FORWARD-LOOKING INFORMATION

Transcription

1 MARCH

2 FORWARD-LOOKING INFORMATION Certain information contained herein may constitute forward-looking statements that involve known and unknown risks, assumptions, uncertainties and other factors. Forward-looking statements in this presentation include, but are not limited to: (i) Inter Pipeline s low risk business strategy; (ii) the ability to maintain Inter Pipeline s current level of dividends and its growth potential; (iii) potential growth opportunities for both oil sands and conventional transportation assets through third-party growth projects, bolt-on projects, infrastructure development and expanded transportation service and including and all the potential benefits to be derived from those opportunities; (iv) the cost of Boreal pipeline expansion; (v) statements regarding the Heartland Petrochemical Complex and the expansion of the Central Alberta Pipeline, including the timing of construction and fabrication activities, sourcing of components, costs, and in-service dates for each project, and all the potential benefits to be derived from those projects, including without limitation all the financial benefits; (vi) the contracting process to secure take-or-pay contracts for the Heartland Petrochemical Complex; (vii) the potential to suspend the premium dividend reinvestment program in relation to the Heartland Complex by the end of 2019; (viii) the timing of the completion of the NuStar Europe acquisition and the anticipated benefits of this acquisition and the growth opportunities associated therewith; and (ix) the financial forecasts and anticipated financial performance of Inter Pipeline. Readers are cautioned not to place undue reliance on forward-looking statements, as such statements are not guarantees of future performance. Inter Pipeline in no manner represents that actual results, levels of activity and achievements will be the same in whole or in part as those set out in the forward-looking statements herein. Such information, although considered reasonable by Inter Pipeline at the time of preparation, may later prove to be incorrect and actual results may differ materially from those anticipated in the statements made. For this purpose, any statements that are not statements of historical fact may be deemed to be forward-looking statements. Forward-looking statements often contain terms such as "may", "will", "should", "anticipate", "expects" and similar expressions. Such assumptions, risks, uncertainties and other factors include, but are not limited to, risks and assumptions associated with operations, such as Inter Pipeline s ability to successfully implement its strategic initiatives and achieve expected benefits, including the further development of its pipeline systems and other facilities; assumptions concerning operational reliability; Inter Pipeline s ability to maintain its investment grade credit ratings; the availability and price of labour, equipment and construction materials; the status, credit risk and continued existence of customers having contracts with Inter Pipeline and its affiliates; availability of energy commodities; volatility of and assumptions regarding prices of energy commodities; competitive factors, pricing pressures and supply and demand in the oil and gas transportation, natural gas liquids processing and storage industries; assumptions based upon Inter Pipeline s current guidance; fluctuations in currency and interest rates; inflation; the ability to access sufficient capital from internal and external sources; risks and uncertainties associated with Inter Pipeline s ability to maintain its current level of cash dividends to its shareholders; risks inherent in Inter Pipeline s Canadian and foreign operations; risks of war, hostilities, civil insurrection, instability and political and economic conditions in or affecting countries in which Inter Pipeline and its affiliates operate; severe weather conditions; terrorist threats; risks associated with technology; Inter Pipeline s ability to generate sufficient cash flow from operations to meet its current and future obligations; Inter Pipeline s ability to access external sources of debt and equity capital; general economic and business conditions; the