FORWARD-LOOKING INFORMATION

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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 news release 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 particular 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 forwardlooking 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-GAPP 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 Operates world-scale energy infrastructure assets Stable in an uncertain market, with a strong balance sheet and investment grade credit rating Sustainable dividend profile that has upside growth potential Well-positioned to capitalize on future growth opportunities 2

4 WORLD SCALE ENERGY INFRASTRUCTURE ASSETS Oil Sands Transportation NGL Processing Conventional Oil Pipelines Bulk Liquid Storage 2018 September YTD EBITDA 47% 33% 15% 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* *Subject to NuStar Europe acquisition closing, which was announced October 30, 2018 and is expected to close in Q

5 AREAS OF OPERATION 2018 September YTD EBITDA 5% 95% Canada Europe Existing Inter Terminals NuStar Europe Terminals SWEDEN DENMARK IRELAND ENGLAND NETHERLANDS GERMANY 4

6 LOW RISK BUSINESS STRATEGY WELL DIVERSIFIED Large-scale and strategically located assets Capital-efficient growth opportunities OPERATIONAL EXCELLENCE Exceptional EH&S performance and reliability Industry-leading project execution DIVIDEND GROWTH & STABILITY 10 years of consecutive dividend increases 10 year dividend CAGR ~7% STABLE CASH FLOW 68% of EBITDA from cost-of-service and fee-based contracts Majority investment grade counterparties STRONG FINANCIAL POSITION Solid balance sheet Excellent access to capital markets Investment grade credit rating 5

7 DIVIDEND GROWTH $ 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 2019F 7.3% CAGR F 2018F and 2019F based on actual dividends to November 2018 and $ per share per month thereafter 6

8 DIVIDEND STABILITY $ Million $1,000 $800 $600 $400 $200 $ FFO Dividend FFO Dividend FFO Dividend FFO Dividend FFO Dividend FFO Dividend Oil Sands Transportation Conventional Oil Pipelines Bulk Liquid Storage NGL Processing FFO is attributable to shareholders and before sustaining capital; corporate costs allocated based on IPL assumptions 7

9 RECENT DEVELOPMENTS Announced acquisition of NuStar Europe for ~$354 million, which is expected to add 33% to total European storage capacity Dividend increased to $1.71 per share annually, marking 10 years of consecutive dividend increases NGL Processing generated record quarterly funds from operations (FFO) of $135 million Spending $82 million to expand the Central Alberta Pipeline system in order to better service the East Duvernay basin Constructing Canada s first integrated Propane Dehydrogenation (PDH) & Polypropylene (PP) complex for $3.5 billion 8

10 2018 September YTD EBITDA 47% 9

11 OIL SANDS TRANSPORTATION AOSP IMPERIAL KEARL HUSKY SUNRISE SUNCOR AOC HANGINGSTONE JACOS / NEXEN HANGINGSTONE Three major oil sands pipeline systems with a combined ultimate capacity of 4.6 million b/d Corridor Cold Lake LAMONT TERMINAL CNR KIRBY NORTH CNR KIRBY SOUTH CNR PRIMROSE / WOLF LAKE BRUDERHEIM FACILITY FCCL CHRISTINA LAKE FCCL NARROWS LAKE FCCL FOSTER CREEK OSUM ORION IMPERIAL COLD LAKE Polaris 3,300 km of pipeline and 3.8 million barrels of storage Substantial available capacity for 3 rd party growth projects Over 20 years remaining on cost-of-service contracts Approximately 40 years if extension provisions exercised 10

12 CORRIDOR PIPELINE CAPACITY 000 s b/d 1,400 1,400 1,200 1, POTENTIAL 3 RD PARTY CAPACITY** CONTRACTED VOLUMES 0 Current Throughput* Installed Capacity Ultimate Capacity *YTD September 30, 2018 **Subject to existing shipper approval 11

13 COLD LAKE PIPELINE CAPACITY 000 s b/d 1,800 2,000 1,600 AVAILABLE CAPACITY 1,900 ~645 1,400 1,200 1, CONTRACTED VOLUMES ~1, Original Cold Lake FCCL CNR Kirby North & South Osum Orion Ultimate Capacity 12

14 POLARIS PIPELINE CAPACITY 000 s b/d 1, AVAILABLE CAPACITY 1,300 ~ CONTRACTED VOLUMES ~ FCCL Imperial Kearl Husky Sunrise CNR Kirby North & South JACOS Hangingstone AOC Hangingstone Ultimate Capacity 13

15 ATTRACTIVE BOLT-ON PROJECT MULTIPLES Total Capital ($ Million) $ x 6.0x 4 PROJECTS $300 Over $580 million in announced bolt-on oil sands connections $ x 4.0x 4 PROJECTS 11 connections executed, with an average EBITDA multiple of ~3.2x $100 $0 < 2.0x 3 PROJECTS EBITDA Multiple Range Identified growth opportunities largely composed of bolt-on projects 14

