreement is presented
in
Note 13.
Transactions with Related Parties—Omnibus
Agreement
of
Item 8. Financial Statement and Supplementary Data
in this Annual Report. We cannot assure you that USD will be able
to develop or construct, or that we or USD will be able to acquire,
any other
midstream infrastructure projects, including any projects to expand
the Stroud Terminal. Among other things, the ability of USD to
further develop the Stroud Terminal, or any other project, and our
ability to acquire such projects, will depend upon USD’s and our
ability to raise additional equity and debt financing. We are under
no obligation to make any offer, and USD and USDG are under no
obligation to accept any offer we make, with respect to any asset
subject to our ROFO. Additionally, the approval of Energy Capital
Partners is required for the sale of any assets by USD or its
subsidiaries, including us (other than sales in the ordinary course
of business), acquisitions of securities of other entities that
exceed specified materiality thresholds and any material unbudgeted
expenditures or deviations from our approved budget. Energy Capital
Partners may make these decisions free of any duty to us and our
unitholders. This approval would be required for the potential
acquisition by us of any projects to expand the Stroud Terminal, as
well as any other projects or assets that USD may develop or
acquire in the future or any third-party acquisition we may pursue
independently or jointly with USD. Energy Capital Partners is under
no obligation to approve any such transaction. Additional
discussion of the special approval rights of Energy Capital
Partners is included in
Part III, Item 10.
Directors,
Executive Officers and Corporate Governance—Special
Approval Rights of Energy Capital Partners
in this Annual Report. If we are unable to acquire any projects to
expand the Stroud Terminal from USD, which USD retained the right
to develop and operate, these projects may compete directly with
our current terminal assets for future throughput volumes. As a
result, our ability to enter into new Terminal Services Agreements,
or to renew such agreements with our existing customers, following
the termination of our existing agreements or the terms thereof and
our ability to compete for future spot volumes could be affected.
Furthermore, cyclical changes in the demand for crude oil and other
liquid hydrocarbons may cause USD or us to reevaluate any future
expansion projects, including any projects to expand the Stroud
Terminal. Lastly, if we do not make acquisitions on economically
beneficial terms, our future growth will be limited, and the
acquisitions we do make may reduce, rather than increase, our
results of operations and cash flows.
Interest Rate Environment
Interest rates in U.S. and international credit markets remain low
relative to historical levels. This could affect our future ability
to access the credit markets to fund our future growth.
Additionally, as with other yield-oriented securities, our unit
price could be affected by the level of our cash distributions and
the associated implied distribution yield. Therefore, changes in
interest rates, either positive or negative, may affect the yield
requirements of investors who invest in our units, and, as such, a
rising interest rate environment could have an adverse impact on
our unit price and our ability to issue additional equity, or
increase the cost of issuing equity. However, we expect that our
cost of capital would remain competitive, as our competitors would
face similar circumstances. We have entered into an interest rate
swap contract to partially mitigate our exposure to interest rate
fluctuations on our variable rate debt. The swap contract
establishes a fixed secured overnight rate, or SOFR, for our debt
of 3.956%. Refer to
Note 18. Derivative
Financial Instruments
of
Item 8. Financial Statement and Supplementary Data
in this Annual Report for more information on our interest rate
swap.
Factors Affecting the Comparability of Our Financial
Results
The comparability of our current financial results in relation to
prior periods are affected by the factors described
below.
Impact of Hardisty and Stroud Terminals Contract
Changes
As a result of the successful commencement of the DRU as previously
discussed, effective August 1, 2021, the maturity date of three
Terminal Services Agreements that are with the existing DRU
customer at our Hardisty Terminal were extended through mid-2031.
