usd partners lp investor presentation · 2019-08-13 · usd partners lp investor presentation citi...
TRANSCRIPT
Delivering Energy Infrastructure Solutions1
USD Partners LP
Investor Presentation
Citi Midstream & Energy Infrastructure Conference
August 2019
Delivering Energy Infrastructure Solutions
Cautionary Statements
This presentation contains forward-looking statements within the meaning of
U.S. federal securities laws, including statements related to USD Partners LP
(“USDP” or the “Partnership”), the results of development and
commercialization efforts by the Partnership and its sponsor, USD Group
LLC (“USDG” or the “Sponsor”), the stability and predictability of the
Partnership’s cash flows, the Partnership’s financial flexibility, the
Partnership’s plans with respect to leverage, the intention of Energy Capital
Partners (“ECP”) to invest in the Sponsor, Canadian oil sands production
growth expectations and sensitivity to price movements, expectations with
respect to end markets for Canadian oil sands production, pipeline capacity
and the timing of completion of pipeline expansion projects, expectations
related to crude oil spreads and their impact on demand for our terminalling
services, expectations with respect to USDP’s and USDG’s ability to
successfully execute on their commercial priorities and growth projects;
expectations with respect to growth and opportunities in the Mexican refined
products market, the ability of the railroads serving our terminals to meet
customer demand, expectations of growth opportunities and growth drivers at
the Partnership’s terminals, and expectations related to the buildout and
commercialization of the Sponsor’s Houston Ship Channel joint venture.
These statements can be identified by the use of forward-looking terminology
including “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue,”
or other similar words. These statements discuss future expectations, contain
projections of results of operations or of financial condition, or state other
“forward-looking” information. These forward-looking statements involve risks
and uncertainties. When considering these forward-looking statements, you
should keep in mind the risk factors and other cautionary statements in this
presentation, which could cause our actual results to differ materially from
those contained in any forward-looking statement.
A forward-looking statement may include a statement of the assumptions or
bases underlying the forward-looking statement. USDP believes that it has
chosen these assumptions or bases in good faith and that they are
reasonable. You are cautioned not to place undue reliance on any forward-
looking statements. Except as required by law, USDP undertakes no
obligation to revise or update any forward-looking statement. You should also
understand that it is not possible to predict or identify all such factors and
should not consider the following list to be a complete statement of all
potential risks and uncertainties:
Changes in general economic conditions; the effects of competition in our
industry, in particular, by pipelines and other terminalling facilities; shut-
downs or cutbacks at upstream production facilities or refineries or other
businesses to which we transport products; the supply of, and demand for,
crude oil and biofuels rail terminalling services; our limited history as a
separate public partnership; the price and availability of debt and equity
financing; our ability to successfully implement our business plan; our ability
to complete growth projects on time and on budget; hazards and operating
risks that may not be fully covered by insurance; disruptions due to
equipment interruption or failure at our facilities or third-party facilities on
which our business is dependent; our ability to successfully identify and
finance acquisitions and other growth opportunities; natural disasters,
weather-related delays, casualty losses and other matters beyond our
control; interest rates; labor relations; large customer defaults; changes in tax
status; changes in laws or regulations to which we are subject, including
compliance with environmental and operational safety regulations that may
increase our costs; the coverage, price and availability of insurance;
disruptions due to equipment interruption or failure at our facilities or third-
party facilities on which our business is dependent; the effects of future
litigation; and the factors discussed in the “Risk Factors” section of the
Partnership’s Annual Report on Form 10-K for the fiscal year ended
December 31, 2018, as updated by the Partnership’s subsequently filed
Quarterly Reports on Form 10-Q, which are available to the public at the U.S.
Securities and Exchange Commission’s website (www.sec.gov) and at the
Partnership’s website (www.usdpartners.com).
DRUBITTM is a trade mark of USDG and its affiliates.
2
Delivering Energy Infrastructure Solutions
Overview of USD Partners LP
NYSE: USDP
3
Delivering Energy Infrastructure Solutions
Adjusted EBITDA driven by take-or-pay contracts¹
A Growth-Oriented Logistics MLP with High-Quality Cash Flows
Formed in 2014 by US Development Group to acquire,
develop and operate midstream infrastructure and
complementary logistics solutions
• Assets primarily focused on the transportation of heavy crude oil
from Western Canada to key demand centers across North America
Substantially all of our operating cash flow is generated
from multi-year, take-or-pay contracts with primarily
investment grade customers
• Including major integrated oil companies, refiners and marketers
Assets provide multi-modal logistics services, including:
• Railcar loading and unloading
• Storage and blending in on-site tanks
• Inbound and outbound pipeline connectivity
• Truck transloading
• Leased railcars and associated fleet services
Units currently offer ~14% yield²
No direct commodity exposure
4
Other Fee-Based
1%
Take-or-Pay Contracts
99%
Primarily large, investment grade customers³
1. Pie chart represents the Partnership’s Terminalling and Fleet Segment Adjusted EBITDA for the six months ended 6/30//2019. Adjusted EBITDA is a non-GAAP measure. For a description of Adjusted EBITDA and a reconciliation to the most comparable measures
calculated in accordance with GAAP, see the Appendix to this presentation.
2. Based on a closing price of $10.75 on 8/12/2019 and second quarter 2019 distribution of $0.3650 per unit ($1.46 per unit annualized).
