investor presentation · marketer (a / a3) integrated (bbb / ba2) marketer (bb / ba2) casper...

Delivering Energy Infrastructure Solutions

Investor PresentationJune 2016

1


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 commercialization efforts by the Partnership and its sponsor, expected Adjusted EBITDA and distribution growth in 2016, the stability and predictability of the Partnership’s cash flows, the Partnership’s financial flexibility, the Partnership’s plans to de-lever through mid-to-late 2016, the intention of Energy Capital Partners to invest in our sponsor, Canadian oil sands 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 related to the buildout and commercialization of the sponsor’s Houston Ship Channel joint venture and the prospects of, and the potential benefits from, moving heavier crude through the use of a diluent recovery unit. 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 competitive conditions 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; our ability to successfully implement our business plan; our ability to complete growth projects on time and on budget; operating hazards and other risks incidental to handling crude oil and biofuels 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; change in availability and cost of capital; 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; changes in insurance markets impacting cost and the level and types of coverage available; 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, 2015, 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).

DRUBITSM is a service mark of USD Group LLC (USDG) and its affiliates.

2


Overview of USD Partners LPNYSE: USDP

3


Adjusted EBITDA Driven by Take-or-Pay Contracts

A Growth-Oriented Logistics MLP with High-Quality Cash Flows

Formed in 2014 by US Development Group, LLC to acquire, develop and operate energy-related logistics assets

• Including rail terminals and other high-quality and complementary midstream infrastructure

Substantially all of our operating cash flow is generated from multi-year, take-or-pay contracts for crude oil terminalling services, such as:

• Railcar loading for transportation to end markets

• Storage and blending in on-site tanks

• Related logistics services

Attractive ~11% yield plus announced guidance of 10% distribution growth in 2016 ¹

No direct commodity exposure

J. Aron & Company

Other Fee-Based 4%

Take-or-Pay Contracts96%

Large, Primarily Investment Grade Customers ²

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. Pie chart represents the Partnership’s first quarter 2016 Adjusted EBITDA before corporate expenses.1. Based on a closing price of $11.03 on 5/24/2016, first quarter 2016 distribution of $0.3075 per unit ($1.23 per unit annualized), and management’s guidance issued on 10/29/2015 that management intends to recommend a distribution increase of at least $0.0075

per unit each quarter through the fourth quarter of 2016. Any distribution or distribution increase recommended by management will be subject to board approval.2. Includes selected terminal customers.

4


Aerial View of Hardisty Terminal

Located in Close Proximity to the Hardisty Hub

Hardisty Terminal at Canada’s Largest Crude Oil Storage Hub

Crude oil origination terminal that loads various grades of Canadian crude oil onto railcars for transportation to end markets• Capacity to load up to two 120-railcar unit trains per day

• Located on Canadian Pacific’s North Main Line, which offers connectivity to key refining markets across North America

Only unit train-capable terminal serving the Hardisty hub• Hardisty hub is Western Canada’s primary storage and origination point with

over 20 million barrels of storage capacity

• Pipeline connection from Gibsons’ Hardisty storage terminal delivers crude oil to terminal

– Directly connected to six million barrels of storage capacity

– Additional 2.9 million barrels of storage capacity under construction

– Exclusive means by which crude oil can be transported by unit train

Commercialization efforts underway by our sponsor with both new and existing customers for future expansions• Seeking take-or-pay agreements under similar or longer terms than existing

contracts

• Targeting flexibility to load heavier grades of crude (Railbit, DRUBITSM and bitumen) from WCSB

• Substantial engineering and permitting progress achieved to date, including recent permits from AER

Hardisty Crude Oil Storage Hub

Source: Genscape, Gibson Energy Inc. (Hardisty crude oil storage capacity figures)

Hardisty Terminal’s Scalable Design

5


Aerial View of Casper Terminal

Casper Terminal Provides Competitive Access to Coastal Refiners

Recently acquired crude oil terminal located in Casper, Wyoming• Unit train-capable terminal with loading capacity in excess of 100,000 bpd

• Six customer-dedicated storage tanks with 900,000 barrels of total capacity

• Supported by take-or-pay contracts with high-quality, primarily investment grade refiners

• Commenced operations in September 2014 and acquired in November 2015

Ability to receive, blend and store specific grades of crude oil to optimize economics• Direct pipeline connection from the Express Pipeline to terminal

• Access to a variety of light, medium and heavy crude oil from Western Canada (dilbit, synbit, syncrude, etc.)

