Investor Presentation

Transcription

1 Investor Presentation MLPA Conference

2 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, 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 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 forwardlooking 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; shutdowns 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 thirdparty 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, 2016, 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 ( and at the Partnership s website ( DRUBIT SM is a service mark of USDG and its affiliates. 2

3 Overview of USD Partners LP NYSE: USDP 3

4 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 Other Fee-Based 4% 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 Take-or-Pay Contracts 96% Adjusted EBITDA driven by take-or-pay contracts ¹ Storage and blending in on-site tanks Related logistics services Units offer ~10% current yield ² Expect 5-10% distribution growth in 2017 J. Aron & Company No direct commodity exposure Primarily large, investment grade customers ³ 1. Pie chart represents the Partnership s Adjusted EBITDA before corporate expenses for the three months ended 3/31/2017. 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 $13.80 on 5/30/2017 and first quarter 2017 distribution of $0.335 per unit ($1.34 per unit annualized). 3. Includes selected terminal customers. 4

5 Strategically Positioned Terminals Levered to Growing Canadian Production 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 per day 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 ~9 of over 20 million barrels of storage at Hardisty ¹ Aerial View of Hardisty Terminal Take-or-pay contracts with producers, refiners and marketers Ability to add a third train of daily loading capacity in <1 year 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 handle both unit-train and manifest shipments Hardisty Terminal s Scalable Design Located on the BNSF Main Line, which maximizes access to customerpreferred destinations on the West and Gulf coasts Take-or-pay contracts with large refiner customers Includes 900,000 barrels of customer-dedicated storage capacity Additional flexibility from truck loading and unloading capabilities 1. Source: Gibson Energy public filings and Genscape. Aerial View of Casper Terminal 5

6 Assets Underpinned by Take-or-Pay Contracts with High-Quality Customers Crude terminals serve primarily large, investment-grade customers and are underpinned by long-term take-or-pay contracts that generate over 90% of Adjusted EBITDA Hardisty Terminal Casper Terminal Customer Type Credit Rating Investment Grade? Contract Term Through Date Marketer Not rated Sep-2019 Refiner BBB+ / A3 Jun-2019 Integrated A- / Baa1 Jun-2019 Integrated A+ / Aa3 Jun-2019 Marketer A+ / A3 Jun-2019 Integrated BBB / Ba2 Split Jun-2019 Marketer BB / Ba2 Jun-2019 Refiner BB+ / Ba1 Aug-2019 Refiner BBB+ / A3 Oct-2018 Refiner BBB / Baa2 Aug-2017 Source: Standard & Poor s, Moody s (as of 5/30/2017) 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. Ratings of Baa3 / BBB- or better are considered investment grade. % of Adjusted EBITDA represents the Partnership s Adjusted EBITDA before corporate expenses for the three months ended 3/31/2017. 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. 6

7 Delivering Value through a Volatile Market Since IPO, USDP has meaningfully outperformed crude and the AMZ Index, plus paid over $3 per unit in distributions 110% 100% 90% USDP WTI AMZ Quarterly Distribution ($ / unit) $ $ $ $0.3150$ $ $0.2900$0.2925$ % $ Indexed Price Performance 70% 60% 50% 40% 30% 20% 10% 0% Q4'14¹ Q1'15 Q2'15 Q3'15 Q4'15 Q1'16 Q2'16 Q3'16 Q4'16 Q1'17 Source: NYSE (as of 5/30/2017) 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 $ Distribution amount of $ represents a pro-rated targeted minimum quarterly distribution based on the partial quarter following initial public offering. 7

8 Financial Flexibility to Execute on Growth Opportunities ~$192 million of available liquidity, including: ~$4 million of unrestricted cash and cash equivalents ~$188 million of revolver capacity with additional $100 million accordion available on senior secured credit facility ¹ Conservative leverage profile ~3.2x Net Debt / Adjusted EBITDA ² Expect to continue to de-lever with excess cash flow Well-capitalized sponsor with backing from Energy Capital Partners Sponsor has cash on hand and no outstanding debt ECP indicated an intention to invest over $1.0 billion of additional equity capital in our sponsor ³ Energy infrastructure-focused private equity fund with over $13 billion of capital commitments Leverage and Liquidity (in millions, as of 3/31/2017) Unrestricted cash and cash equivalents $4 Revolving credit facility capacity $400 Less: Revolver borrowings ($212) Available liquidity $192 Revolver borrowings $212 Term loan outstanding $0 Total Debt $212 Net Debt $208 Total Debt / Adjusted EBITDA 2 3.3x Net Debt / Adjusted EBITDA 2 3.2x Extensive MLP and midstream experience 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 3/31/ Subject to market and other conditions. 8