Due to the significantly longer contract tenor of the terminalling
services agreements associated with the DRU volumes, contracted
rates on an annual basis are lower as compared to the contracted
rates associated with the historical, shorter-term, agreements,
which results in lower cash flows to the Partnership on an annual
basis, but support a higher net present value to the Partnership
and provide a more predictable cash flow profile. Additionally,
effective August 1, 2021, the existing DRU customer elected to
reduce its volume commitments at the Stroud Terminal attributable
to the Partnership by one-third of the previous commitment through
June 2022, at which point the agreement was terminated. The
agreement represented our sole third-party customer contract for
our Stroud Terminal and as such none of the capacity of the Stroud
Terminal is
contracted as of July 1, 2022. For further discussion of the
impacts of these contract changes on our financial results, refer
to
Results of Operations
—
By Segment, Terminalling Services
below.
Early Cancellation of Hardisty South Customer Contract in
2021
In June 2021, a customer of the Hardisty South terminal paid our
Sponsor for the early cancellation of their existing multi-year
take-or-pay contract. The contract cancellation payment was
recognized as revenue by our Sponsor in June 2021 and in turn a
proportionate amount of pipeline fee expense was also recognized
under our collaborative arrangement with Gibson.
Casper Terminal Impairment of Intangible Assets and Long-lived
Assets and Goodwill
In September 2022, we determined that recurring periods where cash
flow projections were not met due to adverse market conditions at
our Casper Terminal was an event that required us to evaluate our
Casper Terminal asset group for impairment. Accordingly, we
measured the fair value of our Casper terminal asset group by
primarily relying on the cost approach. As a result of the
impairment analysis, we determined that the carrying value of the
Casper Terminal asset group exceeded the fair value of the Casper
terminal as of September 30, 2022, the date of our evaluation and
recognized an impairment loss of $71.6 million which we recorded
in
“Impairment loss on intangible and long-lived assets”
on our consolidated statements of operations.
In addition, 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
year ended December 31, 2020.
West Colton Terminal Customer Contracts
Our West Colton Terminal receives fixed fees per gallon of ethanol
transloaded at our terminal pursuant to a Terminal Services
Agreement with one of the world’s largest producers of biofuels.
Effective January 2022, we entered into a new five-year agreement
with the existing West Colton ethanol customer that has a minimum
monthly throughput commitment. This new agreement replaced the
previous short-term agreement at the terminal that had been in
place since July 2009. Under this new agreement, our customer is
obligated to pay the greater of a minimum monthly commitment fee or
a throughput fee based on the actual volume of ethanol loaded at
our West Colton Terminal. If the customer loads fewer volumes than
its allotted amount in any given month, that customer will receive
a credit for up to six months, which may be used to offset fees on
throughput volumes in excess of its minimum monthly commitments in
future periods, to the extent capacity is available for the excess
volume. This contract is expected to add incremental
“Net cash provided by operating activities”
and Adjusted EBITDA of approximately $1.0 million to $1.5
million per year, subject to changes in expected
throughput.
Additionally, in June 2021, we entered into a new terminalling
services agreement with USD Clean Fuels LLC, or USDCF, a subsidiary
of USD, that is supported by a minimum throughput commitment to
USDCF from an investment-grade rated, refining customer as well as
a performance guaranty from USD. The Terminal Services Agreement
provides for the inbound shipment of renewable diesel on rail at
our West Colton Terminal and the outbound shipment of the product
on tank trucks to local consumers. The new terminalling services
agreement has an initial term of five years and commenced on
December 1, 2021 and is expected to add approximately $2.0 million
per year of incremental
“Net cash provided by operating activities”
and Adjusted EBITDA over the five-year term of the agreement. We
have modified our existing West Colton Terminal so that it now has
the capability to transload renewable diesel in addition to the
ethanol that it has been transloading.
CARES Act
On March 27, 2020, the CARES Act was signed into law. The CARES Act
is an emergency economic stimulus package enacted in response to
the coronavirus outbreak which, among other measures, contains
numerous income tax provisions. Some of these tax provisions are
expected to be effective retroactively for tax years ending before
the date of enactment. For us, the most significant change included
in the CARES Act was the impact to U.S.
net operating loss carryback provisions. U.S. net operating losses
incurred in tax years 2018, 2019, and 2020 can now be fully carried
back to the preceding five tax years and may be used to fully
offset taxable income (i.e. they are not subject to the 80 percent
net income offset limitation of Section 172 of the U.S. Tax
Code).
