usd partners lp investor presentation · 2019-08-13 · usd partners lp investor presentation citi...

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


Overview of USD Partners LP

NYSE: USDP

3


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.


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


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


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


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



Stroud Terminal (22% of Adj. EBITDA) (1)

Producer A / A3 52% Jun-2020

Producer5 A / A3 10% Jan-2020



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.


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


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


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


Western Canadian Market

Update and Opportunities


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


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


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


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


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


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


$(45.00)

$(43.00)

$(41.00)

$(39.00)

$(37.00)

$(35.00)

$(33.00)

$(31.00)

$(29.00)

$(27.00)

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$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


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


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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


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


Asset Overview:

USD Partners’ Crude Terminals


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.


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.


Selected Sponsor Development

Activities


-

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


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


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


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


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


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


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


34

Appendix

34


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


$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


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


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


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

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