SEP Spectra Energy Partners, LP Common Units Representing Limited Partner Interests (delisted)

Al Monaco, Chief Executive Officer | John Whelen, Chief Financial Officer November 2, 2018 Q3 2018: Financial Results & Business Update

Legal Notice Forward Looking Information This presentation includes certain forward looking statements and information (FLI) to provide potential investors, shareholders and unitholders of Enbridge Inc. (Enbridge or the Company), Enbridge Income Fund Holdings Inc. (ENF), Enbridge Energy Partners, L.P. (EEP), Enbridge Energy Management, LLC (EEQ) and Spectra Energy Partners, LP (SEP) with information about Enbridge, ENF, EEP, EEQ, SEP and their respective subsidiaries and affiliates, including management’s assessment of their future plans and operations, which FLI may not be appropriate for other purposes. FLI is typically identified by words such as “anticipate”, “expect”, “project”, “estimate”, “forecast”, “plan”, “intend”, “target”, “believe”, “likely” and similar words suggesting future outcomes or statements regarding an outlook. All statements other than statements of historical fact may be FLI. In particular, this presentation contains FLI pertaining to, but not limited to, information with respect to the following: 2018 and future year strategic priorities and guidance; expected EBITDA or expected adjusted EBITDA; expected DCF and DCF/share; expected future debt/EBITDA; future financing options; expectations on sources and uses of funds and sufficiency of financial resources; secured growth projects and future growth, development and expansion program and opportunities; expected benefits of asset dispositions; closing of announced dispositions, amalgamations and corporate simplification transactions, and the timing and impact thereof; future asset sales or other monetization transactions; sponsored vehicle strategy, including the simplification of the Company’s corporate structure and expected benefits thereof; distribution coverage; dividend and distribution growth and dividend and distribution payout expectations; expected impact of tax reform and FERC policy-related matters, including sponsored vehicle impacts; foreign exchange hedges; project execution, including capital costs, expected construction and in service dates and regulatory approvals; and system throughput, capacity, expansions and potential future capacity solutions. Although we believe that the FLI is reasonable based on the information available today and processes used to prepare it, such statements are not guarantees of future performance and you are cautioned against placing undue reliance on FLI. By its nature, FLI involves a variety of assumptions, which are based upon factors that may be difficult to predict and that may involve known and unknown risks and uncertainties and other factors which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by the FLI, including, but not limited to, the following: the expected supply of, demand for and prices of crude oil, natural gas, natural gas liquids and renewable energy; exchange rates; inflation; interest rates; availability and price of labour and construction materials; operational reliability and performance; customer and regulatory approvals; maintenance of support and regulatory approvals for projects; anticipated in-service dates; weather; governmental legislation; announced and potential disposition, amalgamation and corporate simplification transactions, and the timing and impact thereof; impact of capital project execution on the Company’s future cash flows; credit ratings; capital project funding; expected EBITDA or expected adjusted EBITDA; expected future cash flows and expected future DCF and DCF per share; estimated future dividends and distributions; financial strength and flexibility; debt and equity market conditions, including the ability to access capital markets on favourable terms or at all; cost of debt and equity capital; economic and competitive conditions; changes in tax laws and tax rates; and changes in trade agreements. We caution that the foregoing list of factors is not exhaustive. Additional information about these and other assumptions, risks and uncertainties can be found in applicable filings with Canadian and U.S. securities regulators (including the most recently filed Form 10-K and any subsequently filed Form 10-Q, as applicable). Due to the interdependencies and correlation of these factors, as well as other factors, the impact of any one assumption, risk or uncertainty on FLI cannot be determined with certainty. Except to the extent required by applicable law, we assume no obligation to publicly update or revise any FLI made in this presentation or otherwise, whether as a result of new information, future events or otherwise. All FLI in this presentation and all subsequent FLI, whether written or oral, attributable to Enbridge, ENF, EEP, EEQ or SEP, or persons acting on their behalf, are expressly qualified in its entirety by these cautionary statements. Non-GAAP Measures This presentation makes reference to non-GAAP measures, including adjusted earnings before interest, income taxes, depreciation and amortization (Adjusted EBITDA), ongoing EBITDA, distributable cash flow (DCF), ongoing DCF and DCF per share. Adjusted EBITDA represents EBITDA adjusted for unusual, non-recurring or non-operating factors on both a consolidated and segmented basis. Management uses adjusted EBITDA to set targets and to assess the performance. DCF is defined as cash flow provided by operating activities before changes in operating assets and liabilities (including changes in environmental liabilities) less distributions to non-controlling interests and redeemable non-controlling interests, preference share dividends and maintenance capital expenditures, and further adjusted for unusual, non-recurring or non-operating factors. Management also uses DCF to assess the performance and to set its dividend or distribution payout target. Management believes the presentation of these measures gives useful information to investors, shareholders and unitholders as they provide increased transparency and insight into the performance of Enbridge, ENF, EEP, EEQ and SEP. Reconciliations of forward looking non-GAAP financial measures to comparable GAAP measures are not available due to the challenges and impracticability with estimating some of the items, particularly with estimates for certain contingent liabilities, and estimating non-cash unrealized derivative fair value losses and gains and ineffectiveness on hedges which are subject to market variability and therefore a reconciliation is not available without unreasonable effort. These measures are not measures that have a standardized meaning prescribed by generally accepted accounting principles in the United States of America (U.S. GAAP) and may not be comparable with similar measures presented by other issuers. A reconciliation of non-GAAP measures to the most directly comparable GAAP measures is available on the applicable entity’s website. Additional information on non-GAAP measures may be found in the earnings news releases or additional information on the applicable entity’s website, www.sedar.com or www.sec.gov.