3. Includes selected terminal customers.
Delivering Energy Infrastructure Solutions
Strategically Positioned Network Supports Significant Growth Opportunities
5
Legend:
= USDP crude terminals
= Select USDG projects/assets
Hardisty Origination
Terminal
Stroud Destination
Terminal
Texas Deepwater
and Deer Park Rail
Terminal
Cushing
Oil Sands
A competitive network with full-suite logistics solutions that meet customer needs in a dynamic energy market
Casper Origination
Terminal
Strategically integrated network of terminal
assets provides valuable market access and
optionality
• Comprehensive solution for heavy crude oil from origin to destination
• Potential for in-network flexibility
• Advantaged rates
Network drives additional commercial
opportunities supporting sustainability and
future growth
• Hardisty Terminal is the only unit-train capable facility directly connected to Canada’s largest crude oil hub
• Inception to date, the Partnership’s Hardisty rail terminal has loaded over 1,000 unit trains with approximately 60 million barrels of crude oil
• Pipeline-to-rail delivery from Casper to the West and Gulf Coasts
• Rail-to-pipeline access to Gulf Coast via Hardisty to Stroud
• Stroud terminal strategically located as the only unit-train facility connected to Cushing storage hub
• Texas Deepwater development integrates substantial storage, blending and distribution infrastructure, including ability to export to international markets
• Developing a network of refined products destination terminals across Mexico to support rail advantaged markets
Crude Oil, NGLs
and Refined
Products
Permian
Basin
Delivering Energy Infrastructure Solutions
Market Driving Significant Re-Contracting and Expansion Momentum for USDP
New oil sands production capacity is brought online and ramps up over 12 to 18 months
Apportionment on export pipelines increases until physical operating capacity is met
Western Canadian crude oil price discount deepens relative to global prices
Physical barrels seek alternative transportation means, including rail solutions
Point of re-contracting across crude terminal network with potential for expansion
6
Delivering Energy Infrastructure Solutions
Terminals Underpinned by Multi-Year Contracts with High-Quality Customers
7
Customer Type Credit Rating Investment Grade?
% of Terminal Capacity Contracted
as of July 1, 2019
Contract Term
Through Date
Average Customer Dividend
Yield
Hardisty Terminal – USD Partners LP (63% of Adj. EBITDA) (1)
Integrated A-/ Baa1 23% Jun-2022
Integrated BBB / Ba1 Split 25% Jun-2023
Marketer BBB- / Ba2 Split 17% Jun-2023
Producer2 A / A3 25% Jun-2020
Producer A / A3 8% Jan-2020
Producer3 A / A3 2% Jun-2024
Total Capacity Contracted 100%
Hardisty South – USD Group LLC
Refiner4 BB/Ba3 50% Dec-2023
Producer4 BBB-/Baa3 17% Jun-2022
Government Agent4 A+/Aa1 - Dec-2022
Producer3 A / A3 27% Jun-2024
Total Capacity Contracted 94%
Stroud Terminal (22% of Adj. EBITDA) (1)
Producer A / A3 52% Jun-2020
Producer5 A / A3 10% Jan-2020
Producer5 A / A3 31% Jun-2024
Total Capacity Contracted 93%
Casper Terminal (14% of Adj. EBITDA) (1)
Refiner BBB / Baa2 10% Aug-2019
Integrated AA+ / Aaa Variable Sept-2021
Producer Not Rated Variable Dec-2019
USD has been successful in re-contracting its existing customers as well as signing new agreements with new customers; the Partnership has replaced
approximately 83% of the Hardisty terminal’s current cash flows, on an annualized basis, over the next three years starting in July 2019
3.5%
2.6%
2.2%
4.4%
Source: Standard & Poor’s, Moody’s, Yahoo Finance (as of 8/8/2019)
Note: Certain customers are wholly-owned subsidiaries of the entities whose credit rating and yield are shown above. Marketers include midstream companies with marketing operations. Ratings of Baa3 / BBB- or better are considered investment grade.
1. Based on Partnership’s Terminalling and Fleet Segment Adjusted EBITDA for the six months ended June 30, 2019. Remaining 1% of Adjusted EBITDA is generated by the Partnership’s West Colton facility and railcar business.
2. Producer’s capacity at Hardisty via USD Marketing’s contracted capacity with the Partnership.
3. In July 2019, the Partnership entered into a renewal and extension that covers approximately 15% of the capacity at the Partnership’s Hardisty terminal. The Partnership expects to service the contract using the limited remaining capacity available at the Hardisty terminal, as well as by subletting excess capacity from USDG’s
Hardisty South Expansion.
4. USD Partners does not derive any cash flows from the agreements listed herein associated with USD Group LLC’s Hardisty South expansion. The capacity of the Hardisty South expansion will increase in January 2020 from current levels upon the commencement of the contract with the Government Agent, noted above.
5. Producer’s capacity at Stroud via USD Marketing, a wholly-owned subsidiary of USD Group LLC, pursuant to the Marketing Services Agreement established with the Partnership entered into at the time of the Stroud acquisition. The agreement that expires June 2024 is subject to early termination upon satisfaction of certain
conditions.
Contracted at USD Group LLC.