• Access to local production from truck unloading units

• Alleviates potential bottleneck from capacity differential between Express (~280,000 bpd inbound) and Platte (~168,000 bpd outbound) pipelines

Located on the BNSF Main Line with flexibility for both unit train and manifest shipments• Maximizes access to customer-preferred destination terminals, particularly on the

West Coast

• Origination / destination pairing on a single Class 1 railroad improves turn-times and reduces switching fees

– Improves railcar fleet utilization

Source: Spectra Energy Partners LP Supplemental Information Appendix dated 5/4/2016 (map)

Located at the Intersection of Express and Platte Pipelines

Rail routes

6


TodayHardisty Terminal (54% of Adj. EBITDA)

Marketer (Not rated)

Refiner (BBB+ / A3)

Integrated (A- / Baa1)

Integrated (A+ / Aa3) 3.8%Marketer (A / A3)

Integrated (BBB / Ba2)

Marketer (BB / Ba2)

Casper Terminal (39% of Adj. EBITDA)

Refiner (BB+ / Ba1)

Refiner (BBB+ / A3) 3.3%Refiner (BBB / Baa2)

Railcar Fleet Services(3% of Adj. EBITDA)

Integrated (A- / Baa1) Multiple contracts through Apr-2024 →Marketer (Not rated) Dec-2022 →Integrated (A+ / Aa3) Aug-2022 → 4.7%Marketer (BB / Ba2) Feb-2021 →Marketer (A / A3)

Marketer (Not rated) Multiple contracts

2016 2017 2018 2019 Average Customer Dividend

Yield:

Cash Flows from High-Quality Take-or-Pay Contracts

High-quality, primarily investment grade customers provide stable and predictable cash flows through current commodity price cycle

Source: Standard & Poor’s, Moody’s, company news releases, FactSet (as of 5/24/2016)Note: Certain USD customers are wholly-owned subsidiaries of the entities whose credit rating and yield are shown above. Marketers include midstream companies with marketing operations as well as trading-focused companies. % of Adj. EBITDA represents the Partnership’s first quarter 2016 Adjusted EBITDA before corporate expenses. 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.

7


Financial Flexibility to Execute on Growth Opportunities

~$167 million of available liquidity, including:

• ~$9 million of cash

• ~$159 million of revolver capacity after exercising $100 million senior secured credit facility accordion in November of 2015

Conservative leverage profile

• ~3.6x Net Debt / Pro Forma Adjusted EBITDA ¹

• Expect to de-lever through mid-to-late 2016 to targeted levels (≤ 3.5x)

Well-capitalized sponsor with backing from Energy Capital Partners

• Separate sponsor credit facility to support development projects (currently no debt outstanding at sponsor)

• ECP indicated an intention to invest over $1.0 billion of additional equity capital in our sponsor ²

– Energy infrastructure-focused private equity fund with over $13 billion of capital commitments

– Extensive MLP and midstream experience

Leverage and Liquidity (in millions, as of 3/31/2016)

Cash and Cash Equivalents $8.6

Revolving Credit Facility Capacity 361.7

Less: Revolver Borrowings (203.0)

Available Liquidity $167.3

Revolver Borrowings $203.0

Term Loan (drawn in C$, shown in US$) 38.3

Total Debt $241.3

Net Debt 232.7

Total Debt / Pro Forma Adj. EBITDA¹ 3.7x

Net Debt / Pro Forma Adj. EBITDA¹ 3.6x

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. Based on results for the twelve month period ended 3/31/2016, pro forma for $26 million of expected 2016 Adjusted EBITDA and $0.7 million of one time costs attributable to the Casper terminal acquisition.2. Subject to market and other conditions.