Agenda Progress on strategic priorities and Q3 Business update Financial results review Line 3 Replacement

Significant progress advancing key strategic priorities Progress on Strategic Priorities in 2018 First Half Q3 Strong operating and financial results $7.5B non-core asset sales announced Issued $3B hybrids SV simplification, buy-in offers Line 3 replacement MPUC approval Other project execution $1.6B placed into service Strong Q3 results $5.7B asset sales proceeds received 4.7x Debt/EBITDA vs 5.0x target (2018) Suspended DRIP (Dec.1 dividend) Reached SV buy-in agreements Combining Ontario Utilities Line 3 replacement execution Finalized route MPUC written orders received Advancing permitting process Other project execution NEXUS and Valley Crossing in service

Q3 2018 Consolidated Financial Results Summary Adjusted earnings before interest, taxes, depreciation and amortization (adjusted EBITDA) and Distributable Cash Flow (DCF) are non-GAAP measures. For more information on non-GAAP measures please refer to disclosure in the Q3 earnings release and MD&A available at www.enbridge.com. Adjusted EBITDA is not presented on a $/share basis. Adjusted EBITDA DCF Record Q3 results; full year DCF/share expected to be in the upper half of the guidance range Adjusted Earnings For the 3 and 9 months ended Sep 30, $ millions Q3: $0.82/ share $0.93/ share YTD: $2.61/ share $3.40/ share Q3: $0.39/ share $0.55/ share YTD: $1.33/ share $2.01/ share $1,324 Q1 $3,165 Q2 $1,858 Q1 Q2 $1,094 Q1 Q2 13% 30% 41% 51% $2,586 Q3 $1,334 Q3 $632 Q3 $1,585 $2,958 $933