9 Western Canada Market Update and Opportunities 9

10 Western Canadian Oil Sands are Unlike U.S. Shale 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 Canada 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 Gathering Substantially all production is gathered into two storage hubs, Hardisty and Edmonton Local gathering systems are generally wellconnected to refining centers via pipelines Infrastructure Constrained Developed / Region-specific 10

11 Substantial Consolidation Puts Oil Sands in Active and Focused Hands Announced C$17.7 billion acquisition of remaining 50% interest in hallmark Foster Creek and Christina Lake oil sands projects, plus Deep Basin assets, from ConocoPhillips Recently resumed construction on 50,000 bpd Christina Lake Phase G with first oil expected H Evaluating Narrows Lake Phase A and Foster Creek Phase H Announced C$12.7 billion acquisition of 70% of the Athabasca Oil Sands Project and all of the Canadian in-situ and undeveloped oil sands assets previously owned by Shell First oil from 80,000 bpd Horizon Phase 3 expected late 2017 Pursuing Horizon debottleneck project with Q turnaround Acquired additional working interests in Fort Hills mine from Total and in Syncrude project from Murphy Oil and buy-out of Canadian Oil Sands Ltd First oil from 194,000 bpd Fort Hills mine expected late 2017 with ramp up through 2018 Obtained regulatory approval for first two 40,000 bpd Meadow Creek East phases with potential first oil in 2022 Source: Company websites, publicly-available investor presentations 11

12 Upside Potential to Current Production Growth Forecasts Consolidation of producing assets among Canada-focused companies expected to drive incremental growth over current forecasts as cost reductions, operating efficiencies and technological advancements are incorporated into development plans Today CAPP s 2016 Western Canadian Crude Oil Supply Forecast (millions of barrels per day) Long-term opportunity for existing and potential new rail capacity Source: Canadian Association of Petroleum Producers (June 2016) CAPP s Chart Notes: Capacity shown can be reduced by temporary operating and physical constraints. Enbridge capacity reduced by volumes of US Bakken transported in

13 Export Pipeline Volumes Nearing Capacity, Despite Recent Supply Disruptions Published Export Pipeline Apportionment Express Volumes 50% Mainline Trans Mountain 300 Unutilized Avg. Volume Current Capacity 40% % 20% (Mbpd) % 50 0% Nov-16 Dec-16 Jan-17 Feb-17 Mar-17 Apr-17 - (Mmbpd) Mainline Volumes Unutilized Avg. Volume Current Capacity (Mbpd) Keystone Volumes Unutilized Avg. Volume Current Capacity Source: Argus (apportionment), Genscape (capacity and utilization) 13

14 Uncertain Timing and Quantity of Additional Export Pipeline Capacity Expected timelines have shifted meaningfully since originally proposed Proposed Pipeline CAPP s Estimated In-Service Date Capacity (mbpd) Line 3 Restored (Mainline) 370 H Trans Mountain Expansion 590 Q Q Q Late 2019 Keystone XL Denied Energy East 1,100 Q Q Late 2020 Northern Gateway 525 Q Q Uncertain Multiple headwinds remain Large number of conditions imposed on pipelines with Canadian federal approvals Canadian federal approval process currently under review with significant changes recommended in recent assessment Well-organized opposition from environmentalists, First Nations and other segments of the general public, particularly at the state and provincial levels Substantial cost increases resulting from delays Energy East estimated to cost C$15.7 billion versus C$12 billion in late 2015 Trans Mountain Expansion estimated to cost C$7.4 billion versus C$5.4 billion in late 2015 Long-term commitments for end-to-end transportation costs needed to support returns on significant capital costs (relative to rail) Keystone XL undergoing commercial review with current and potential customers Source: Canadian Association of Petroleum Producers, public announcements, Wall Street research 14

15 Substantial and Visible Production Growth Directed at Hardisty Opportunity to provide volume and quality solutions for new and existing customers Customer Project Crude Type¹ Barrels Available for Takeaway (bpd) (Bitumen+Diluent) Anticipated Project Start Up Hardisty (Direct / Indirect)² Producer 1 Project A Synbit 150,000 Q Indirect Current Customer? Producer 2 Project A Synbit 150,000 Q Indirect Yes Producer 3 Project B Dilbit 37,500 Q Direct Yes Producer 3 Project C Dilbit 62,500 Q Direct Yes Producer 4 Project D Synbit 70,000 Q Indirect Producer 5 Debottleneck Synthetic 15,000 Q Indirect Producer 5 Project E Synthetic 80,000 Q Indirect Producer 6 Project F Dilbit 121,615 Q Direct Yes Producer 2 Project F Dilbit 69,905 Q Direct Yes Producer 7 Project F Dilbit 47,880 Q Direct Producer 8 Project G Dilbit 20, Direct Producer 3 Project H Dilbit 62,500 H Direct Yes Producer 5 Project I Dilbit 50,000 Q Indirect Producer 1 Project J Synbit 90, Indirect Producer 8 Project K Dilbit 13, Direct Producer 3 Project L Dilbit 37,500 TBD (2020) Direct Yes Producer 3 Project M TBD 45,000³ TBD (2020) TBD Yes Producer 9 Project N Dilbit 49, TBD Debottlenecking 4 Various Various 120, Both Various Total Nameplate Capacity 1,292,100 Estimated Volumes Already Online from Ramp-Up (281,500) Visible New Production / Capacity 1,010,600 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 month ramp up period to reach full capacity. 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. 3. Represents bitumen volumes until marketed quality is determined. 4. Assumes 30,000 bpd per year from (30,000 x 4 years). 15