As a result of these CARES Act changes, for the year ended December
31, 2020, we recognized a current tax benefit of $536 thousand
for a claimable tax refund by carrying back to U.S. net operating
losses incurred in 2018, 2019, and 2020. We also recognized a
one-time deferred tax expense of $46 thousand in the first
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.
Segment Allocation of Certain Selling, General and Administrative
Costs
Historically, we have allocated certain selling, general and
administrative expenses to our Terminalling services and Fleet
services segments that included corporate function personnel costs
for managing our business that are allocated to us by our general
partner, as well as other administrative expenses including audit
fees and certain consulting fees. Beginning with the first quarter
in 2021, these selling, general, and administrative expenses that
are not directly related to operating our Terminalling services and
Fleet services segments are now allocated to corporate selling,
general, and administrative expenses to better reflect the
financial results of our Terminalling services and Fleet services
segments. The effect of the change in allocation of the certain
selling, general and administrative expenses increases the segment
profit for both the Terminalling and Fleet segments with a
corresponding increase to the expenses associated with Corporate
activities, as compared to the method of allocation that was used
in the prior periods.
RESULTS OF OPERATIONS
We conduct our business through two distinct reporting segments:
Terminalling services and Fleet services. We have established these
reporting segments as strategic business units to facilitate the
achievement of our long-term objectives, to aid in resource
allocation decisions and to assess operational
performance.
The following table summarizes our operating results by business
segment and corporate charges for each of the years
indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, |
|
2022 |
|
2021
(1)
|
|
2020
(1)
|
|
(in thousands) |
|
Operating income (loss) |
|
|
|
|
|
|
Terminalling services |
$ |
(44,236) |
|
|
$ |
37,846 |
|
|
$ |
5,926 |
|
|
Fleet services |
662 |
|
|
597 |
|
|
73 |
|
|
Corporate and other |
(16,111) |
|
|
(12,558) |
|
|
(11,611) |
|
|
Total operating income (loss) |
(59,685) |
|
|
25,885 |
|
|
(5,612) |
|
|
Interest expense |
10,670 |
|
|
6,990 |
|
|
10,088 |
|
|
Loss (gain) associated with derivative instruments |
(12,327) |
|
|
(4,129) |
|
|
3,896 |
|
|
Foreign currency transaction loss (gain) |
2,055 |
|
|
(707) |
|
|
170 |
|
|
Other income, net |
(90) |
|
|
(31) |
|
|
(793) |
|
|
Provision for income taxes |
1,293 |
|
|
933 |
|
|
337 |
|
|
Net income (loss) |
$ |
(61,286) |
|
|
$ |
22,829 |
|
|
$ |
(19,310) |
|
(1) As
discussed in
Item 8. Financial Statements and Supplementary
Data,
Note .2
Summary of Significant Accounting Policies
of this Annual Report, our consolidated financial statements have
been retrospectively recast to include the pre-acquisition results
of the Hardisty South Terminal, which we acquired effective
April 1, 2022, because the transaction was between
entities under common control.