Delivering Energy Infrastructure Solutions
Commercial Priorities and Strategic Organic Growth
8
Pipeline takeaway constraints have created significant demand for the Partnership’s strategically positioned
network of rail terminal assets
Commercial Priorities
• Complete renewal and extension of current Hardisty and Stroud contracts with new and existing
customers
• Fully commercialize the Casper Terminal
Potential Organic Growth Projects at the Partnership
• Pursue “Hub Strategy” at Casper Terminal through potential additional connections to other
downstream pipelines in the area
• Expand capacity at the Hardisty and Stroud terminals to support growing customer demand
• Develop a network of advantaged products destination terminals in Central Mexico
• Develop liquids connectivity options at Texas Deepwater property located at the Houston Ship
Channel
Potential Organic Growth Projects at the Sponsor Level
In Progress
In Progress
In Progress
In Progress
In Progress
In Progress
Delivering Energy Infrastructure Solutions
Casper Terminal: Creating Long-term Value
9
~$15 million of capex to build the pipeline connection; expected to be
completed by November 2019• The connection to a nearby terminal with significant pipeline
connectivity will enhance the utility of the Casper Terminal
• Connection will provide outbound access to:
– PADD II refineries
– U.S. Gulf coast
– Salt Lake City
– Rocky Mountain Pipeline
– Western corridor through Plains terminal
• Underwritten by three-year take-or-pay agreement with new
customer for tank fees, standby fee for rail loading and a per
barrel fee for rail loading, effective as of September 2018
• Several customers indicating interest in the Casper Terminal
once connection is in place
Future Growth
• Enbridge recently announced an open season to increase
the capacity of its Express pipeline by up to 50 kbpd with the
use of Drag Reducing Agent (DRA) and the addition of pump
stations. The open season is expected to conclude on
August 23, 2019. (1)
– This project could increase crude-by-rail volumes out of the
Casper Terminal as the Partnership believes pipelines in the
region are already currently being utilized at or near full
capacity
Connection Enhances Value Through Increased Access
Wyoming
Sour
Casper
Terminal
Hardisty
(WCS)
Nearby
Terminal
Salt
Lake
City
Wood
River +
PADD II
Refineries
Pipeline connection
under construction
Guernsey
The announced pipeline connection allows Casper to manage and profit from volatility at both origin and destination
1. Source: Public Company website, Press Releases
Delivering Energy Infrastructure Solutions
Financial Flexibility to Execute on Growth Opportunities
~$175 million of available liquidity, including:
• ~$7 million of unrestricted cash and cash equivalents
• ~$168 million of revolver capacity with additional $100 million
accordion available on senior secured credit facility1
Credit Facility Refinancing
• On November 2, 2018, the senior secured credit facility was amended
and restated
• The new facility is a four-year committed facility that matures in
November 2022, with a borrowing capacity of $385 million; includes a
reduction of 25 basis points to the applicable margin the Partnership is
charged on LIBOR-based borrowings
Conservative leverage profile
• ~3.8x Net Debt / LTM Adjusted EBITDA²
• Expect to de-lever in 2020 with projected excess cash flow generated
from future growth projects
Well-capitalized sponsor with backing from Energy Capital
Partners
• ECP indicated an intention to invest over $1.0 billion of additional
equity capital in our sponsor³
– Energy infrastructure-focused private equity fund with over $19
billion of capital commitments
– Extensive MLP and midstream experience
10
Leverage and Liquidity (in millions, as of 6/30/2019)
Note: Adjusted EBITDA is a non-GAAP measure. For a description of Adjusted EBITDA and a reconciliation to the most comparable measures calculated in accordance with GAAP, see the Appendix to this presentation.
1. Accordion subject to receiving increased commitments from lenders or other financial institutions and satisfaction of certain conditions.
2. Based on historical Adjusted EBITDA for the twelve month period ended 6/30/2019 and pro forma adjustments.
3. Subject to market and other conditions.
Unrestricted cash and cash equivalents $7
Revolving credit facility capacity $385
Less: Revolver borrowings ($217)
Available liquidity $175
Revolver borrowings $217
Total Debt $217
Net Debt $210
Total Debt / LTM Adjusted EBITDA² 3.9x
Net Debt / LTM Adjusted EBITDA² 3.8x
Delivering Energy Infrastructure Solutions11
Western Canadian Market
Update and Opportunities
Delivering Energy Infrastructure Solutions
Oil sands projects require substantial up-front capital and produce for multiple decades with relatively low decline,
creating a more visible production outlook that is less sensitive to commodity prices than U.S. shale
Western Canadian Oil Sands U.S. Shale
Production Type Heavy crude oil Crude oil, natural gas and associated liquids
Typical API Gravity
of Crude Oil
Raw Bitumen: Less than 10
Diluted Bitumen: ~20 to 22
Upgraded Bitumen / Synthetic Crude: ~31 to 33
~35 to 50+
Capital Profile Significant up-front capital Ratable
Asset Life 30+ years Various
Decline Profile Low High initial declines
Sensitivity to Spot Prices Low High
GatheringSubstantially all production is gathered into two
storage hubs, Hardisty and Edmonton
Local gathering systems are generally well-
connected to refining centers via pipelines
Infrastructure Constrained Developed / Region-specific
Western Canadian Oil Sands are Unlike U.S. Shale
12
Delivering Energy Infrastructure Solutions
WCS spreads
reach levels that
incentivize the
utilization of rail
takeaway capacity
The Macro Story We Have Long-Expected is Here
Current Heavy Canadian Sour market dynamics tell the following story…
Production growth
strains available
takeaway capacity;
increases pipeline
apportionment
Stranded heavy
barrels pushed
into storage;
increases
inventory levels
Change
in Price
Change
in Price
Change
in Price
…and key indicators suggest WCS will be discounted for the foreseeable future,
resulting in a continued escalation of rail activity
Change
in Price
13
Delivering Energy Infrastructure Solutions
Growing Western Canadian Crude Oil Supply Requires Additional Takeaway
14
Source: Canadian Association of Petroleum Producers (June 2019)
CAPP’s Chart Notes: Capacity shown can be reduced by any extraordinary and temporary operating and physical constraints.
Relative to 2018 levels, CAPP recently forecasted supply growth of ~350 mbpd by 2020 and ~1.2 Mmbpd by 2030,
well in excess of existing pipeline takeaway capacity
2019 Western Canadian
supply forecastLong-term
opportunity
for existing
and potential
new rail
capacity
Delivering Energy Infrastructure Solutions
Opportunity to Support Substantial and Visible Oil Sands Production Growth
15
Customer Project Crude Type¹
Barrels Available for Takeaway (bpd)
(Bitumen+Diluent)
Anticipated
Start-Up Date
Hardisty
(Direct / Indirect)² Current Customer?