16 Rail Provides Significant Potential Value Rail provides flexible market access at a relatively low fixed cost, enabling a portfolio approach to transportation Low Cost Greater Optionality Higher Degree of Quality Control Small portion of all-in transportation costs are fixed Less capital intensive than pipeline alternatives Readily scalable Faster physical delivery than pipelines (<10 days vs. 30+ days) Flexibility to choose destination market once train is loaded Quality control vs. potential quality degradation in pipelines Ability to improve margins on specialty barrels Cost-Effective Insurance Against Potential Widening of Spreads Illustrative economics of a 30,000 bpd terminal commitment relative to 300,000 bpd of total production Rail commitment for 10% of production: $2.00 / bbl Illustrative terminal fee Potential exposure per day if transportation is constrained and spreads widen: $15.00 / bbl Illustrative widening of spread X X 30,000 bpd Minimum volume commitment 300,000 bpd Production base $60,000 Fixed cost Effective rate: $60,000 / $4,500,000 = ~1% = = $4,500,000 Value at risk 16

17 Rail Option Creates Floor on Spreads and Protects Price for Canada s Production Canadian producers broadly benefit from investments in rail capacity, limiting the risk of large discounts resulting from infrastructure constraints, as experienced in $10 $5 $0 ($5) USGC Maya spot price less est. pipeline costs from Hardisty to the USGC USGC Maya spot price less est. rail costs from Hardisty to the USGC WCS-WTI Spread Pipeline Capacity Added Fort McMurray Wildfires Syncrude Upgrader Fire & Maintenance Discount to WTI ($ per barrel) ($10) ($15) ($20) ($25) ($30) Whiting Refinery Outage Cold Weather Event ($35) ($40) Rail Capacity Established ($45) Source: Argus Crude and internal estimates for transportation and quality cost adjustments (pricing as of 5/26/2017) 17

18 Expected Path Forward Creates Re-Contracting and Expansion Opportunity New oil sands production capacity is brought online and ramps over 12 to 18 months Apportionment on export pipelines increases until physical operating capacity is met Western Canadian crude price discount deepens relative to global prices Physical barrels seek alternative transportation means, including rail Point of re-contracting at Hardisty and Casper with potential for expansion 18

19 Update on Sponsor Development Activities 19

20 U.S. as New Swing Supplier Drives Commercial Opportunities in the Gulf Coast Meaningful growth in global demand driving increasing Gulf Coast exports of crude oil and refined products 102 World Liquid Fuels Consumption (Mmbpd) ~101 Mmbpd 1000 PADD 3 Exports of Crude and Petroleum Products (mbpd) Crude Oil (left) Petroleum Products (right) 4, ,250 ~97 Mmbpd 800 4, , , , , , , , ,000 Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Jan-2013 Apr-2013 Jul-2013 Oct-2013 Jan-2014 Apr-2014 Jul-2014 Oct-2014 Jan-2015 Apr-2015 Jul-2015 Oct-2015 Jan-2016 Apr-2016 Jul-2016 Oct-2016 Jan-2017 Source: U.S. Energy Information Administration (latest available as of 5/11/2017) 20

21 Existing Infrastructure Built to Support Current Supply Levels Gulf Coast crude oil storage utilization remains well above historical levels, despite recent capacity additions PADD 3 Working Storage Capacity (thousand barrels) PADD 3 Storage Utilization Rate (percent) 350,000 80% 300,000 70% 250,000 60% 200,000 50% 150,000 40% 100,000 30% 50,000 20% - 10% Refinery Storage Tank and Underground Storage Refinery Storage Tank and Underground Storage Total Source: U.S. Energy Information Administration (latest available as of 5/12/2017) 21

22 Houston Ship Channel Development to Deliver Full Suite of Logistics Solutions Texas Deepwater Partners, a USDG joint venture, is actively engaged with high-quality, primarily investment grade counterparties to provide storage, blending and distribution infrastructure, including exports to international markets Site plan featuring multiple docks and millions of barrels of storage capacity Aerial view of Texas Deepwater terminal on the Houston Ship Channel (yellow shading) 22