potential delays of and costs of overruns on construction projects, including, but not limited to Inter Pipeline s current pipeline, petrochemical, NGL processing and terminal storage projects and future expansions of Inter Pipeline s assets; risks associated with the failure to finalize formal agreements with counterparties in circumstances where letters of intent or similar agreements have been executed and announced by Inter Pipeline; Inter Pipeline s ability to make capital investments and the amounts of capital investments; changes in laws and regulations, including environmental, regulatory and taxation laws, and the interpretation of such changes to Inter Pipeline s business; the risks associated with existing and potential or threatened future lawsuits and regulatory actions against Inter Pipeline and its affiliates; increases in maintenance, operating or financing costs; availability of adequate levels of insurance; difficulty in obtaining necessary regulatory approvals or land access rights and maintenance of support of such approvals and rights; the timing, financing and completion of acquisitions and other projects Inter Pipeline is developing; the realization of the anticipated benefits of acquisitions and other projects Inter Pipeline is developing; and such other risks and uncertainties described from time to time in Inter Pipeline s reports and filings with the Canadian securities authorities. The impact of any one assumption, risk, uncertainty or other factor on a forward-looking statement cannot be determined with certainty, as these are interdependent and Inter Pipeline s future course of action depends on management s assessment of all information available at the relevant time. You can find a discussion of those risks and uncertainties in Inter Pipeline s securities filings at Readers are cautioned that the foregoing list of assumptions, risks, uncertainties and factors is not exhaustive. The forward-looking statements contained in this news release are made as of the date of this document, and, except to the extent required by applicable securities laws and regulations, Inter Pipeline assumes no obligation to update or revise forward-looking statements made herein or otherwise, whether as a result of new information, future events, or otherwise. The forward-looking statements contained in this document and all subsequent forward-looking statements, whether written or oral, attributable to Inter Pipeline or persons acting on Inter Pipeline s behalf are expressly qualified in their entirety by these cautionary statements. NON-GAAP FINANCIAL MEASURES Certain financial measures referred to in this corporate presentation are not measures recognized by GAAP. These non-gaap financial measures do not have standardized meanings prescribed by GAAP and therefore may not be comparable to similar measures presented by other entities. Investors are cautioned that these non-gaap financial measures should not be construed as alternatives to other measures of financial performance calculated in accordance with GAAP. IHS MARKIT MATERIALS The IHS Markit reports, data and information referenced herein (the "IHS Markit Materials") are the copyrighted property of IHS Markit Ltd. and its subsidiaries ( IHS Markit ) and represent data, research, opinions or viewpoints published by IHS Markit, and are not representations of fact. The IHS Markit Materials speak as of the original publication date thereof and not as of the date of this document. The information and opinions expressed in the IHS Markit Materials are subject to change without notice and IHS Markit has no duty or responsibility to update the IHS Markit Materials. Moreover, while the IHS Markit Materials reproduced herein are from sources considered reliable, the accuracy and completeness thereof are not warranted, nor are the opinions and analyses which are based upon it. IHS Markit is a trademark of IHS Markit. Other trademarks appearing in the IHS Markit Materials are the property of IHS Markit or their respective owners. Inter Pipeline, and its subsidiaries, subscribe to various IHS Markit data services and a subsidiary of Inter Pipeline has contracted with IHS Markit for consultant services with respect to the Heartland Petrochemical Complex. 1