Producer 1 Project A Dilbit 286,000 Online / Ramping Indirect
Producer 2 Project B Dilbit 78,000 Online / Ramping Indirect
Producer 3 Project C Synbit/Dilbit 72,500 Online / Ramping Indirect Yes
Producer 4 Project C Synbit/Dilbit 72,500 Online / Ramping Indirect
Producer 5 Project D Dilbit 225,000 Online / Ramping Indirect Yes
Producer 5 Project E Dilbit 262,500 Online / Ramping Direct Yes
Producer 6 Project F Synbit 70,000 Online / Ramping Indirect
Producer 7 Project G Dilbit 39,000 Online / Ramping Indirect
Producer 8 Project H Syncrude 80,000 Online / Ramping Indirect
Producer 9 Project I Dilbit 127,025 Online / Ramping Direct Yes
Producer 4 Project I Dilbit 62,365 Online / Ramping Direct
Producer 10 Project I Dilbit 50,010 Online / Ramping Direct
Producer 11 Project J Dilbit 17,000 Online / Ramping Indirect
Producer 5 Project E Dilbit 65,000 Q2 2019 Direct Yes
Producer 2 Project K Dilbit 3,900 H2 2019 Indirect
Producer 3 Project L Dilbit 46,714 Q3 2019 Indirect Yes
Producer 2 Project M Dilbit 14,286 Q4 2019 Indirect
Producer 1 Project N Dilbit 28,571 Q4 2019 Indirect
Producer 2 Project O Dilbit 14,286 Q1 2020 Indirect
Producer 8 Project P Dilbit 52,000 Q1 2020 Indirect
Producer 8 Project Q Dilbit 14,286 Q1 2020 Direct
Producer 5 Project R Dilbit 50,000 Q2 2020 Indirect Yes
Producer 8 Project Q Dilbit 22,857 Q1 – Q3 2020 Direct
Producer 12 Project S Dilbit 37,143 Q3 2020 Direct
Producer 2 Project T Dilbit 14,286 Q4 2020 Indirect
Producer 13 Project U Dilbit 18,571 Q4 2020 Direct
Producer 5 Project V Dilbit 65,000 2023 Indirect Yes
Producer 8 Project W Syncrude 45,000 Q2 2021 Indirect
Producer 8 Project W Syncrude 57,143 Q2 2021 Indirect
Producer 2 Project X Dilbit 14,286 2H 2021 Indirect
Producer 5 Project Y Dilbit 40,000 2021 – 2022 Indirect Yes
Producer 2 Project K Dilbit 8,571 2021 Indirect
Producer 13 Project Z Dilbit 141,429 2020 – 2022 Direct
Producer 2 Project AA Dilbit 14,286 2022 Indirect
Producer 14 Project AB Syncrude 77,500 TBD Indirect
Producer 1 Project AC Dilbit 150,000 2023 TBD
Producer 3 Project AD Dilbit 64,500 TBD Indirect Yes
Various Debottleneck Various 75,000 2019-2020 Both
Total Nameplate Capacity 2,576,514
Estimated Volumes Already Online from Ramp-Up (1,394,231)
Expected Production Growth through 2022 1,182,283
Note: Based on customer announcements and internal analysis. Actual amounts and the timing and destination of additional barrels may differ from the above estimates. Oil sands projects typically require a 12-18 month ramp up period to reach full capacity. Current customers shaded in blue.
1. Synthetic crude oil is a light sweet grade produced from processing bitumen in an upgrader facility used in connection with certain oil sands production. ‘Synbit‘ typically includes a 50/50 mix of bitumen and synthetic crude oil. ‘Dilbit’ typically includes a 70/30 mix of bitumen and diluent, such
as natural gas liquids and condensates.
2. ‘Direct’ indicates barrels that are delivered directly to Hardisty; ‘Indirect’ denotes barrels that arrive at Hardisty via Edmonton on Enbridge’s Oil Sands System.
USDP’s terminal network positioned to provide both volume and quality solutions for new and existing customers
Delivering Energy Infrastructure Solutions
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
50%
55%
Mainline Trans Mountain
High Apportionment as Production Exceeds Available Pipeline Capacity
16
Source: Argus (as of 8/7/2019)
Export pipelines from Western Canada to the U.S. cannot accommodate the volume of barrels requested or “nominated” for
shipment by customers, causing apportionment to rise
Apportionment represents the percentage of barrels nominated that will not be allocated space on upcoming shipments
Published Apportionment on Major Export Pipelines
Pip
elin
e
Apport
ionm
ent %
Apportionment
levels have
remained high
Delivering Energy Infrastructure Solutions
0%
10%
20%
30%
40%
50%
60%
70%
0
10,000,000
20,000,000
30,000,000
40,000,000
50,000,000
60,000,000
70,000,000
(barr
els
)
Key Western Canadian Hubs and Storage Terminals
Total Capacity Actual Volume Utilization %
Crude Oil Storage Levels Remain Elevated
17
Source: Genscape (latest as of 8/7/2019)
New oil sands production and pipeline outages drive inventories higher as barrels that cannot be shipped are stored
Syncrude
upgrader
outage
Fort McMurray
wildfires
% U
tiliza
tion
Alberta
Production
Curtailment
Commenced
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Dis
count
to W
TI ($
per
barr
el)
USGC Maya spot price less est. pipeline costs from Hardisty to USGC
USGC Maya spot price less est. rail costs from Hardisty to USGC
WCS-WTI Spread
Rail and terminal providers are mobilizing to meet surge in demand as customers are highly-motivated to evacuate
additional barrels via established rail takeaway capacity
Canadian Crude Oil has Discounted Significantly as a Function of Takeaway Constraints
18
Source: Argus Crude and internal estimates for transportation and quality cost adjustments (pricing as of 8/7/2019)
As pipeline takeaway
capacity remains constrained
relative to supply, prices will
discount to beyond rail parity
Western Canadian Select vs. Mexican Maya: A Heavy Alternative Feedstock in the U.S. Gulf Coast
Spreads narrowed in
early 2019 resulting
from the Alberta
production curtailment
Delivering Energy Infrastructure Solutions
$(45.00)
$(43.00)
$(41.00)
$(39.00)
$(37.00)
$(35.00)
$(33.00)
$(31.00)
$(29.00)
$(27.00)
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$(3.00)
$(1.00)
$1.00
$3.00
$5.00
$7.00
WCS Hardisty and Houston Differential to WTI
WCS Hardisty to WTI WCS Houston to WTI
Forward WCS Prices Indicate Ongoing Takeaway Constraints – This Drives Expectations
for Contract Renewals and Extensions as well as Potential Growth Opportunities
19
Forward curve supports significant potential margin at rates equal or greater than existing contracted rates,
incentivizing customers to pursue multi-year term agreements
Source: WCS Houston: Argus/Calrock as of 8/7/2019; June to December 2019 data based on Calrock forward; Spread data only available through December 2019.