23 Improving the Model by Railing a Heavier Canadian Barrel USDG is leading the development of a better industry solution for transporting bitumen barrels Status Quo: Dilbit Oil sands production combined with condensate or another diluent to enable pipeline flow, including in gathering lines Future: DRUBIT SM Primarily bitumen barrel transportable by rail created by a diluent recovery unit, or DRU, which separates diluent for return upstream Gas Naphtha 30% diluent (e.g., condensate) 70% bitumen (oil sands production) Sell more oil sands production per barrel 5% diluent Opportunity for refiners to use a more profitable feedstock 95% bitumen Paraffins Gasoline Diesel Crude Lube Oil Fuel Oil Bitumen 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 23

24 Comprehensive Logistics Network Positioned for Organic Growth Our Vision: A competitive network with full-suite logistics solutions that meet customer needs in a dynamic energy market, including transportation, storage, blending and export Expected Customer Benefits: Physical takeaway Access to the largest refining centers in North America Export optionality Quality preservation Better prices for products sold Western Canadian Crude Oil Infrastructure Required to Meet Customer Needs: Railcar loading and unloading Storage tanks Blending tanks Pipeline connectivity Barge docks Deepwater docks Expected Investor Benefits: Long term contracts Visible cash flows High quality customers Solid asset mix Exposure to multiple growth areas West Texas Crude Oil Crude Oil and Refined Products Legend: = USDP crude terminals = USDG Texas Deepwater = Growth areas Source: Association of American Railroads (map) 24

25 USD Partners LP Investment Highlights Units offer ~10% Yield and Expected 2017 Distribution Growth of 5-10% Multi-Year Take-or-Pay Contracts High Quality, Primarily Investment Grade Customers Strategically Positioned Terminals Levered to Growing Oil Sands Production Financial Flexibility to Pursue Organic Growth and Potential Acquisitions Relationship with Sponsor and Energy Capital Partners 25

26 Appendix 26 26

27 USD Partners LP Structure Energy Capital Partners USD Holdings LLC & Management Goldman Sachs Development Projects Hardisty Terminal Expansions Houston Ship Channel, TX Philadelphia, PA Jacksonville, FL 100% Ownership Interest USD Group LLC (the Sponsor) USD Partners GP LLC (GP & IDRs) 49.5% LP Interest (Common Units and Subordinated Units) Public Unitholders Other Strategic Projects 2.0% GP Interest & IDRs 48.6% LP Interest Operating Projects Hardisty Crude Terminal (Initial Phase) Casper Crude Terminal USD Partners LP (NYSE: USDP) San Antonio Ethanol Terminal West Colton Ethanol Terminal Railcar Fleet Services Note: Public unitholders includes 92,500 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% of total units) issued to certain sellers of the Casper terminal. 27

28 Strong Safety Record Distinguishes USD in the Marketplace We are committed to safe, efficient and reliable operations that comply with environmental and safety regulations 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 2016 marked USDG s 11 th consecutive year with zero recordable injuries USDG has handled through its terminal network over 183 million barrels of biofuels and liquid hydrocarbons 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 ten years USDG has won numerous safety awards from multiple Class 1 railroads Zero lost time injuries at USDP facilities since inception 28

29 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 expense, 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 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. 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 29

30 Adjusted EBITDA and Distributable Cash Flow Reconciliation For the Three Months Ended For the Year Ended March 31, December 31, (in thousands) Net cash provided by operating activities $ 12,815 $ 9,224 $ 53,076 Add (deduct): Amortization of deferred financing costs (215) (215) (861) Deferred income taxes (58) 46 (46) Changes in accounts receivable and other assets (1,827) (1,974) (1,859) Changes in accounts payable and accrued expenses (400) 832 1,917 Changes in deferred revenue and other liabilities 1,120 (543) 996 Change in restricted cash 21 2, Interest expense, net 2,603 2,183 9,837 Provision for (benefit from) income taxes 1,185 1,797 (759) Foreign currency transaction loss (gain) ¹ 30 (130) (750) Deferred revenue associated with minimum monthly commitment fees ² ,485 Adjusted EBITDA 15,354 14,409 63,690 Add (deduct): Cash received (paid) for income taxes ³ (616) (1,710) (845) Cash paid for interest (2,362) (1,807) (8,722) Maintenance capital expenditures (126) - (238) Distributable cash flow $ 12,250 $ 10,892 $ 53,885 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 gains and losses associated with activities between the Partnership s U.S. and Canadian subsidiaries. 2. 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. 3. Includes partial refunds of approximately $0.7 million (representing C$0.9 million) and $3.7 million (representing C$4.9million) received during the three months ended 3/31/2017 and the twelve months ended 12/31/2016, respectively, for the Partnership s 2015 foreign income taxes 30