16 OVER-BUILD STRATEGY (000 s b/d) Contracted Available Ultimate Cold Lake 1, ,900 Corridor * 1,400 Polaris ,300 Total Capacity 2,255 2,345 4,600 Successful expansion of the Cold Lake and Polaris pipeline systems increased total available capacity to 2.3 million b/d Over-build economics supported by existing contracts Well-positioned to accommodate high return bolt-on projects Identified ~$3 billion of long-term potential oil sands opportunities *Subject to existing shipper approval 15

17 COMPETITIVE ADVANTAGE Less regulatory risk Less capital risk Less schedule risk Greater flexibility to accommodate small & large scale projects 16

18 2018 September YTD EBITDA 33% 17

19 NGL PROCESSING Pioneer I & II Large-scale NGL infrastructure 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 Three straddle plants strategically located on the TransCanada Alberta System Two offgas plants that have dedicated supply agreements Boreal pipeline with low cost expansion up to 125,000 b/d Ethane-plus fractionation at Redwater Heartland Petrochemical Complex development totaling ~$3.5 billion Expected in-service date of late 2021 *50% working interest in the Empress V facility 18

20 $1.20 COCHRANE FRAC-SPREAD USD per USG $1.00 $0.80 $0.60 Average: $0.54 $0.40 $0.20 $ Frac Spread: Mont Belvieu NGL less AECO Natural Gas Applicable to propane-plus sales from the Cochrane Straddle Plant; data from January 2015 through September

21 OFFGAS COMPOSITION & FRAC-SPREADS USD per USG $2.10 Redwater Olefinic Fractionator Volume Composition* $1.80 Olefinic NGL 23% $1.50 Average: $1.63 Polymer grade propylene 11% Alky feed 8% $1.20 Olefinic condensate 4% $0.90 Paraffinic NGL 36% $0.60 Average: $0.72 Propane 29% $0.30 Normal butane 7% $0.00 Jan-17 Q1 Apr-17 Q2 Jul-17 Q3 17 Oct-17 Q4 17 Jan-18 Q1 18 Apr-18 Q2 18 Jul-18 Q3 18 Ethane-ethylene 41% Olefinic Indicative Frac-Spread Paraffinic Indicative Frac-Spread *YTD September 30, 2018; composition based on production volumes, which may differ from sales volumes 20

22 OFFGAS PROCESSING, PDH & PP OVERVIEW AECO AECO Offgas Plants Offgas Offgas 1 Boreal Pipeline Boreal Pipeline Ethane- Ethylene Mix Redwater Olefinic Fractionator Redwater Propane Propane Producers 3 rd Party Propane PDH Facility Polymer Grade Propylene (PGP) 2 PP Facility PP Marketed Products PP Consumers Or Marketers 1 2 Extraction of ethane-plus from offgas received directly from Suncor and CNRL Horizon upgraders The ethane-plus mix is transported to the Redwater Olefinic Fractionator (ROF) via the Boreal pipeline system where it is fractionated PDH Facility to consume ~22,000 b/d of propane, including up to ~12,000 b/d of high-purity propane sourced from ROF, to produce 525 kilotonnes per annum (KTA) of PGP PP Facility to consume 525 KTA of PGP to produce 525 KTA of polypropylene 21

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24 HEARTLAND PETROCHEMICAL COMPLEX Transformational growth opportunity Complex to produce polypropylene, a highvalue and easy to transport plastic Expected to add ~$450 to ~$500 million of average annual EBITDA Accretive to future FFO per share Target 70% to 85% of processing capacity to be underpinned by take-or-pay contracts Alberta produced PP expected to have one of the lowest cash costs in North America Long-term, low-cost feedstock advantage Majority of PP production to be sold into US markets, which are expected to have among the highest prices globally 23

25 POLYPROPYLENE DEMAND 2016 World Demand for Major Polymers 2016 North American Demand for Polypropylene Polypropylene 26% Mexico 17% Canada 6% Other Major Polymers 74% United States 77% PP is the world s single largest polymer 2016 global demand of 67,000 KTA Demand forecast to increase 25% to 84,000 KTA by 2021 United States is the primary market for PP in North America 2016 North America demand of 8,100 KTA Demand forecast to increase 13% to 9,100 KTA by 2021 Source: IHS Markit Materials 24

26 PROJECT STATUS De-risked approximately 40% of $3.5 billion project cost Based on lump-sum contracts, firm purchase orders, and substantially completed time and materials works Well-advanced PDH project Detailed engineering substantially complete Over $500 million lump-sum/unit rate contract for construction awarded to Kiewit Piling activities are complete, with concrete and fabrication work well underway PP development is progressing on schedule and on budget FEED is complete Detailed engineering phase in progress 25