WCS Hardisty: Argus/Bloomberg as of 8/7/2019
The difference between
the spreads provides
incentive to move
volumes by rail to the
U.S. Gulf Coast
WC
S to W
TI D
iffe
rential
Alberta Government
production
curtailment impact
WCS/WTI spread
expected to widen
beyond rail parity as
pipeline takeaway
capacity remains
constrained
Delivering Energy Infrastructure Solutions
Alberta Production Curtailment Overview and Implications
ACTION
• In early December 2018, the Alberta Government announced it would curtail production by 325 kbpd of (crude/bitumen), effective January 1, 2019
OBJECTIVE
• The stated objective of the cuts is to reduce storage until it reaches 16MMbbls (currently at 27.1 MMbbls); once this target is achieved, the curtailment will be reduced to 95kbpd (oil) / 117kbpd (bitumen)
20
CONSEQUENCES
• The previous Alberta Government increased production by 150k bpd as of June 2019, and put plans in place to reduce curtailment another 25k bbls in both August and September 2019 due to draw on inventories.
• The new Alberta government are continuing to reduce curtailment
• Crude by rail will be required to achieve storage objective and will continue to be utilized after storage is cleared and production increases following curtailment repeal and new production coming online in 2019
WCS 2019 Market Implications
1. Production cuts stabilize the differentials in near term, improving balance sheet and cash flow of key Canadian customers and ensures long term Alberta production growth
2. Demand for rail is expected to continue to be greater than supply during curtailment period. In the coming months, available tier I rail capacity will be fully utilized to achieve targeted production and inventory levels (due to a wider WCS / WTI spread)
3. The Alberta Government (APMC) committed to take 120kbpd of rail capacity out of Alberta starting in 2019, effectively endorsing rail takeaway as a solution for Canadian exports
• In June 2019, the Alberta Government announced that they have engaged CIBC Capital Markets to help oversee the divestment of the crude-by-rail program and its transition to the private sector
• The Alberta Government has stated that it expects the process to be completed by the Fall of 2019
Source: Alberta Government Website; publicly-available press releases; Genscape storage data as of 8/7/2019.
Alberta Production Curtailment
Month Curtailment Level Production Level
January 2019 325,000 bpd 3.56 MMBD
February 2019 250,000 bpd 3.63 MMBD
March 2019 250,000 bpd 3.63 MMBD
April 2019 225,000 bpd 3.66 MMBD
May 2019 200,000 bpd 3.68 MMBD
June 2019 175,000 bpd 3.71 MMBD
July 2019 175,000 bpd 3.71 MMBD
August 2019 150,000 bpd 3.74 MMBD
September 2019 125,000 bpd 3.76 MMBD
Delivering Energy Infrastructure Solutions
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TI ($
per
barr
el)
USGC Maya spot price less est. pipeline costs from Hardisty toUSGCUSGC Maya spot price less est. rail costs from Hardisty toUSGCWCS-WTI Spread
Illustrative Value Preservation
Rail Takeaway Solutions Provide Significant Potential Value
• Smaller portion of all-in transportation costs are fixed
• Less capital intensive than pipeline alternatives
• Readily scalable
Low Cost / Capital
Efficiency
• Faster physical delivery than pipelines (<10 days vs. 30+ days from Hardisty to the Gulf Coast)
• Flexibility to choose destination market once train is loaded
Greater Optionality
• Quality control vs. potential quality degradation in pipelines
• Ability to improve margins on specialty barrels
Higher Degree of
Quality Control
21
Rail provides flexible market access at a relatively low fixed cost, enabling a portfolio approach to transportation
Western Canadian Select vs. Mexican Maya
Source: Argus Crude and internal estimates for transportation and quality cost adjustments (pricing as of 8/7/2019)
Rail Profitability Analysis For Prior Cycle:
Illustrative 30,000 BPD
commitment via rail for 24
months
21,900,000 Bbls
Average estimated margin
for railed barrels ($ / Bbl) (1)
$13.13
Total value preserved $287,550,000
1. For period between January 2012 through December 2013.
Benefits of Rail
Delivering Energy Infrastructure Solutions
Uncertain Timing and Quantity of Additional Export Pipeline Capacity
22
Expected timelines have shifted meaningfully over time for the three remaining export pipeline developments
CAPP’s Estimated In-Service Date
Proposed Pipeline
Capacity
(mbpd) 2013 2014 2015 2016 2017 2018 2019
Mainline Line 3 Replacement 370 H2 2017 2019 2019 2019 2020
Trans Mountain Expansion 590 Q4 2017 Q4 2017 Q4 2018 Late 2019 End 2019 Dec 2020+ 2020+
Keystone XL 830 2015 2017 2018 Denied 2020+ 2020+ 2020+
Energy East (Canceled) 1,100 Q4 2017 Q4 2018 2020 Late 2020 2021+ Not included Not included
Northern Gateway (Rejected) 525 Q4 2017 Q3 2018 2019 Uncertain Not included Not included Not included
Source: Canadian Association of Petroleum Producers, Bloomberg, government websites, corporate press releases and earnings call transcripts
• The Minnesota Court of Appeals ruled in June
2019 that state regulators failed to consider the
impact of an oil spill in Lake Superior’s
watershed when they approved an
environmental review for Enbridge’s Line 3
project. Enbridge also still needs certain state
permits and approval from the Army Corps of
Engineers before it can begin Line 3
construction.
• The project, which was initially excepted to be in
service before the end of 2019, has been
delayed until the second half of 2020.
Major energy projects still face multiple headwinds
• Regulatory landscape in flux as Canada introduced new legislation to overhaul the primary federal energy regulator and the environmental assessment
process for major projects, as well as enhance environmental protections for fish and navigable waters
• Well-organized opposition from environmental groups, general public and segments of local governments adds to timing uncertainty
Enbridge Line 3
• The Canadian Federal Government purchased
the Trans Mountain pipeline expansion from
Kinder Morgan in mid-2018.