Enterprise-wide Secured Growth Project Inventory Segments: Liquids Pipelines GTM – US Transmission GTM – Canadian Transmission Gas Distribution Green Power & Transmission Project Expected ISD Capital ($B) 2019 Stratton Ridge 1H19 0.2 USD PennEast 2H19 0.3 USD Hohe See Wind & Expansion – Germany 2H19 1.1 CAD Line 3 Replacement – Canadian Portion 2H19 5.3 CAD Line 3 Replacement – U.S. Portion 2H19 2.9 USD Southern Access to 1,200 kbpd 2H19 0.4 USD Utility Core Capital 2019 0.8 CAD 2019 TOTAL $13B* 2020 T-South Expansion 2020 1.0 CAD Spruce Ridge 2020 0.5 CAD Utility Core Capital 2020 0.7 CAD 2020 TOTAL $2B* TOTAL Capital Program $22B* * Rounded, USD capital has been translated to CAD using an exchange rate of $1 U.S. dollar = $1.30 Canadian dollars. Project Expected ISD Capital ($B) 2018 High Pine In service 0.4 CAD Stampede Lateral In service 0.2 USD Wyndwood In service 0.2 CAD Rampion Wind – UK In service 0.8 CAD RAM In service 0.5 CAD NEXUS In service 1.3 USD TEAL In service 0.2 USD Other Misc. Liquids In service 0.1 CAD Valley Crossing Pipeline In service 1.6 USD Atlantic Bridge In service + 4Q18 0.6 USD STEP/Pomelo Connector 4Q18 0.4 USD Utility Core Capital 2018 0.5 CAD 2018 TOTAL $7B* $22B of diversified low-risk secured projects supports and extends cash flow growth

New Projects in Service Natural Gas: NEXUS/TEAL - US$1.5B Natural Gas: Valley Crossing - US$1.6B Providing Marcellus and Utica natural gas to markets in Ohio, Michigan and Ontario In service October 2018 ~1.4 Bcf/day of capacity Providing export capacity to support Mexican demand Header system in service November 2018 Mexican exports to begin in coming months ~2.6 Bcf/day of capacity The major gas pipeline projects came into service in Q4 PERMIAN Valley Crossing Pomelo Connector Mexico TX Gulf Coast Express Texas Eastern TORONTO NEXUS Dawn Hub Vector Texas Eastern MI ON PA OH Parkway TEAL NY

Line 3 Replacement Project Update Critical $9B infrastructure replacement project Canadian construction program well underway > 850 km of pipeline now laid (over 80%) Wisconsin segment complete and in-service ~13 mile segment Minnesota PUC approved issuing a Certificate of Need and Route Permit substantially along Enbridge’s preferred route with minor modifications and certain conditions Written Orders delivered by MPUC; remaining permit applications now submitted to various agencies Next steps: Q4 2018: Ongoing state and federal permitting process Q1 2019: Begin construction 2H 2019: Expected in-service Execution progressing well; continue to target in-service date in the second half of 2019 Edmonton Hardisty Kerrobert Gretna ND WI MN Regina Construction complete In service segments to date Approved MN route Superior

WCSB Crude Oil Market Fundamentals Liquids Pipelines Business Update Restoring Capacity 2H2019 Capacity (KBPD) Line 3 Replacement +375 Incremental Capacity Post Line 3 System DRA Optimization +75 BEP Idle +100 Incremental Capacity 2020+ Line 4 Capacity Restoration +25 System Station Upgrades +100 Southern Lights (Line 13) Reversal +150 Total Potential Incremental Capacity +825 WCSB Oil Price Differentials ($US/bbl) Enbridge’s Potential Pipeline Solutions Challenging near-term fundamentals, however, Enbridge can provide significant relief with Line 3 Replacement and potential future incremental capacity solutions Western Canada Oil Supply Forecasts (KBPD)

Union Gas EGD TORONTO DETROIT Dawn Storage Hub ON QC NY MI MN OTTAWA Proceeding with Amalgamation Utilities Business Update OEB Approved Incentive Framework Provides regulatory certainty Allows control and flexibility over operations Enables significant efficiencies One of the Largest Utility Franchises in North America Customers (million) New Customers (in 2017) Rate Base ($B) EGD 2.2 ~30,000 $5.9 Union Gas 1.5 ~22,000 $4.8 TOTAL 3.7 ~52,000 $10.7 Scale of Amalgamation Incentive Rate Structure Term 5 years Annual Inflation GDP IPI FDD Stretch Factor 0.3% Earnings Sharing Threshold Earnings sharing at 50/50 above 150 basis points over the OEB-approved ROE (beginning in Year 1) Unbudgeted Capital Expenditures Incremental Capital Module Effective Date January 1, 2019