3 INTER PIPELINE Operate world-scale energy infrastructure assets Stable in an uncertain market, with a strong balance sheet and investment grade credit rating Sustainable dividend profile with upside growth potential Well-positioned to capitalize on future growth opportunities 2

4 WORLD-SCALE ENERGY INFRASTRUCTURE Oil Sands Transportation NGL Processing Conventional Oil Pipelines Bulk Liquid Storage 2018 Annual EBITDA ($1.2 billion) 48% 34% 13% 5% 2.3 million b/d of contracted capacity Over 240,000 b/d of production capacity 3,900 km pipeline network in western Canada 37 million barrels of storage capacity in Europe 3

5 AREAS OF OPERATION 2018 Annual EBITDA ($1.2 billion) 5% Canada 95% Europe SWEDEN DENMARK IRELAND ENGLAND NETHERLANDS GERMANY 4

6 RECENT DEVELOPMENTS Annual funds from operations (FFO) for 2018 totaled a record $1.1 billion Successfully closed $750 million subordinated hybrid note offering Dividend increased to $1.71 per share annually, marking 10 years of consecutive dividend increases Spending $82 million to expand the Central Alberta Pipeline system Constructing Canada s first integrated propane dehydrogenation and polypropylene complex for $3.5 billion 5

7 BUSINESS STRATEGY OWN AND OPERATE HIGH-QUALITY ENERGY INFRASTRUCTURE ASSETS Well-contracted to provide cash-flow stability Industry-leading project execution, with exceptional EH&S performance MAINTAIN STRONG FINANCIAL POSITION AND DIVIDEND TRACK RECORD Maintain investment grade credit rating 70% EBITDA from cost-of-service and fee-based contracts 60%Payout ratio before sustaining capital Dividends underpinned by cost-of-service and fee-based cash flow; commodity-based cash flow used to fund growth PURSUE DISCIPLINED GROWTH, BOTH ORGANICALLY AND THROUGH ACQUISITION ~$3.7 billion of announced capital opportunities Heartland Complex expected to add approximately $450 to $500 million of average annual EBITDA 10Yr 12% Track record of consecutive dividend increases CAGR in FFO per share ( ) 6

8 EBITDA BY CONTRACT TYPE Cost-of-Service 56% Fee-Based 13% Oil Sands Transportation ($592 million) 100% NGL Processing ($426 million) 12% 4% Commodity-Based 29% Product Margin 2% Conventional Oil Pipelines ($166 million) 18% 22% 28% 84% Bulk Liquid Storage ($61 million) Total EBITDA: $1,245 million 60% 72% Approximately 70% of 2018 consolidated EBITDA was generated from cost-of-service and fee-based contracts Year ended December 31,

9 GROWTH PROFILE Active Projects Segment Target In-Service Date Est. Capital Cost ($ Million) Heartland Petrochemical Complex NGL Late-2021 $3,500 Kirby North (Cold Lake & Polaris) Oil Sands Mid-2019 $110 Stettler Expansion Phase 1 (CAPL) Conventional Q / Q2 2020* $82 Total ~$3,700 Potential Projects Segment Announcement Timing Est. Capital Cost ($ Million) Polaris Connections Oil Sands Short-to-long-term $1,300 Bow River to CAPL Connector Pipeline Stettler Expansion Phase 2 & 3 (CAPL) Conventional Medium-term $600+ Cochrane Expansion NGL Medium-term $400 Acrylic Acid & Derivatives Facility NGL Medium-term $600 Cold Lake Connections Oil Sands Long-term $800 Corridor Connections** Oil Sands Long-term $700 Total $4,400+ *Expansion is expected to enter service in phases beginning in Q2 2019, with full operations expected in Q **Subject to existing shipper approval 8

10 CASH FLOW GROWTH FFO per share 11.8% CAGR $2.65 $2.80 $2.38 $2.19 $1.52 $1.57 $1.60 $1.71 $1.26 $1.27 $ % CAGR FFO per share attributable to shareholders 9

11 DIVIDEND GROWTH Dividends per share 5.3% CAGR F $1.57 $1.63 $1.69 $1.71 $1.49 $1.32 $1.18 $1.06 $0.85 $0.91 $ F 7.3% CAGR F 2019F based on actual dividends to date and $ per share per month thereafter 10

12 $1,200 DIVIDEND STABILITY $ Million $1,000 $800 $600 $400 $200 $ FFO 2013 Dividend 2014 FFO 2014 Dividend 2015 FFO 2015 Dividend 2016 FFO 2016 Dividend 2017 FFO 2017 Dividend 2018 FFO 2018 Dividend Cost-of-Service Fee-Based Commodity-Based Product Margin Dividends supported by cost-of-service and fee-based cash flow FFO is attributable to shareholders and before sustaining capital; calculation based on IPL assumptions 11

13 LEVERAGE METRICS Covenant Max 65% Target Min 19% Target Max 4.3x Prudent balance sheet management Solid foundation to finance growth projects 57% 54% 52% 22% 22% 4.8x Strong access to capital markets 17% 3.9x 3.8x $1.5 billion committed credit facility provides low-cost source of financing Key metrics to improve once the Heartland Complex is operational Leverage expected to increase over construction period Sr. Recourse Debt to Capitalization FFO to Recourse Debt* Recourse Debt to EBITDA* Financing plan includes hybrid securities, which receive favorable equity treatment Committed to maintaining a strong and flexible balance sheet *Based on Standard & Poor s calculation methodology; hybrid notes treated as 50% equity by credit rating agencies 12