Summary Analysis of Operating Results
Year ended December 31, 2022 compared to the year ended
December 31, 2021
Changes in our operating results for the year ended
December 31, 2022, as compared with our operating results
for the year ended December 31, 2021, were primarily
driven by:
•activities
associated with our Terminalling services business
including:
–higher
revenue recognized in June 2021 due to early contract cancellation
payment for existing multi-year take-or-pay contract at the
Hardisty South Terminal, with no similar occurrence in
2022;
–lower
revenues at our combined Hardisty Terminal due to a reduction in
contracted capacity at both our legacy Hardisty and Hardisty South
terminals that was effective July 1, 2022;
–lower
revenue at our Stroud Terminal associated with a decrease in
contracted volume commitments at the terminal that became effective
August 2021 and the conclusion of the sole customer contract
effective July 1, 2022, as discussed in more detail below,
partially offset by recognizing previously deferred revenue in 2022
associated with the make-up right options we granted to our
customers with no similar occurrence in 2021;
–higher
revenue at our West Colton Terminal due to the commencement of the
renewable diesel contract that occurred in December
2021;
–increase
in operating costs resulting from a significant non-cash impairment
of intangible and long-lived assets associated with our Casper
Terminal recognized in the third quarter of 2022 due to recurring
periods where cash flow projections were not met due to adverse
market conditions, as discussed in detail below;
–lower
pipeline fee expenses resulting from lower revenues at the Hardisty
and Hardisty South terminals as previously discussed;
–lower
selling, general and administrative expenses at the Hardisty South
Terminal associated with lower service fees that were paid to our
Sponsor for the periods prior to our acquisition of the assets, as
discussed in more detail below; and
–lower
depreciation and amortization costs associated with the decrease in
the carrying value of our intangible assets coupled with a decrease
in terminal assets due to the impairment at our Casper Terminal as
discussed above.
•higher
gains on our interest rate derivatives that included cash proceeds
from the settlement of our interest rate derivative that occurred
in July and October of 2022, partially offset by a non-cash loss as
compared to 2021;
•higher
corporate selling, general and administrative expense due to costs
incurred during 2022 associated with our acquisition of the
Hardisty South Terminal, which was completed in April 2022;
and
•an
increase in corporate interest expense primarily due to higher
interest rates coupled with an increase in average amounts
outstanding on our Credit Agreement.
A more comprehensive discussion regarding our results of operations
and financial condition for the year ended
December 31, 2022 compared to the year ended
December 31, 2021 is presented below. A discussion
regarding our financial condition and results of operation for the
year ended December 31, 2021 as compared with the year
ended December 31, 2020 for our Fleet Segment and our
Corporate results can be found under
Item 7
in our Annual Report on Form 10-K for the year ended
December 31, 2021, filed with the SEC on March 3, 2022,
which is available free of charge on the SEC’s website at
www.sec.gov
and on our website at
www.usdpartners.com.
Due to the aforementioned acquisition of the Hardisty South
Terminal and the associated retrospective recast of our prior year
financial results, a discussion regarding our financial condition
and results of operation for the year ended
December 31, 2021 as compared with the year ended
December 31, 2020 for our Terminalling Services Segment
has been updated and is provided below.
RESULTS OF OPERATIONS - BY SEGMENT
TERMINALLING SERVICES
The following table sets forth the operating results of our
Terminalling services business and the approximate average daily
throughput volumes of our terminals for the periods
indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, |
|
2022 |
|
2021(1)
|
|
2020
(1)
|
|
(in thousands, except Bpd)
|
|
Revenues |
|
|
|
|
|
|
Terminalling services |
$ |
107,075 |
|
|
$ |
198,933 |
|
|
$ |
164,072 |
|
|
|
|
|
|
|
|
Freight and other reimbursables |
557 |
|
|
542 |
|
|
795 |
|
|
Total revenues |
107,632 |
|
|
199,475 |
|
|
164,867 |
|
|
Operating costs |
|
|
|
|
|
|
Subcontracted rail services |
13,583 |
|
|
17,828 |
|
|
14,539 |
|
|
Pipeline fees |
28,084 |
|
|
54,248 |
|
|
42,869 |
|
|
Freight and other reimbursables |
557 |
|
|
542 |
|
|
795 |
|
|
Operating and maintenance |
8,830 |
|
|
8,006 |
|
|
8,789 |
|
|
Selling, general and administrative |
9,559 |
|
|
57,838 |
|
|
35,880 |
|
|
Impairment of intangible and long-lived assets |
71,612 |
|
|
— |
|
|
— |
|
|
Goodwill impairment loss |
— |
|
|
— |
|
|
33,589 |
|
|
Depreciation and amortization |
19,643 |
|
|
23,167 |
|
|
22,480 |
|
|
Total operating costs |
151,868 |
|
|
161,629 |
|
|
158,941 |
|
|
Operating income (loss) |
(44,236) |
|
|
37,846 |
|
|
5,926 |
|
|
Interest expense |
124 |
|
|
499 |
|
|
1,156 |
|
|
|
|
|
|
|
|
Foreign currency transaction loss (gain) |
1,916 |
|
|
(730) |
|
|
91 |
|
|
Other income, net |
(78) |
|
|
(29) |
|
|
(781) |
|
|
Provision for income taxes |
1,265 |
|
|
862 |
|
|
831 |
|
|
Net income (loss) |
$ |
(47,463) |
|
|
$ |
37,244 |
|
|
$ |
4,629 |
|
|
Average daily terminal throughput (Bpd) |
75,706 |
|
|
114,963 |
|
|
85,300 |
|
(1) As
discussed in
Item 8. Financial Statements and Supplementary
Data,
Note 2.