• The NEB submitted its reconsideration report to
the governor-in-council in February 2019. The
report has 156 conditions and 16
recommendations to the Government. The
Government officially approved expansion of
Trans Mountain in June 2019.
Trans Mountain
• Appeals court has lifted an injunction that
blocked construction of the pipeline but TC
announced that they officially have missed their
2019 construction season due to the court
delays
• Order issued by a Montana Judge barring pre-
construction activities was dissolved in July
2019. This is only a partial victory for the
pipeline as the project still faces a legal
challenge in Nebraska, with a decision being
due sometime in the third quarter of 2019.
Keystone XL
Delivering Energy Infrastructure Solutions23
Asset Overview:
USD Partners’ Crude Terminals
Delivering Energy Infrastructure Solutions
Aerial view of Casper terminal
Strategically Positioned Terminals Levered to Growing Canadian Production
24
Aerial view of Hardisty terminal
Hardisty terminal’s scalable design
Our Hardisty terminal is the only unit-train capable facility directly connected to
Hardisty, Canada’s largest crude oil storage and export hub
• Capacity to load up to two 120-railcar unit trains or ~150,000 barrels per day¹
• The Partnership’s sponsor completed an expansion project in January 2019, referred to
as Hardisty South, that added incremental capacity of one 120-railcar unit train or
~75,000 barrels per day2
• Located on Canadian Pacific’s North Main Line, which offers connectivity to key refining
markets across North America
• Exclusive unit-train loading facility for Gibson Energy, who has ~10 million of nearly 30
million barrels of storage at the Hardisty hub3
– Gibson is constructing another 2.0 million barrels of storage expected in Q4 2019,
and an additional 0.5 million barrels of storage expected in Q4 2020
• Multi-year take-or-pay contracts with producers, refiners and marketers
Our Casper terminal is the only unit-train capable facility directly connected
to the Express Pipeline, which runs from the Hardisty hub to Casper,
Wyoming
• Capacity to load over 100,000 bpd, including both unit-train and manifest shipments,
with approximately 900,000 barrels of on-site storage
• Located on the BNSF Main Line, maximizing access to customer-preferred destinations
on the West and Gulf coasts
• Includes take-or-pay contracts and recent spot activity with large refiner and producer
customers
• Flexibility to receive various grades of crude oil from truck unloading station, as well as
an inbound connection from the Platte terminal
• Expansion project underway to construct an outbound pipeline connection to a nearby
terminal that is expected to be completed in November 2019
1. Based on two 120-railcar unit trains comprised of 28,371 gallon (~676 barrels) railcars being loaded at 92% 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.
2. USD Partners does not derive any cash flows associated with USD Group LLC’s Hardisty South expansion.
3. Source: Gibson Energy public filings and Genscape.
Delivering Energy Infrastructure Solutions
Stroud Destination Terminal Connects Western Canadian Crude to Cushing
25
Terminal Overview
• 76-acre terminal with ~50,000 barrels per day¹ of railcar unloading
capacity, two on-site tanks with 140,000 barrels of total capacity
and one truck bay
• Served by the BNSF and Union Pacific railways
• Includes 17-mile pipeline connecting the Stroud terminal to the
Cushing hub
• 300,000 barrels of segregated working storage capacity at Cushing
leased to facilitate outbound shipments
• Initial multi-year take-or-pay agreement with investment-grade
rated, multi-national energy company commenced in October 2017
• Stroud customer secured the remaining available capacity at the
Stroud terminal from USD Marketing LLC for periods ending in
January 2020 and June 20242 (most recent renewal) Aerial view of Stroud terminal
Stroud Terminal: Crude Destination
Railcar unloading Tankage
Pipeline to
USDP-dedicated
tank at Cushing
Cushing Hub: Market Optionality
• Sell at Cushing
• Sell at Gulf
Coast via
downstream
pipelines
Hardisty Terminal:
Crude Origination
Railcar loading
The Only Unit Train Facility Directly Connected to the Cushing Storage Hub
1. Based on pumping capacity constraints on the pipeline utilized to move crude oil between the Stroud terminal tanks and third party storage tanks at Cushing. With pump modifications, the terminal could unload up to ~64,000 bpd
based on one 104-railcar unit train of 28,371 gallon (~676 barrels) railcars at 92% of volumetric capacity per day. Actual amount of crude oil unloading 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.
2. Pursuant to the Marketing Services Agreement established with the Partnership at the time of the Stroud acquisition. The agreement that expires June 2024 is subject to early termination upon satisfaction of certain conditions.