14 48% 2018 ANNUAL EBITDA 13

15 OIL SANDS TRANSPORTATION Three major oil sands pipeline systems AOSP IMPERIAL KEARL HUSKY SUNRISE Cold Lake, Corridor and Polaris Polaris Pipeline Cold Lake Pipeline Corridor Pipeline Diluent and / or Bitumen Blend Athabasca Oil Sands JACOS / NEXEN HANGINGSTONE CNR KIRBY NORTH CNR KIRBY SOUTH CNR PRIMROSE / WOLF LAKE AOC HANGINGSTONE CVE NARROWS LAKE CVE CHRISTINA LAKE CVE FOSTER CREEK OSUM ORION IMPERIAL COLD LAKE Provide bitumen blend and diluent transportation service Over 3,300 km of pipeline and 3.8 million barrels of storage capacity BRUDERHEIM FACILITY Combined ultimate capacity of 4.6 million b/d Overbuild strategy provides long-term growth platform 14

16 EBITDA STABILITY (000 s b/d) Product Contracted Capacity Ultimate Capacity EBITDA underpinned by long-term cost-of-service contracts Cold Lake Bitumen Blend 1,255 1,900 Contracted capacity of ~2.3 million b/d Corridor Bitumen Blend 465 1,400 Polaris Diluent 535 1,300 Total 2,255 4, EBITDA of ~$600 million, independent of throughput volumes and commodity price fluctuations Flow through of substantially all operating costs to shippers Over 20 years remaining on cost-ofservice contracts Approximately 40 years if extension provisions exercised Approximately 97% of EBITDA underpinned by investment grade counterparties 15

17 OVERBUILD STRATEGY HORIZON SUNRISE PHASE 2 & DEBOTTLENECK ASPEN PHASE 1 & 2 Over 2.3 million b/d of available capacity, providing long-term growth platform Well-positioned to accommodate high return bolt-on projects Polaris Pipeline Cold Lake Pipeline Corridor Pipeline Diluent and / or Bitumen Blend Athabasca Oil Sands MACKAY RIVER ALGAR LAKE GROUSE KIRBY NORTH PHASE 1 & 2 BLACKGOLD COLD LAKE EXPANSION Ability to accommodate both small and large-scale projects Provide customers less regulatory, capital and schedule risk Proven strategy 11 bolt-on connections totaling over $580 million Average EBITDA multiple of ~3.2x Identified ~$3 billion of long-term potential oil sands opportunities 16

18 34% 2018 ANNUAL EBITDA 17

19 NGL PROCESSING Pioneer I & II Large-scale NGL infrastructure Three straddle plants strategically located on the TransCanada Alberta System Boreal Pipeline Offgas Extraction Facility Straddle Plant Redwater Olefinic Fractionator Heartland Complex Athabasca Oil Sands TransCanada Alberta System Redwater ~40,000 b/d Capacity Cochrane ~100,000 b/d Capacity Heartland Complex 525 KTA Capacity Empress II & V* ~105,000 b/d Capacity Two offgas plants with dedicated supply agreements Boreal pipeline with low cost expansion up to 125,000 b/d Ethane-plus fractionation facility at Redwater Heartland Petrochemical Complex development totaling ~$3.5 billion Complex to produce polypropylene, a high-value and easy to transport plastic *50% working interest in the Empress V facility 18

20 NGL PROCESSING EBITDA $ Million $450 $375 $300 $225 $150 Significant EBITDA generation at Cochrane and Redwater Robust frac-spreads and strong volumes drove record results in 2018 Commodity-based EBITDA used to fund growth and strengthen balance sheet Stable cost-of-service and fee-based EBITDA component $75 $ Cost-of-Service EII & EV propane plus Commodity-Based (Cochrane) Fee-Based Ethane & ethane-ethylene mix Commodity-Based (Redwater) ($ Million) Straddle Plants $116 $192 Redwater $146 $234 Cost-of-Service & Fee-Based $40 $68 Commodity-Based $222 $358 Total EBITDA $262 $426 Straddle plants include Cochrane and Empress II (EII) as well as a 50% working interest in Empress V (EV) 19