8


Current Market Dynamics and Opportunities

9


Oil sands production has unique qualities that make it less sensitive to temporary commodity price movements

Western Canada Oil Sands U.S. Shale

Production Type Heavy Crude Crude, natural gas and associated liquids

Typical API Gravity of CrudeRaw Bitumen: ~8°Diluted Bitumen: ~20° to 22°Upgraded Bitumen / Synthetic Crude: ~31° to 33°

~35° to 50+°

Decline Profile Very low High initial declines

Asset Life 30+ years Various

Capital Profile Significant up front capital Ratable

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

10


Industry forecasts production growth of 700,000 to 1,000,000 barrels per day by 2020

Steady Growth in Western Canada Crude Oil Production

Source: Bank of Montreal (bar graph), Canadian Association of Petroleum ProducersNote: Forecast does not include diluent volumes needed to move oil sands production (bitumen) via pipelines.

Western Canada Crude Oil Production Outlook (April 2016)

2.9

3.4 3.5

3.8 3.9

4.1 4.3

4.6

4.9 5.1

5.2

-

1.0

2.0

3.0

4.0

5.0

6.0

2010 2011 2012 2013 2014 2015 2016E 2017E 2018E 2019E 2020E

(mill

ions

of b

arre

ls p

er d

ay)

Other Heavy Conventional Oil Sands - Mining Oil Sands - In Situ CAPP Forecast (June 2015)

11


Canadian Production Growth is Directed to Hardisty Storage Hub

500,000 to 570,000 bpd of new volumes expected by 2017

• Dilbit growth of ~340,000 to 360,000 bpd

• Syncrude growth of ~110,000 to 130,000 bpd

• Synbit growth of ~50,000 to 80,000 bpd

Estimate 340,000 to 370,000 bpd of new volumes directed to Hardisty by 2017, the equivalent of ~6 unit trains per day

• Our Hardisty terminal currently has capacity to load up to two unit trains per day

Industry deploying substantial capital in anticipation of growth

• Nearly 1.0 MMbpd of new gathering capacity into the Hardisty hub recently completed

• 2.9 MMbbls of new storage capacity under construction at Gibsons’ Hardisty terminal, supported by take-or-pay contracts

• Spectra Energy Partners’ $135MM Express Enhancement project due in service by Q4 2016

Our Hardisty and Casper terminals are scalable and strategically positioned to meet upcoming transportation needs

Oil Sands Producing

Areas

Edmonton, Alberta

Est. 160,000 to 200,000 bpd

Express Pipeline

Hardisty, Alberta

Est. 340,000 to 370,000 bpd

Casper, Wyoming

Rail to market

Rail to marketSource: Alberta Oil Sands Industry Quarterly (Spring 2016), company Annual information Forms and annual reports, Gibson Energy Inc., internal estimates, Spectra Energy Partners LP Supplemental Information Appendix dated

5/4/2016 Note: Management estimates for specific qualities of crude have been applied to publicly available estimates for new production capacity. Dilbit volumes assume a diluent requirement of ~30%. Synbit volumes assume a 50/50 blend of syncrude and bitumen. Assumes 60,000 barrels per unit train.

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Additional Pipeline Capacity is Still Unclear

Proposed long haul pipeline additions from Western Canada have faced meaningful delays

Proposed PipelineCapacity

(mbpd)2013 CAPP Est. In Service Date

2014 CAPP Est. In Service Date

2015 CAPP Est. In Service Date

Current Est. In Service Date

Keystone XL 830 2015 2017 2018 ?

Trans Mountain Expansion 590 Q4 2017 Q4 2017 Q4 2018 End of 2019

Northern Gateway 525 Q4 2017 Q3 2018 2019 ?

Energy East 1,100 Q4 2017 Q4 2018 2020 2020

Mainline Expansion 370 − − H2 2017 2019

Require long-term commitments for end-to-end transportation costs to support returns on substantial capital costs (relative to rail)

Recent political shift to more resistant governments

Well-organized opposition from environmentalists and segments of the general public alike

Presidential permit required to cross the U.S. border

Substantial cost increases resulting from delays

Limited incentives to encourage cooperation between provinces to reach Canada’s coasts

• Vast majority of production originates in Alberta, a province in the interior of the country

Multiple headwinds remain

Source: University of Calgary, investor presentations, public announcements, Canadian Association of Petroleum Producers

13


($45)

($40)

($35)

($30)

($25)