Delivering Energy Infrastructure Solutions26
Selected Sponsor Development
Activities
Delivering Energy Infrastructure Solutions
-
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
5.0
5.5
6.0
6.5
7.0
7.5
8.0
(mill
ions o
f barr
els
per
day)
Petroleum Products Crude Oil
79
84
89
94
99
104
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
(mill
ions o
f barr
els
per
day)
World Liquids Fuels Consumption
U.S. Role as Marginal Supplier Drives Logistics Opportunities in the Gulf Coast
27
Source: U.S. Energy Information Administration (latest available as of 8/8/19)
Demand for storage and deepwater docks increasing to support exports as growing North American supply and
advantaged U.S. Gulf Coast refining center meet growing global liquids demand, including from Latin America
~0.7 million bpd of
export growth in
the last 12 monthsClose to 3 million bpd of
demand growth
expected in next 2 years
PADD3 Exports of Crude Oil and Petroleum Products
Delivering Energy Infrastructure Solutions
U.S. Gulf Coast is the Advantaged Supplier of Refined Products
Latin America Liquid Refined Product Demand Forecast Asia Liquid Refined Product Demand Forecast
U.S. is the advantaged and incremental supplier of refined products to Latin American and European markets
• U.S. Gulf Coast is the preferred supplier of refined products to Latin America due to regional lack of refining capacity and higher
complexity. Mexico is the largest US refined product export market
- Total Latin American demand for refined products is set to increase by nearly one million barrels per day by 2030
• Asia refined product demand represents an important growth opportunity for U.S. Gulf Coast refined product exports due to the
completed expansion of the Panama Canal
- Asia refined product demand is forecasted to grow by eight million barrels per day by 2030
• Current refined product terminals on the Houston Ship Channel are operating at capacity and experiencing heavy vessel
demurrage
28
Source: U.S. Energy Information Administration International Energy Outlook 2017
0
5
10
15
20
25
30
35
40
45
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Mill
ion
bb
ls/d
Asia
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Mill
ion
bb
ls/d
Mexico Brazil Other LatAm
Delivering Energy Infrastructure Solutions
Aerial view of TexasDeepwater terminal on the Houston Ship Channel (yellow shading)
USDG’s TexasDeepwater Partners Joint Venture on the U.S. Gulf Coast
29
TexasDeepwater Partners is actively engaged with high-quality, primarily investment grade counterparties to develop
substantial storage, blending and distribution infrastructure, including exports to international markets
• Advantaged greenfield location directly
on the Houston Ship Channel
• Large-scale footprint with 45’ draft
capabilities
• Independent terminal with potential for
customer-focused solutions
• Numerous rights-of-way could provide
connectivity to nearly all major inbound
liquids pipelines
• Multiple docks providing deepwater
access to international markets, plus
barge connectivity to Gulf Coast refining
centers
• Assets expected to be backed by multi-
year take-or-pay contracts
• Well-suited as future drop down to USDP
• Current railcar storage and dredge
operations support key preparation
activities, such as permitting, engineering
and connectivity efforts
Delivering Energy Infrastructure Solutions
Large Scale, Multi-Modal Energy Terminal Directly on the Houston Ship Channel
30
988-acre property is fully-permitted to support up to 12 million barrels of liquids storage, multiple docks (including
barge and deepwater), inbound and outbound pipeline connectivity, as well as a unit train capable rail terminal
Houston
Ship
Channel
Delivering Energy Infrastructure Solutions
TDWP Deer Park Rail Terminal Facility Overview
31
• Operations
‒ TDWP has completed the refurbishment and retrofit of Shell’s Deer
Park Rail Terminal (DPRT) to transload refined products directly
from Shell’s refinery to railcars
‒ TDWP will lease the facility from Shell and serve as operator of the
refined products transload terminal
o Initially focused on serving the diesel market, with an option to
expand capabilities to regular / premium gasoline and jet fuel
‒ Rail loading rack is directly connected to Shell’s Deer Park refinery
complex as well as the Shell Colex terminal
‒ Refinery can provide products meeting Mexican product
specifications as set forth in NOM-016-CRE-2016
Facility Layout
• Commercial / Financial
‒ Shell is TDWP’s direct commercial counterparty, with multi-year contract in place
‒ Commencement date: August 2019
TDWP is the operator of a new refined products origination terminal in the U.S. Gulf Coast, placed into service in
August 2019, to serve surging demand in the Permian Basin and Mexico
New Origin for Ultra-Low Sulfur Diesel
Delivering Energy Infrastructure Solutions
Developing a Network of Refined Products Destination Terminals Across Mexico
32
Mexico is a large and growing energy export market for the United States
• Exports of petroleum products (e.g., motor
gasoline, distillate fuel oil, propane) to Mexico
have more than doubled over the last 3 years
• In 2017, Mexico was the destination for over
1 million bpd and over $23 billion worth of
petroleum products from the U.S.
• TexasDeepwater joint venture positioned to be a
origination point from the Gulf Coast
Current takeaway and storage infrastructure not yet optimized to support large volume of imports
• Opportunity to leverage existing rail infrastructure
to enable timely customer solutions / speed-to-
market
• Ability to offer origin optionality to optimize
delivered price in Mexico
USDG is developing a network of strategically positioned destination terminals in rail-advantaged markets
• Querétaro and Cuauhtémoc terminals have
commenced operations
Source: Mapswire (map), U.S. Energy Information Administration
Legend:
= TexasDeepwater JV
= USDG terminal assets/ developments
Significant opportunity to enhance the distribution of refined products in a complementary and growing market
Delivering Energy Infrastructure Solutions
DRUBIT: Improving the Model by Railing a Heavier Canadian Barrel
33
USDG is leading the development of a better industry solution for transporting bitumen barrels, enhancing rail’s
long-term value proposition for Canada’s growing oil sands production
Status Quo: Dilbit
Oil sands production combined with condensate
or another diluent to enable pipeline flow,
including in gathering lines
Future: DRUBITTM
Primarily bitumen barrel transportable by rail created by a diluent recovery
unit, or DRU, which separates diluent for return upstream
Gas
Paraffins
Diesel
Lube Oil
Gasoline
Fuel Oil
Bitumen
Naphtha
Crude
30% diluent
(e.g., condensate)
70% bitumen
(oil sands
production) 95% bitumen
5% diluent Opportunity for
refiners to use a
more profitable
feedstock
Sell more
oil sands
production
per barrel
Cost competitive for producers
• Volume uplift: Ability to ship more bitumen
per barrel than what flows in pipelines
• Reduced diluent needs / costs
• Utilizes existing railcar fleet
Better feedstock for refiners
• Consistent product
• Ability to blend an optimal crude
feedstock
• Utilizes existing railcar fleet
More efficient for railroads
• Non-flammable, non-hazardous material
• Ability to take more direct routes
• More efficient operations
Delivering Energy Infrastructure Solutions
34
Appendix
34
Delivering Energy Infrastructure Solutions
USD Partners LP Structure
35
USD Group LLC
(the Sponsor)
USD Partners GP LLC
(GP & IDRs)
Public Unitholders
Hardisty Crude
Terminal
(Initial Phase)
Stroud Crude
Terminal
West Colton
Ethanol TerminalRailcar
Fleet Services
100%
Ownership
Interest
1.7% GP Interest
& IDRs
Energy Capital
Partners
USD Holdings LLC
& ManagementGoldman Sachs
42.9% LP Interest
(Common Units and
Subordinated Units)
Casper Crude
Terminal
De
ve
lop
me
nt
Pro
jects
Op
era
tin
g P
roje
cts
55.4% LP Interest
Note: As of 6/30/2019 per second quarter 2019 10-Q.