Expect no material impact from FERC policy statement changes FERC Update and Outlook Gas Transmission Business Update No material financial impact from FERC policy actions Does not impact pipelines in corporate structures Does not impact negotiated rate agreements 501-G filings demonstrate ROE’s within appropriate range Texas Eastern rate case on track to be filed by end of year Potential for revenue enhancement with updated cost of service factors US Gas Transmission FERC Filings U.S. Transmission

Executing on Plan to Simplify Structure Sponsored Vehicles Benefits for SV Shareholders Direct ownership in largest energy infrastructure Company in North America Enhanced dividend coverage Diverse opportunity set for growth beyond 2020 Stronger balance sheet and enhanced credit profile Enhanced trading liquidity Benefits for ENB Shareholders Simplifies corporate & capital structure Increased ownership of core strategic assets Higher retention of cash flow Enhanced credit and funding profile Accretive to post-2020 financial outlook Targeted Timeline

Consolidated Adjusted EBITDA Performance Q3 2018 Liquids Pipelines + Higher throughput and IJT on the Mainline System + Higher average rate on Canadian Mainline FX hedges + New projects placed into service Gas Transmission and Midstream + New projects placed into service + Favourable commodity prices Absence of EBITDA from asset sales Gas Distribution + Rate base and customer growth + New projects placed into service Green Power and Transmission + Higher wind resources on the Canadian wind farm portfolio Energy Services + Wider location and quality differentials Eliminations & Other Higher hedge settlement losses Adjusted EBITDA (C$ Millions, except per share amounts) 3Q17 3Q18 Liquids Pipelines 1,353 1,633 Gas Transmission and Midstream 941 1,038 Gas Distribution 238 259 Green Power and Transmission 68 73 Energy Services (24) 10 Eliminations and Other 10 (55) Consolidated Adjusted EBITDA1 2,586 2,958 Consolidated Adjusted Earnings1 632 933 Adjusted EPS1 $0.39 $0.55 (1) Adjusted EBITDA, adjusted earnings, and adjusted EPS are non-GAAP measures. Reconciliations to GAAP measures can be found in the Q3 earnings release available at www.enbridge.com.

Consolidated DCF Performance Q3 2018 (1) Adjusted EBITDA, DCF and DCF per share are non-GAAP measures. Reconciliations to GAAP measures can be found in the Q3 earnings release available at www.enbridge.com (C$ Millions, except per share amounts) 3Q17 3Q18 Consolidated Adjusted EBITDA1 2,586 2,958 Maintenance capital (360) (324) Interest expense (646) (705) Current income tax (22) (71) Distributions to non-controlling and redeemable non-controlling interests (267) (302) Cash distributions in excess of equity earnings 67 90 Preferred share dividends (82) (94) Other receipts of cash not recognized in revenue 60 53 Other non-cash adjustments (2) (20) DCF1 1,334 1,585 Weighted Average Shares Outstanding (Millions) 1,635 1,705 DCF per Share1 $0.82 $0.93 3Q18 vs. 3Q17 DCF Adjusted EBITDA drivers noted in previous slide Higher maintenance capital on specific Gas Transmission programs in Q3 2017 New equity investments placed into service in 2017 resulting in higher equity distributions Higher financing costs from incremental financing instruments issued Higher distributions to NCI due to increased public ownership and higher distributions within the Fund Group

Financial Guidance Reiteration Strong year to date performance expected to drive full year DCF/share to the upper half of guidance range Adjusted EBITDA is a non-GAAP measure. Reconciliations to GAAP measures can be found in the Q3 earnings release available at www.enbridge.com. $3.68 2018 DCF/share Outlook Q3 YTD ~$12,500 ~21% Consolidated EBITDA Outlook ($MM) Q3 YTD 17% 10% Dividend CAGR through 2020 1 2 2018 EBITDA & DCF/share Guidance 10% CAGR