27 PROJECT EXECUTION IPL is in a strong position to construct the Heartland Petrochemical Complex Lack of major project development in Alberta results in favorable engineering, procurement and construction environment, including availability of skilled labour Project workforce is fully mobilized on-site, operating with a team that has both petrochemical and Alberta large-project experience Successful track record of completing large-scale construction projects, with over $6.4 billion of developments completed in the last 10 years Engineering and procurement firms chosen with global petrochemical experience, utilizing proven technology PDH Fluor has completed 20 petrochemical facilities since 2000 that are up to 1,500 KTA in size Honeywell UOP s Oleflex technology has been in commercial use since 1990 and is utilized in 19 other PDH facilities globally PP Linde Engineering has extensive expertise with 12 operating and seven planned polyolefin facilities Grace UNIPOL technology is operating in 55 PP reactor lines worldwide 26

28 CAPITAL PROFILE & FINANCING STRATEGY $ Million Total project cost of ~$3.5 billion ~$2,405 Debt / Hybrid Financing (60%) Capacity available under existing $1.5 billion committed credit facility Periodic issuance of new term debt Hybrid debt securities ~$ % equity treatment under credit facility and up to 50% by credit rating agencies Equity Financing (40%) Undistributed cash flow from operations ~$270 Invested 2018F 2019F-2021F As at Q Q4 NGL Processing segment has generated record FFO for the past four quarters Premium DRIP generates ~$300 million annually If strong financial performance continues, expected to be in a position to suspend the Premium DRIP by the end of

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% 465% Edmonton Propane Price $ % $ % $ % 193% $ % 71% 41% $0.25 0% 2014* $0.00 Heartland Polypropylene Edmonton Propane (USD per USG) Propane producers would have realized a 115%* uplift in their propane value through the Heartland Complex Propane value increase based on IPL s capital fee, propane feedstock, as well as estimated operating, marketing and delivery costs *Data from April 2014 through December 2017, representing the period since the Cochin pipeline discontinued Alberta propane export service 29

31 INDICATIVE PP BUYER SAVINGS Polypropylene Savings 30% 28% Edmonton Propane Price $ % 24% $ % 19% $ % 12% $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 2017, representing the period since the Cochin pipeline discontinued Alberta propane export service 30

32 HEARTLAND COMPLEX ADVANTAGE Propane Value Increase 125% 100% Heartland Complex Edmonton Propane Price $1.25 $ % 50% West Coast Export $0.75 $ % $0.25 0% $0.00 Apr * Apr Apr Apr Heartland Polypropylene West Coast Export to Asia Edmonton Propane (USD per USG) Propane producers would have earned ~2x* the uplift by converting their propane to PP versus exporting to Asian markets Heartland PP value increase based on IPL s capital fee, propane feedstock, as well as estimated operating, marketing and delivery costs West Coast Export value increase assumes Northeast Asia propane price less $0.35 USD per USG for rail, terminal and shipping costs *Data from April 2014 through December 2017, representing the period since the Cochin pipeline discontinued Alberta propane export service 31

33 PROPANE FEEDSTOCK SUPPLY ADVANTAGE 000 s b/d IPL PDH & PP in-service Sustainable Canadian propane feedstock advantage Over the long term the Canadian propane market is expected to remain oversupplied F 2025F 2030F 2035F Supply expected to grow as producers continue to drill for liquids rich gas Demand increases from IPL s Heartland Complex and potential West Coast exports alone do not balance the propane market Sufficient domestic propane supply for multiple PDH facilities Base Propane Demand Canadian Export to US IPL PDH Feedstock Potential West Coast Export Source: IHS Markit Materials and IPL estimates 32

34 Delivered Cash Cost* NORTH AMERICAN COST COMPETITIVENESS USD per metric ton $1, F PP Price $1,200 $1,000 Indicative Margin $800 $600 $400 $200 $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 33

35 2018 September YTD EBITDA 15% 34

36 CONVENTIONAL OIL PIPELINES 3,900 km of oil pipelines servicing over 100 producers 100% cost-of-service, fee-based and product margin business $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 35

37 CONVENTIONAL GROWTH OPPORTUNITIES Mainline Expansion EDMONTON Stettler Expansion STETTLER HARDISTY 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 Potential to expand mainline required to support production growth forecasts East Duvernay Three Hills Connector Pipeline Additional opportunity to expand transportation service into the preferred Edmonton market Pipeline connection from Bow River to CAPL, provides Alberta Viking, Glauconite and surrounding volumes market optionality Central Alberta System Bow River System Potential Pipeline Expansion Combined, these opportunities could represent over $600 million in capital over the next several years 36