($20)

($15)

($10)

($5)

$0

$5

$10

Dis

coun

t to

WTI

($ p

er b

arre

l)

USGC Maya spot price less estimated pipeline freight costs from Hardisty to USGCUSGC Maya spot price less estimated rail freight costs from Hardisty to USGCWCS price

Spreads Suggest Market is Currently in Balance

Forecasted production growth expected to push WCS discounts wider and incentivize additional WCS barrels to move by rail to the U.S. Gulf Coast

Source: Bloomberg, Platts and internal estimates for transportation cost adjustments (as of 5/24/2016)

Incentive to Invest in Takeaway Capacity

Incentive to Move by Rail

Incentive to Move by Pipe

14


Growing Canadian Crude Oil Exports Headed to U.S. Gulf Coast

U.S. is effectively the sole export market for Canadian crude oil• World’s largest consumer of crude oil

• Destination for >99% of Canadian crude oil exports in 2015

– Record-high share of U.S. imports and continuing to increase

Midwest (PADD 2), Canada’s largest export market, is estimated to be mostly saturated• Two thirds of Canadian crude oil exports in 2015

• 50+% increase since 2010, resulting from:

– New refining capacity

– Expanded inbound pipelines

Gulf Coast (PADD 3) refiners import substantial volumes of heavy crude oil, including from Mexico and Venezuela• Imports from Canada more than doubled from 2013 to 2015

– Helped by improved market connectivity

• Destination for ~13% of Canadian crude oil exports in 2015

U.S. Gulf Coast is the largest refining center in North America and likely destination for growing Canadian crude

-

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

11.0

Canada Saudi Arabia Venezuela Mexico Other

U.S. Crude Oil Imports (millions of barrels per day)

Source: Canada National Energy Board, U.S. Energy Information Administration

15


Growth Opportunity: U.S. Gulf Coast Terminal on the Houston Ship Channel

In October 2015, USDG and Pinto Realty Partners LP formed a joint venture to develop a premier logistics terminal on the Houston Ship Channel and are currently engaged in commercial negotiations with potential customers

• 988-acre property could support several million barrels of storage capacity, multiple docks and a rail terminal with capacity to unload multiple unit trains per day

• Advantaged location positioned to provide access to substantially all inbound and outbound pipelines

• Dockage would provide barge connectivity to major Gulf Coast refining centers, as well as deepwater access to international markets

• Service by two Class 1 railroads (BNSF and UP)

Strategic Texas Deepwater Property on the Houston Ship Channel

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Cost competitive for producers• Volume uplift: Ability to ship more

bitumen per barrel than what flows in pipelines

• Reduced diluent needs / costs

• Quality preservation

• Utilizes existing railcar fleet

More efficient for railroads• Non-flammable

• Non-hazardous

• Less volatile

Better feedstock for refiners• Consistent product

• Ability to blend an optimal crude feedstock

• Utilizes existing railcar fleet

Growth Opportunity: Improving the Model by Railing a Heavier Canadian Barrel

Expected benefits of DRUBITSM:

USDG is leading the development of a better industry solution for transporting bitumen barrels − expected to maximize economics across the value chain − through the use of a diluent recovery unit (DRU), our scalable terminal footprints and expansive rail infrastructure

17


USD Partners LP Highlights

Attractive ~11% Yield plus 2016 Distribution Growth Guidance of 10%

Take-or-Pay Cash Flows

High Quality, Primarily Investment Grade Customers

Strategically Located Assets Positioned for Organic Growth

Conservative Leverage with Available Liquidity

Relationship with Sponsor and Energy Capital Partners

18


Appendix

19

19


USD Partners LP Structure

USD Group LLC(the Sponsor)

USD Partners GP LLC(GP & IDRs)

Public Unitholders

Hardisty Crude Terminal

(Initial Phase)

San AntonioEthanol Terminal

West ColtonEthanol Terminal

RailcarFleet Services

Hardisty Terminal Expansions

100% Ownership

Interest

2.0% GP Interest & IDRs

OtherStrategic Projects

Energy Capital Partners

USD Holdings LLC & Management Goldman Sachs

49.9% LP Interest(Common Units and Subordinated Units)

Casper Crude Terminal

Dev

elop

men

t Pro

ject

sO

pera

ting

Proj

ects

Houston Ship Channel, TX

Philadelphia, PA

Jacksonville, FL

48.1% LP Interest

Note: Public unitholders includes 138,750 Class A units (<1% of total units) beneficially owned by certain management team members subject to certain vesting and other conversion requirements and 1.7 million units (~7.5% of total units) issued to certain sellers of the Casper terminal who are restricted for one year post-closing.