Summary of Significant Accounting Policies
of this Annual Report, our consolidated financial statements have
been retrospectively recast to include the pre-acquisition results
of the Hardisty South Terminal Acquisition, which we acquired
effective April 1, 2022, because the transaction was
between entities under common control.
Year ended December 31, 2022 compared to the year ended
December 31, 2021
Terminalling Services Revenue
Revenue generated by our Terminalling services segment decreased
$91.8 million to $107.6 million for the year ended
December 31, 2022, as compared with the year ended
December 31, 2021. This decrease was primarily due to the
Hardisty South Terminal receiving a customer contract cancellation
payment in the second quarter of 2021, as discussed above in
Factors
Affecting the Comparability of Our Financial Results
with no similar occurrence during 2022. Additionally, our combined
Hardisty Terminal revenues were also lower due to a reduction in
contracted capacity at both our legacy Hardisty and Hardisty South
terminals effective July 1, 2022, as discussed above in
General
Trends and Outlook.
Revenues were also lower at our Hardisty Terminal due to an
unfavorable variance in the Canadian exchange rate on our
Canadian-dollar denominated contracts during 2022 as compared to
2021, discussed in more detail below. In addition, we had lower
revenues at our Stroud Terminal due to the decrease in contracted
volume commitments that became effective in August 2021 and the
conclusion of that sole customer
contract in June 2022, as discussed above in
Factors
Affecting the Comparability of our Financial
Results.
Partially offsetting this decrease in revenues at our Stroud
Terminal was the recognition of previously deferred revenue in the
current year associated with the make-up right options we granted
to our customers with no similar occurrence in 2021. At our Casper
Terminal, we had a decrease in revenues due to lower storage
revenues at our Casper Terminal in the current period as compared
to the prior year period due to the conclusion of one of our
customer contracts that occurred in September 2021 coupled with
reduced throughput as discussed below. Partially offsetting the
decreased revenue was higher revenue at our West Colton Terminal
during 2022 due to the commencement of the renewable diesel
contract that occurred in December 2021.
Our average daily terminal throughput decreased 39,257 bpd to
75,706 bpd for the year ended December 31, 2022, as
compared with 114,963 bpd for the year ended
December 31, 2021. Our throughput volumes decreased
primarily due to a decrease in throughput volumes at our Stroud
Terminal resulting from the previously discussed decrease in
contract volume commitments and the conclusion of our sole customer
contract at the terminal effective July 1, 2022, which also lead to
a decrease in volumes at our Hardisty Terminal, as it is the
origination terminal for volumes delivered to our Stroud Terminal.
In addition, our Hardisty Terminal volumes were lower due to a
reduction in contracted capacity at our legacy Hardisty and
Hardisty South terminals effective July 1, 2022, as
discussed above. Throughput volumes at our Casper terminal also
decreased primarily due to current market conditions. Partially
offsetting this decrease was an increase in throughput volumes at
our West Colton Terminal due primarily to the commencement of our
new renewable diesel agreement.