USD Partners LP
(NYSE: USDP)
Hardisty Terminal
Expansions
Other
Strategic Projects
Houston Ship Channel, TX
Refined Products
Terminals - Mexico
Stroud Terminal
Expansions
Delivering Energy Infrastructure Solutions
$0
.24
37
5
$0
.28
75
$0
.29
00
$0
.29
25
$0
.30
00
$0
.30
75
$0
.31
50
$0
.32
25
$0
.33
00
$0
.33
50
$0
.34
00
$0
.34
50
$0
.35
00
$0
.35
25
$0
.35
50
$0
.35
75
$0
.36
00
$0
.36
25
$0
.36
50
Quarterly Distribution ($ / unit)
USDP Units Continue to Deliver Value through Volatile Market
36
Source: NYSE (as of 8/7/2019)
Note: Indexed price performance since USDP’s initial public offering pricing date of 10/8/2014. USDP performance calculated based on initial public offering price of $17.
* Distribution amount of $0.24375 represents a pro-rated targeted minimum quarterly distribution based on the partial quarter following initial public offering.
Since IPO, USDP has outperformed the Alerian MLP Index (AMZ) plus paid over $6.21 per unit in distributions
20%
25%
30%
35%
40%
45%
50%
55%
60%
65%
70%
75%
80%
85%
90%
95%
100%
105%
110%
Indexed P
rice P
erf
orm
ance
USDP AMZ WTI
Delivering Energy Infrastructure Solutions
Strong Safety Record Distinguishes USD in the Marketplace
All USDP 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
2018 marked USDG’s 13th consecutive year with zero recordable injuries
USDG has handled through its terminal network a total of approximately 240 million barrels of liquid hydrocarbons and
biofuels without a single DOT/PHMSA reportable spill
USDG has been nationally recognized by the National Safety Council for having an outstanding safety record for the last
eleven years
USDG has won numerous safety awards from multiple Class 1 railroads
Zero “lost time injuries” at USDP facilities since inception
37
We are committed to safe, efficient and reliable operations that comply with environmental and safety regulations
Delivering Energy Infrastructure Solutions
Non-GAAP Measures
We define Adjusted EBITDA as Net cash provided by operating activities
adjusted for changes in working capital items, changes in restricted cash,
interest, income taxes, foreign currency transaction gains and losses,
adjustments related to deferred revenue associated with minimum monthly
commitment fees and other items which do not affect the underlying cash
flows produced by our businesses. Adjusted EBITDA is a non-GAAP,
supplemental financial measure used by management and external users of
our financial statements, such as investors and commercial banks, to assess:
• our liquidity and the ability of our business to produce sufficient cash flow
to make distributions to our unitholders; and
• our ability to incur and service debt and fund capital expenditures.
We define Distributable Cash Flow, or DCF, as Adjusted EBITDA less net
cash paid for interest, income taxes and maintenance capital expenditures.
DCF does not reflect changes in working capital balances. DCF is a non-
GAAP, supplemental financial measure used by management and by
external users of our financial statements, such as investors and commercial
banks, to assess:
• the amount of cash flow available for making distributions to our
unitholders;
• the excess cash flow being retained for use in enhancing our existing
business; and
• the sustainability of our current distribution rate per unit.
We believe that the presentation of Adjusted EBITDA and DCF in this report
provides information that enhances an investor's understanding of our ability
to generate cash for payment of distributions and other purposes. The GAAP
measure most directly comparable to Adjusted EBITDA and DCF is Net cash
provided by operating activities. Adjusted EBITDA and DCF should not be
considered as alternatives to Net cash provided by operating activities or any
other measure of liquidity presented in accordance with GAAP. Adjusted
EBITDA and DCF exclude some, but not all, items that affect cash from
operations 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.
38
Delivering Energy Infrastructure Solutions
Adjusted EBITDA and Distributable Cash Flow Reconciliation
39
Note: Adjusted EBITDA is a non-GAAP measure. For a description of Adjusted EBITDA, see slide titled “Non-GAAP Measures.”
1. Represents foreign exchange transaction amounts associated with activities between the Partnership’s U.S. and Canadian subsidiaries.
2. Represents the change in non-cash contract assets associated with revenue recognized in advance at blended rates based on the escalation clauses in certain of the Partnership's customer contracts.
3. Represents 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 concurrent ly with the
recognition of revenue.
For the Year Ended
December 31,
2019 2018 2019 2018 2018
Net cash provided by operating activities 9,336$ 11,484$ 19,507$ 19,588$ 45,129$
Add (deduct):
Amortization of deferred financing costs (207) (215) (657) (430) (866)
Deferred income taxes 154 1,248 403 2,538 3,971
Changes in accounts receivable and other assets 3,134 (863) 2,298 6,414 (815)
Changes in accounts payable and accrued expenses (1,221) (4,243) (2,009) (2,978) 639
Changes in deferred revenue and other liabilities (2,264) 5,735 (2,462) 236 196
Interest expense, net 2,970 2,713 6,150 5,198 11,356
Provision for (benefit from) income taxes 128 (910) 198 (1,817) (2,669)
20 117 202 (94) (14)
Other income (25) — (42) — —
(52) (52) (103) (103) (205)
213 — 213 — —
Adjusted EBITDA 12,186 15,014 23,698 28,552 56,722
Add (deduct):
Cash paid for income taxes (329) (267) (607) (449) (814)
Cash paid for interest (2,995) (2,530) (5,815) (4,821) (10,038)
Maintenance capital expenditures (45) (31) (45) (80) (201)
Distributable cash flow 8,817$ 12,186$ 17,231$ 23,202$ 45,669$
Deferred revenue associated with deficiency credits (3)
June 30, June 30,
(in thousands)
Foreign currency transaction loss (gain) (1)
Non-cash contract asset (2)
For the Six Months EndedFor the Three Months Ended