USD Partners LP(NYSE: USDP)

20


Attractive Yield Relative to Expected Distribution Growth

USDP appears undervalued based on management’s guidance of at least 10% distribution growth in 2016

R² = 0.7552

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

0.0% 2.0% 4.0% 6.0% 8.0% 10.0% 12.0% 14.0% 16.0% 18.0% 20.0%

2016

–20

18 D

istr

ibut

ion

CAG

R

Current Yield

Current USDP Yield

Guidance Range

Current Yield vs. 2016 – 2018 Expected Distribution CAGR (Midstream MLPs)

Source: Barclays, Bloomberg (market data as of 5/20/2016)Note: 2016 – 2018 growth rates determined by Wall Street research.

21


Rail Provides Scalable and Flexible Market Access at a Relatively Low Fixed Cost

Cost Speed Market Optionality Quality Preservation

• Less upfront investment and maintenance capital required

• Reduced financial commitments

– 5 – 15 years vs. 10 – 20 years for pipelines

– Fixed terminalling fee is a small portion of the all-in transportation cost

– Cost effective protection from “no flow” scenario

• Transporting heavier barrels promotes use of existing railcar fleets

• Shorter development time

– ~1 year vs. multiple years for pipelines

• Faster deployment of infrastructure

– Significant rail infrastructurealready in place

• Increased ability to scale and expand capacity

– Ability to offer tailored takeaway solutions

• Reach best priced markets on shorter notice

– Ability to choose destination once train is loaded

• Faster physical delivery of product

– Nine days from W. Canada to the Gulf Coast vs. 30 – 45 days via pipelines

• Low fixed cost enables a portfolio approach to transportation

• Reduced cost of feedstock

– Access to domestic feedstock vs. imports

• Consistent quality control vs. potential quality degradation in pipelines

• Loading heavier grades of crude oil reduces need for costly diluents

– Fewer dollars spent sourcing and transporting diluent

– Bitumen volume uplift

– Better value with fewer light ends

Long-term, sustainable energy infrastructure solution with benefits for both producers and refiners

22


Strategically Located Ethanol Destination Terminals

Fragmented production

Pipelines disadvantaged and trucks uneconomical

Significant regional imbalances

Regulatory pressures regarding gasoline blending

Multiple Industry Infrastructure Needs Addressed

Unit train-capable

Transload ethanol received by rail from producers onto trucks to meet local ethanol demand

• Each terminal has 20 railcar offloading positions and three truck loading positions

• San Antonio: 20,000 bpd max rate

• West Colton: 13,000 bpd max rate

Only ethanol rail terminals within a 10-mile radius of nearby gasoline blending terminals serving their respective markets

• San Antonio, Texas

• San Bernardino and Riverside County-Inland Empire region of Southern California

Overview of Ethanol Destination Terminals

San Antonio Terminal Blending

Facilities

Blending Facilities

Blending Facilities

Blending Facilities

Blending Facilities

~5 miles

West ColtonTerminal

Blending Facilities

~1 mile

San Antonio Terminal Location

West Colton Terminal Location

23


Managing a Modern Railcar Fleet for Our Customers

We provide customers with leased railcars and fleet services related to the transportation of liquid hydrocarbons and biofuels by rail on a multi-year, take-or-pay basis

• Services include administrative and billing, management and tracking, maintenance, regulatory reporting and compliance

• We do not own any railcars

• Approximately 83% of our fleet is dedicated to our Hardisty terminal customers with a weighted average remaining contract life of 5.4 years (as of 3/31/2016)