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22 HEARTLAND PETROCHEMICAL COMPLEX Transformational growth opportunity Capacity to consume ~22,000 b/d of propane to produce ~525 kilotonnes per annum (KTA) of polypropylene (PP) Expected to add approximately $450 to $500 million of average annual EBITDA Target 70% to 85% of processing capacity to be underpinned by take-or-pay contracts Operations expected to begin late-2021 Alberta-produced PP expected to have one of the lowest cash costs in North America Oversupplied propane market in Western Canada drives a long-term, low-cost feedstock advantage 21

23 POLYPROPYLENE MARKET FUNDAMENTALS 000 KTA 12 North American Polypropylene Total demand expected to grow ~22% over the next five years Single largest polymer in the world Used in many common goods, such as consumer packaging, automobile parts, medical equipment, currency and textiles 11 Expected to continue having a strong polymer position as a fully-recyclable plastic 10 Global PP market demand F 2023F Majority of HPC s production expected to be sold into the US market, which is expected to have the highest PP price in the world Global demand forecast to grow from ~74,000 KTA to over 90,000 KTA in 2023 Source: IHS Markit Materials; total demand includes domestic demand and exports; demand forecasts based on 5-year period from 2018F to 2023F 22

24 CANADIAN PROPANE SUPPLY ADVANTAGE 000 s b/d 300 Canadian propane market to remain oversupplied over the long-term More than 100,000 b/d of expected oversupply that will have to be exported Forecast petrochemical demand and potential international LPG exports will not balance the Canadian propane market Supply expected to grow as investment in liquids-rich gas plays is projected to continue 100 Canadian propane market structurally disadvantaged F 2020F 2025F 2030F 2035F Propane Exports CKPC PDH Feedstock Base Propane Demand IPL PDH Feedstock Canadian propane priced at a discount to the US due to oversupply and lack of egress Rail is the only propane export option since the Cochin pipeline was reversed in 2014 Source: IHS Markit Materials and IPL estimates 23

25 CANADIAN PROPANE DISCOUNT USD per USG $0.60 Mont Belvieu to Edmonton Propane Price Differential Cochin pipeline reversal* $0.40 $0.29 $0.20 $0.14 $ Monthly Differential Cochin In-Service Differential Cochin Reversed Differential Canadian propane discount relative to US propane creates a feedstock advantage that drives polypropylene cost competitiveness Cochin In-Service Differential from December 2008 to March 2014; Cochin Reversed Differential from April 2014 to December 2018 *Cochin pipeline discontinued Alberta propane export service in March

26 Delivered Cash Cost* NORTH AMERICAN COST COMPETITIVENESS USD per metric ton $1, PP Price $1,500 $1,250 $1,000 Indicative Margin $750 $500 $250 $0 Heartland Complex US-Based PP Facilities Alberta-produced polypropylene expected to have one of the lowest delivered cash costs to the US Midwest *Delivered cost includes fixed, variable, feedstock and logistics costs to the US Midwest Source: IHS Markit Materials 25

27 PROJECT STATUS $3.5 billion project cost de-risked by approximately 45% Based on lump-sum contracts, firm purchase orders, and substantially completed time and materials works Detailed design work and procurement of major equipment to be completed in 2019 Well-advanced PDH project FEED and detailed engineering complete Over $500 million lump-sum/unit rate contract for construction awarded to Kiewit Mechanical construction ongoing PP development progressing FEED complete and detailed engineering phase currently in progress 26

28 CAPITAL PROFILE & FINANCING STRATEGY $ Million Total project cost of ~$3.5 billion ~$1,100 ~$1,100 Heartland Complex financing sources Capacity available under existing $1.5 billion committed credit facility Periodic issuance of new term debt ~$800 ~$500 Hybrid debt securities Successfully issued $750 million of hybrid notes in March 2019 Undistributed cash flow from operations Invested 2019F 2020F 2021F As at Q Over $670 million in undistributed cash flow* generated during 2017 and 2018 Premium DRIP generating ~$300 million annually If strong financial performance continues, expected to be in a position to suspend the Premium DRIP by the end of 2019 *Undistributed cash flow defined as funds from operations less sustaining capital and declared dividends 27