Our terminalling services revenue for the year ended
December 31, 2022, would have been $2.0 million more if
the average exchange rate for the Canadian dollar in relation to
the U.S. dollar for the year ended December 31, 2022, was
the same as the average exchange rate for the year ended
December 31, 2021. The average exchange rate for the
Canadian dollar in relation to the U.S. dollar was 0.7689 for the
year ended December 31, 2022 as compared with 0.7978 for
the year ended December 31, 2021.
Operating Costs
The operating costs of our Terminalling services segment decreased
$9.8 million to $151.9 million for the year ended
December 31, 2022, as compared with the year ended
December 31, 2021. The decrease is primarily attributable
to lower subcontracted rail services costs, pipeline fees,
depreciation and amortization and selling, general and
administrative expenses, partially offset by higher costs
associated with our impairment of intangible and long-lived assets
and higher operating and maintenance expenses for the year ended
December 31, 2022 compared to the year ended
December 31, 2021.
Our terminalling services operating costs for the year ended
December 31, 2022, would have been $1.7 million more
if the average exchange rate for the Canadian dollar in relation to
the U.S. dollar for the year ended December 31, 2022, was
the same as the average exchange rate for the year ended
December 31, 2021.
Subcontracted rail services.
Our costs for subcontracted rail services decreased $4.2 million to
$13.6 million for the year ended December 31, 2022,
as compared with $17.8 million for the year ended
December 31, 2021, primarily due to decreased throughput
at our terminals, 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 and Hardisty South Terminals less direct operating
costs.
Our pipeline fees decreased $26.2 million to $28.1 million for the
year ended December 31, 2022, as compared with the year
ended December 31, 2021, primarily due to lower revenues
at the Hardisty South Terminal coupled with lower revenues at our
legacy Hardisty Terminal as discussed above.
Operating and maintenance.
Operating and maintenance expense increased $0.8 million to $8.8
million for the year ended December 31, 2022, as compared
with $8.0 million for the year ended December 31, 2021.
The increase is primarily due to higher repairs and maintenance
costs at the Hardisty and Hardisty South terminals incurred for
general periodic repairs needed at the terminals coupled with
higher operational supplies, fuel and
utility costs due to increased inflation rates. The increase was
partially offset due to lower utility and supply costs at our
Stroud Terminal associated with lower throughput volumes as
discussed above.
Selling, general and administrative.
Selling, general and administrative expense decreased $48.3 million
to $9.6 million for the year ended December 31, 2022, as
compared with the year ended December 31, 2021. The
decrease is primarily attributable to lower costs at the Hardisty
South Terminal associated with services fees paid to our Sponsor.
Prior to our acquisition of the Hardisty South entities, USD and
the Hardisty South entities entered into a services agreement for
the provision of services related to the management and operation
of transloading assets. Services provided consisted of financial
and administrative, information technology, legal, management,
human resources, and tax, among other services. Upon our
acquisition of the entities effective April 1, 2022, this
services agreement was cancelled and a similar agreement was
established with us. This results in the service fee income being
allocated to us, and therefore offsetting the expense in the
Hardisty South Terminal entity subsequent to the acquisition date
of April 1, 2022. Refer to
Item 8. Financial Statements and Supplementary Data,
Note 13.
Transactions with Related Parties
in this Annual Report for further discussion.
Impairment of intangible and long-lived assets.
In September 2022, we tested the intangible and long-lived assets
associated with our Casper Terminal for impairment due to recurring
periods where cash flow projections were not met due to adverse
market conditions at our Casper Terminal. As a result of our
impairment testing, we recognized an impairment loss on our
intangible and long-lived assets of $71.6 million for the year
ended December 31, 2022. Refer to
Item 8. Financial Statements and Supplementary Data,
Note
8. Property and Equipment
and
Note
10.
Goodwill and Intangibles
in this Annual Report for further discussion.
Depreciation and amortization.
Depreciation and amortization expense decreased $3.5 million to
$19.6 million for the year ended December 31, 2022,
as compared with the year ended December 31, 2021. This
decrease is associated primarily with the decrease in the carrying
value of our intangible assets coupled with a decrease in the
carrying value of the assets at the Casper terminal due to the
impairment that was recognized in September 2022.