3Q18 vs. 3Q17 DCF Analysis Increased earnings from expansion projects placed into service Higher operating and pipeline integrity costs and maintenance capital expenditures Higher equity earnings (including expansion projects under construction in 2017 and not yet generating cash distributions) Spectra Energy Partners (SEP) Ongoing EBITDA and Ongoing Distributable Cash Flow are non-GAAP measures. Reconciliations to GAAP measures can be found in the SEP Q3 earnings release and Reg G schedule available at www.spectraenergypartners.com. 1) As reported, after internal adjustments for trailing 12 months. (US$ millions, except per unit amounts) Q3 2017 Q3 2018 Ongoing EBITDA 554 561 Ongoing DCF 398 364 Distribution Coverage (as declared) 1.2x 1.0x Debt/EBITDA1 4.1x 4.1x Distribution per unit (as declared) $0.72625 $0.77625 Financial Results

Enbridge Energy Partners (EEP) Adjusted EBITDA and DCF are non-GAAP measures. Reconciliations to GAAP measures can be found in the supplemental slides available at www.enbridgepartners.com 1) As reported, after internal adjustments for trailing 12 months. 3Q18 vs. 3Q17 DCF Analysis Increased throughput on Bakken Pipeline System Reduced income tax allowance recovery pursuant to US Tax Reform & FERC policy updates (US$ millions, except per unit amounts) Q3 2017 Q3 2018 Adjusted EBITDA 426 403 DCF 194 184 Distribution Coverage (as declared) 1.2x 1.1x Consolidated Debt/EBITDA1 4.2x 4.5x Distribution per unit (as declared) $0.350 $0.350 Financial Results

Enbridge Income Fund Holdings (ENF) & Fund Group Adjusted EBITDA and DCF are non-GAAP measures. Reconciliations to GAAP measures can be found in the ENF Q3 earnings release and MD&A available at www.enbridgeincomefund.com. 1) As reported, after internal adjustments for trailing 12 months. 3Q18 vs. 3Q17 Fund Group DCF Analysis Higher residual toll and higher throughput on Canadian Mainline Higher FX hedge rates New projects placed into service – Regional Oil Sands System Solid contribution from Alliance Pipeline and Green Power assets Financial Results (C$ millions) Q3 2017 Q3 2018 Fund Group DCF 488 716 Distributions Declared 404 499 Fund Group Debt/EBITDA1 5.7x 3.8x Fund Group Payout Ratio 83% 70% ENF Adjusted Earnings 77 113

(1) Includes amounts “pre-funded” in December 2017 (2) Twelve month trailing Debt: EBITDA as calculated by Management.. Consolidated Debt to EBITDA Profile2 As presented at ENB Days 2017 2018 – 2020 Secured Funding Plan1($C billions) Capital Expenditures Sr. Debt Reduction Internal cash flow net of dividends Common equity Hybrid securities Asset sales $2 2018e DRIP $3 $7.5 $1 Optional hybrid securities Optional asset sales Further Funding Progress Strong YTD financial performance $5.7B cash proceeds from non-core assets Internally generated equity now sufficient to support secured capital program Deleveraging ahead of plan DRIP suspended effective December 1, 2018 dividend Increased Financing Flexibility Significant funding flexibility created to finance capital plan while delevering Funding Plan Execution Long Term Target: ≤ 5.0x 2018 Q3 TTM Consolidated Debt to EBITDA: 4.7x

1. Move to pure regulated pipelines/ utility model $7.5B of non-core asset sales announced in 2018 Original target $3B 2. Accelerate de-leveraging $5.7 billion of asset sales proceeds received in Q3 Achieved 5.0x Debt-to-EBITDA target level 4.7x consolidated Debt-to-EBITDA as at Q3 Suspending the DRIP effective Dec 1 3. Deliver reliable cash flow & dividend per share growth Excellent financial and operating performance across all business units Expect to be in top half of 2018 DCF/share guidance range of $4.15 to $4.45/share $7B projects coming into service in 2018 Line 3 Replacement Project execution progressing well 4. Streamline the business Entered into definitive agreements to buy-in SEP, EEP, EEQ, ENF Proceeding with amalgamation of Union Gas and EGD as approved by the Ontario Energy Board 5. Extend growth beyond 2020 Ongoing development of new project opportunities Executing on our 2018-2020 Strategic Priorities YTD Actions Priorities Q3 Summary

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