29 COMMERCIAL FRAMEWORKS IPL or 3 rd Party Propane Supply Propane Producer Counterparty IPL Receives Propane Cost Recovery Producer Delivers propane IPL Receives Fixed Capital Fee + Operating Cost Recovery IPL PP Production Process IPL Receives Fixed Capital Fee + Operating Cost Recovery IPL Receives PP Delivery Cost Recovery IPL Receives PP Delivery Cost Recovery Polypropylene Counterparty Receives Production Propane Producer Receives PP Market Sales PP counterparties lock-in lower-cost, Alberta produced polypropylene Pay IPL a fixed capital fee as well as a propane, operating and delivery cost recovery charge to receive polypropylene Propane counterparties realize an increased netback from converting lowvalue Alberta propane into higher-value polypropylene Deliver propane and pay IPL a fixed capital fee, as well as an operating and delivery cost recovery charge in exchange for receiving a polypropylene market price 28

30 INDICATIVE PROPANE PRODUCER UPLIFT Propane Value Increase 500% 400% 415% Edmonton Propane Price $1.25 $ % $ % 166% 133% $ % 65% 29% $0.25 0% 2014* $0.00 Heartland Polypropylene Edmonton Propane (USD per USG) Propane producers would have realized a 110%* uplift in their propane value through the Heartland Complex Propane value increase based on IPL s capital fee and propane feedstock, as well as estimated operating, marketing and delivery costs *Data from April 2014 through December 2018, representing the period since the Cochin pipeline discontinued Alberta propane export service 29

31 INDICATIVE PP BUYER SAVINGS Polypropylene Savings Edmonton Propane Price 30% 26% 27% $ % 22% $ % 18% $ % 10% $0.50 6% $0.25 0% 2014* $0.00 Heartland Polypropylene Edmonton Propane (USD per USG) Polypropylene buyers would have saved 20%* through the Heartland Complex Polypropylene savings based on IPL s capital fee, propane feedstock, as well as estimated operating and delivery costs *Data from April 2014 through December 2018, representing the period since the Cochin pipeline discontinued Alberta propane export service 30

32 13% 2018 ANNUAL EBITDA 31

33 CONVENTIONAL OIL PIPELINES 3,900 km of oil pipelines servicing over 100 producers Cost-of-service, fee-based and product margin business Bow River Pipeline Central Alberta Pipeline Mid-Saskatchewan Pipeline Viking Formation East Duvernay Formation $82 million expansion of the Central Alberta Pipeline to service the East Duvernay Two 130,000 barrel oil storage tanks and related infrastructure Expected to be fully operational in Q and generate ~$20 million of annual EBITDA Opportunity for future expansions 32

34 CONVENTIONAL GROWTH OPPORTUNITIES Mainline Expansion Stettler Phase 3 EDMONTON Stettler Expansion Phase 1 HARDISTY Opportunity to expand transportation service into the preferred Edmonton market Pipeline connection from Bow River to CAPL, providing Alberta Viking, Glauconite and surrounding volumes market optionality East Duvernay Three Hills Stettler Phase 2 STETTLER Connector Pipeline Bow River to CAPL Central Alberta System Bow River System Potential Pipeline Expansion Significant potential for future infrastructure development on CAPL to support the East Duvernay Pipeline expansion into Three Hills, where production forecasts are up to 100,000 b/d Mainline expansion potentially required in order to meet forecasted production growth Combined, these opportunities represent over $600 million in growth capital over the next several years 33