Other Expenses (Income)
Interest expense.
Interest expense decreased $0.4 million for the year ended
December 31, 2022 as compared with $0.5 million of
interest expense for the year ended December 31, 2021.
Prior to our acquisition, the Hardisty South entities had a
Construction Loan Agreement as discussed in
Item 8. Financial Statements and Supplementary Data,
Note 11.
Debt
in this Annual Report. As of March 2022, the remaining balance of
the Construction Loan Agreement was transferred by the Hardisty
South entities to a subsidiary of our Sponsor. The decrease in
interest expense associated with the Hardisty South Construction
Loan Agreement is due primarily to a lower balance of debt
outstanding when compared to the prior period
presented.
Year ended December 31, 2021 compared to the year ended
December 31, 2020
Terminalling Services Revenue
Revenue generated by our Terminalling services segment increased
$34.6 million to $199.5 million for the year ended
December 31, 2021, as compared with $164.9 million for
the year ended December 31, 2020. This increase was
primarily due to higher revenues at the Hardisty South and legacy
Hardisty Terminals and our Casper Terminal, partially offset by
lower revenues at our Stroud Terminal. The higher revenues at the
Hardisty South Terminal were primarily associated with a customer
contract cancellation payment received in the second quarter of
2021, as discussed above in
Factors
Affecting the Comparability of Our Financial Results
with no similar occurrence during 2020. At our combined Hardisty
Terminal we also had increased revenues due to a favorable variance
resulting from the Canadian exchange rate on our Canadian-dollar
denominated contracts during 2021 as compared to 2020, discussed in
more detail below, coupled with an increase in rates on certain of
our agreements at our legacy Hardisty Terminal when compared to
2020. Partially offsetting these increases were revenues that were
recognized in 2020 at our legacy Hardisty Terminal that were
previously deferred in the prior year associated with the make-up
right options we granted to customers as these rights were deemed
unlikely to be used in future periods, with no similar recognition
of revenue occurring during 2021. Our Casper Terminal revenues also
increased due to higher throughput volumes at the terminal during
2021 as compared to 2020. The decrease in revenues at our
Stroud
Terminal was primarily due to lower revenues during the second half
of 2021 associated with the existing customer electing to reduce
its contracted volume commitments by one-third of their previous
commitment effective August 2021 as a result of the successful
commencement of the DRU, as discussed above in
Factors
Affecting the Comparability of our Financial
Results.
In addition, we deferred revenue at our Stroud Terminal during the
fourth quarter of 2021 associated with the make-up right options we
grant our customers that were expected to be exercised in 2022.
These decreases in revenues at our Stroud Terminal were partially
offset by higher revenues due to higher rates that are based on
crude oil pricing index differentials.
Our average daily terminal throughput increased 29,663 bpd to
114,963 bpd for the year ended December 31, 2021, as
compared with 85,300 bpd for the year ended
December 31, 2020 due primarily to higher throughput
volumes at our Hardisty, Stroud and Casper terminals. Throughput
volumes at our Hardisty Terminal increased on a year-to-date basis
in 2021 resulting from higher crude oil price levels and a wider
average WCS to WTI pricing spread as compared to the low levels
that existed in 2020 due to the decreased demand that existed
resulting from the impacts of the COVID-19 pandemic. In addition, a
portion of our Hardisty throughput volumes also drives the demand
for deliveries to our Stroud Terminal and its connection to the
Cushing oil hub, and as a result, throughput at our Stroud Terminal
increased during 2021 as compared to 2020. The favorable pricing
environment discussed above also led to the increase in throughput
volumes at our Casper Terminal. Our terminalling services revenues
are recognized based upon the contractual terms set forth in our
agreements that contain primarily “take-or-pay” provisions, where
we are entitled to the payment of minimum monthly commitment fees
from our customers, which are recognized as revenue as we provide
terminalling services. Increases in the average daily terminal