Total Railcars (as of 3/31/2016) 2,993

Coiled and Insulated 2,108

Constructed in 2013 and Later 94%

Average Age ~3 years

Weighted Average Remaining Contract Life 4.8 years

24


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

2015 marked USDG’s 10th consecutive year with zero recordable injuries

USDG has handled through its terminal network over 170 million barrels of biofuels and liquid hydrocarbons without a single DOT/PHMSA recordable spill

USDG has been nationally recognized by the National Safety Council for having an outstanding safety record for the last nine years

USDG has won numerous safety awards from multiple Class 1 railroads

Zero “lost time injuries” at USDP facilities since inception

We are committed to safe, efficient and reliable operations that comply with environmental and safety regulations

25


Non-GAAP Measures

We define Adjusted EBITDA as net income before depreciation and amortization, interest and other income, interest and other expense, unrealized gains and losses associated with derivative instruments, foreign currency transaction gains and losses, income taxes, non-cash expense related to our equity compensation programs, discontinued operations, adjustments related to deferred revenue associated with minimum monthly commitment fees and other items which management does not believe reflect the underlying performance of our business. We define Distributable Cash Flow as Adjusted EBITDA less net cash paid for interest, income taxes and maintenance capital expenditures. Distributable Cash Flow does not reflect changes in working capital balances. Adjusted EBITDA and Distributable Cash Flow are both non-GAAP, supplemental financial measures used by management and by external users of our financial statements, such as investors and commercial banks, to assess:

• our operating performance as compared to those of other companies in the midstream sector, without regard to financing methods, historical cost basis or capital structure;

• the ability of our assets to generate sufficient cash flow to make distributions to our partners;

• our ability to incur and service debt and fund capital expenditures; and

• the viability of acquisitions and other capital expenditure projects and our ability to generate incremental cash flows from these opportunities.

We believe that the presentation of Adjusted EBITDA and Distributable Cash Flow provides information useful to investors in assessing our financial condition and results of operations. We believe that the presentation of

Adjusted EBITDA and Distributable Cash Flow information also enhances investor understanding of our business’ ability to generate cash for payment of distributions and other purposes. The GAAP measures most directly comparable to Adjusted EBITDA are Net Income and Cash Flow from Operating Activities. Adjusted EBITDA should not be considered an alternative to Net Income, Cash Flow from Operating Activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect Net Income, and these measures may vary among other companies. As a result, Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other companies.

26


Adjusted EBITDA and Distributable Cash Flow Reconciliation

1. The amounts presented represent the gross proceeds received at the time the derivative contracts were settled and do not consider the amounts paid in connection with the initial purchase of the derivative contracts. We purchased the derivative contracts for $283 thousand and $79 thousand with respect to the contracts settled in the three months ended March 31, 2016 and 2015, respectively.

2. Represents foreign exchange transaction gains and losses associated with activities between our U.S. and Canadian subsidiaries. 3. Represents deferred revenue associated with minimum monthly commitment fees in excess of throughput utilized, which fees are not refundable to our customers. Amounts presented are net of: (a) the corresponding prepaid Gibson pipeline fee that will be

recognized as expense concurrently with the recognition of revenue; (b) revenue recognized in the current period that was previously deferred; and (c) expense recognized for previously prepaid Gibson pipeline fees, which correspond with the revenue recognized that was previously deferred.

27


Adjusted EBITDA and Distributable Cash Flow Reconciliation

1. The amounts presented represent the gross proceeds received at the time the derivative contracts were settled and do not consider the amounts paid in connection with the initial purchase of the derivative contracts. We purchased the derivative contracts for $403 thousand with respect to the contracts settled in the year ended December 31, 2015.

2. Represents foreign exchange transaction amounts associated with activities between our U.S. and Canadian entities.3. Represents costs incurred associated with unrecovered reimbursable freight costs related to the initial delivery of railcars in support of the Hardisty terminal.4. Represents deferred revenue associated with minimum monthly commitment fees in excess of throughput utilized, which fees are not refundable to the customers. Amounts presented are net of: (a) the corresponding prepaid Gibson pipeline fee that will be

recognized as expense concurrently with the recognition of revenue; (b) revenue recognized in the current period that was previously deferred; and (c) expense recognized for previously prepaid Gibson pipeline fees, which correspond with the revenue recognized that was previously deferred.

Year Ended December 31, 2015 (in thousands)

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