35 CONVENTIONAL EBITDA $ Million $ % CAGR $200 $150 $100 $50 $ Cost-of-Service Fee-Based Product Margin 34

36 5% 2018 ANNUAL EBITDA 35

37 BULK LIQUID STORAGE Terminal Location 23 petroleum and petrochemical storage terminals across Europe SWEDEN Approximately 37 million barrels of total storage capacity IRELAND ENGLAND DENMARK NETHERLANDS GERMANY Cost-of-service and fee-based business Average utilization rate of 77%* Closed NuStar Europe acquisition Seven strategically located terminals in the Netherlands and UK Attractive purchase price multiple of ~8.9x expected average annual EBITDA Complementary to existing operations, with a meaningful entry into the Port of Amsterdam *Year ended December 31,

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39 Credit Leverage Dividends FINANCIAL OBJECTIVES 2018 Target Dividends underpinned cost-of-service and fee-based cash flow Greater than 100% Greater than 100% Payout ratio, after sustaining capital 65% Less than 80% FFO to recourse debt* 22% Greater than 19% Recourse debt to EBITDA* 3.8x Less than 4.3x Sr. recourse debt to total capitalization 52% 50% to 55% Maintain investment grade credit rating BBB+ / BBB BBB 10 years of consecutive dividend increases demonstrate dividend growth that is supported by our strong financial position *Based on Standard & Poor s calculation methodology; hybrid notes treated as 50% equity by credit rating agencies 38

40 CREDIT STRENGTH Oil Sands Transportation ($805 million) NGL Processing ($888 million) Conventional Oil Pipelines ($697 million) Bulk Liquid Storage ($203 million) 97% 84% 74% 41% 12 customers ~20 customers 100+ producers ~130 customers Remaining contract duration of 20+ years Remaining contract duration of ~5 years Typical exposure of 55 days Remaining contract duration of 1+ years Investment Grade Revenue (2018)* Non-Investment Grade Revenue (2018) Over 80% of IPL revenue is sourced from investment grade entities* *Canadian operations include investment grade counterparties or contractual rights to obtain a guarantee from an investment grade parent; European operations include subsidiaries of investment grade parents where IPL typically has the contractual right to customary security 39

41 CAPITAL STRUCTURE $ Billion $8 Target capital structure of 50% to 55% sr. recourse debt to total capitalization Credit facility covenant of 65% $6 $1.4 billion of consolidated debt is nonrecourse to IPL $4 $2 Corridor pipeline system has its own capital structure and credit ratings Flow through of interest costs to shippers IPL bank covenants and credit rating metrics exclude non-recourse debt $ Recourse Debt Non-Recourse Debt IPL Senior Corridor *Based on book values as at December 31, 2018 $750 million of subordinated hybrid notes 100% equity treatment under credit facility and 50% by credit rating agencies 78% of recourse debt is fixed rate* 40

42 $1,250 EBITDA BY BUSINESS SEGMENT $ Million $1,000 $750 $500 $250 $ Oil Sands Transportation NGL Processing Conventional Oil Pipelines Bulk Liquid Storage 41

43 CORPORATE SUSTAINABILITY Commitment to safety Zero lost time incidents Completed 33 in-line inspections covering over 1,300 km of pipeline 99% pipeline availability rate Commitment to the environment Carbon Disclosure Project filing completed for 2018 Full compliance with environmental laws and regulations Commitment to the community Maintain a robust code of ethics and whistleblower policy Strong relationships with community members and indigenous peoples Over $3.1 million and 3,000 volunteer hours contributed to various charities and community initiatives Committed to high standards of worker safety, asset integrity and environmental stewardship Information based on 2018 annual results for Canadian operations 42

44 LOOKING FORWARD Solid track record of increasing shareholder value Continued focus on developing growth opportunities Cost-of-service contracts expected to continue generating the majority of future cash flow Commodity-based cash flow to be reinvested to support growth opportunities Well-positioned to sustain dividends, with upside growth potential 43

45 CONTACT INFORMATION INTER PIPELINE LTD. SUITE 3200, 215 2ND STREET SW CALGARY, AB T2P 1M4 PHONE: 1 (866) PHONE: 1 (403) WEB: INTERPIPELINE.COM INVESTORRELATIONS@INTERPIPELINE.COM 44 44