38 CONVENTIONAL EBITDA $ Million $ % CAGR $150 $75 $ Oil Gathering Hardisty Midstream Marketing 37

39 250 CONVENTIONAL THROUGHPUT 000 s b/d Mid-Saskatchewan Bow River Central Alberta YTD Q3 38

40 2018 September YTD EBITDA 5% 39

41 BULK LIQUID STORAGE Existing Inter Terminals NuStar Europe Terminals 23 petroleum and petrochemical storage terminals across Europe** SWEDEN Approximately 37 million barrels of total storage capacity** Clydebank Grangemouth DENMARK 100% cost-of-service and fee-based business Belfast IRELAND Eastham Runcorn Amsterdam ENGLAND NETHERLANDS Grays GERMANY Average utilization rate of 80%* Announced NuStar Europe acquisition Seven strategically located coastal 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 *YTD September 30, 2018; does not include NuStar Europe **Subject to NuStar Europe acquisition closing, which was announced October 30, 2018 and is expected to close in Q

42 CAPACITY UTILIZATION Utilization (%) 100% Storage (Million barrels) 30 80% 24 60% 18 40% 12 20% 6 0% 0 Q Q Q Q Q Q UK, Ireland & Germany Denmark Sweden Consolidated Utilization 41

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44 Credit & Leverage Dividends FINANCIAL OBJECTIVES 2017 YTD Q F Dividends to be underpinned by cost-of-service and fee-based cash flow Greater than 100% Greater than 100% Greater than 100% Maintain a payout ratio of less than 80% after sustaining capital Less than 66% 63% 80% Consolidated net debt to total capitalization between 50% to 55% Less than 53% 52% 55% Maintain S&P investment grade credit rating of BBB+ or higher BBB+ BBB+ BBB+ 10 years of consecutive dividend increases demonstrate dividend growth that is supported by our strong financial position 43

45 FINANCIAL DISCIPLINE Total Recourse Debt* as at September 30, % 70% 60% 50% Consolidated Net Debt to Total Capitalization Covenant: Max 65% 40% 30% 85% Fixed Rate Recourse Debt Floating Rate Recourse Debt 20% 10% 0% Q Committed to maintaining strong investment grade credit rating *Based on book values 44

46 CREDIT STRENGTH Oil Sands Transportation ($802 million) NGL Processing ($720 million) Conventional Oil Pipelines ($517 million) Bulk Liquid Storage ($221 million) 98% 90% 66% 38% 12 customers ~20 customers 100+ producers ~120 customers Remaining contract duration of 20+ years Remaining contract duration of ~6 years Typical exposure of 55 days Remaining contract duration of ~1 year Investment Grade Revenue (2017)* Non-Investment Grade Revenue (2017) 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 45

47 YTD Q EBITDA BY CONTRACT TYPE Cost-of-Service $514 million Fee-Based 55% Oil Sands Transportation ($439 million) 100% NGL Processing ($311 million) 11% 4% $123 million Commodity-Based 13% 85% $265 million Product Margin $36 million 28% 4% Conventional Oil Pipelines ($142 million) 26% 20% Bulk Liquid Storage ($46 million) 27% Total EBITDA: $938 million 54% 73% Approximately 70% of consolidated EBITDA is generated from cost-of-service and fee-based contracts YTD September 30,

48 MTN MATURITY PROFILE $ Million $1,000 Weighted average: cost of debt of ~3.6%; maturity of ~8 years $750 $500 $250 $ Manageable debt maturity profile limits refinancing risk 47

49 EBITDA BY BUSINESS SEGMENT $ Million $1,200 $1,000 $800 $600 $400 $200 $ Oil Sands Transportation Conventional Oil Pipelines Bulk Liquid Storage NGL Processing 48

50 CORPORATE SUSTAINABILITY Commitment to safety Zero lost time incidents Completed 34 in-line inspections covering over 2,200 km of pipeline 99.99% reliable delivery rate Commitment to the environment Filed inaugural sustainability report 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 $2.7 million and 2,200 volunteer hours contributed to various charities and community initiatives Committed to high standards of worker safety, asset integrity and environmental stewardship Information based on 2017 annual results for Canadian operations 49

51 LOOKING FORWARD Solid track record of increasing shareholder value Continued focus on developing potential growth opportunities Cost-of-service contracts expected to continue generating the majority of future cash flow Fee-based and cost-of-service cash flow alone should support future dividends Well-positioned to sustain dividends, with upside growth potential 50

52 CONTACT INFORMATION SUITE 3200, 215 2ND STREET SW CALGARY, ALBERTA T2P 1M4 PHONE: 1 (866) PHONE: 1 (403) FAX: 1 (403) WEB: INTERPIPELINE.COM INVESTORRELATIONS@INTERPIPELINE.COM 51