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Legal notice Forward Looking Information This presentation includes certain forward-looking statements and information (FLI) to provide potential investors and shareholders of Enbridge Inc. (Enbridge or the Company) with information about Enbridge and its 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: Enbridge’s strategic plan, priorities and outlook; 2025 financial guidance and near and medium term outlooks, including average annual growth rate, distributable cash flow (DCF) per share, adjusted EBITDA and adjusted earnings per share (EPS), and expected growth thereof; expected dividends, dividend growth and dividend policy; expected supply of, demand for, exports of and prices of crude oil, natural gas, natural gas liquids (NGL) , liquefied natural gas (LNG), renewable natural gas (RNG), and renewable energy; energy transition and our approach thereto, including emissions reduction goals; industry and market conditions; anticipated utilization of our assets; expected EBITDA and adjusted EBITDA; expected DCF and DCF per share; expected EPS; expected future cash flows, including free cash flow; expected shareholder returns and returns on capital; expected performance of the Company’s businesses, including customer growth, organic growth opportunities and optimization initiatives; financial strength, capacity and flexibility; financial priorities and outlook; expectations on sources of liquidity and sufficiency of financial resources; expectations on leverage, including debt-to-EBITDA outlook and target range; expected costs, in- service dates and final investment decisions for announced projects, projects under construction and system expansion, optimization and modernization; capital allocation priorities; investment capacity; expected future growth and expansion opportunities, including secured growth program, and development opportunities and strategy; and toll and rate case proceedings and frameworks, including with respect to ongoing and expected rate cases in Ontario, Ohio and North Carolina. Although we believe that the FLI is reasonable based on the information available 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, 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, NGL, LNG, RNG and renewable energy; energy transition, including the drivers and pace thereof; global economic growth and trade; anticipated utilization of our assets; exchange rates; inflation; interest rates; tax laws and tax rates; availability and price of labour and construction materials; the stability of our supply chain; operational reliability and performance; customer, regulatory and stakeholder support and approvals; anticipated in-service dates and final investment decisions; weather; announced and potential acquisition, disposition and other corporate transactions and projects; governmental legislation; evolving government trade policies, including potential and announced tariffs, duties, fees, economic sanctions, or other trade measures; litigation; credit ratings; hedging program; expected EBITDA and adjusted EBITDA; expected earnings/(loss) and adjusted earnings/(loss); expected future cash flows, including free cash flow; expected future DCF and DCF per share; estimated future dividends; financial strength and flexibility; debt and equity market conditions; general economic and competitive conditions; the ability of management to execute key priorities; and the effectiveness of various actions resulting from the Company’s strategic priorities. 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. 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, or any of its subsidiaries or affiliates, or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements. Non-GAAP Measures This presentation makes reference to non-GAAP and other financial measures, including earnings before interest, income taxes, depreciation and amortization (EBITDA), adjusted EBITDA, adjusted earnings and adjusted earnings per share (EPS), distributable cash flow (DCF) and DCF per share, free cash flow and debt-to-EBITDA. Management believes the presentation of these metrics gives useful information to investors and shareholders as they provide increased transparency and insight into the performance of the Company. Adjusted EBITDA represents EBITDA adjusted for unusual, infrequent or other non-operating factors on both a consolidated and segmented basis. Management uses EBITDA and adjusted EBITDA to set targets and to assess the performance of the Company and its business units. Adjusted earnings represent earnings attributable to common shareholders adjusted for unusual, infrequent or other non-operating factors included in adjusted EBITDA, as well as adjustments for unusual, infrequent or other non-operating factors in respect of depreciation and amortization expense, interest expense, income taxes and non-controlling interests on a consolidated basis. Management uses adjusted earnings as another measure of the Company’s ability to generate earnings. DCF is defined as cash flow provided by operating activities before the impact of changes in operating assets and liabilities (including changes in environmental liabilities) less distributions to non-controlling interests, preference share dividends and maintenance capital expenditures, and further adjusted for unusual, infrequent or other non-operating factors. Management also uses DCF to assess the performance of the Company and to set its dividend payout target. Free cash flow represents DCF less dividends and is used by Management as a measure of cash available to spend and in the calculation of Enbridge’s investment capacity, or the Company’s ability to invest cash without increasing leverage above the applicable target range. Debt-to-EBITDA is used as a liquidity measure to indicate the amount of adjusted earnings available to pay debt (as calculated on a GAAP basis) before covering interest, tax, depreciation and amortization. Reconciliations of forward-looking non-GAAP and other financial measures to comparable GAAP measures are not available due to the challenges and impracticability of estimating certain items, particularly certain contingent liabilities and non-cash unrealized derivative fair value losses and gains which are subject to market variability. Because of those challenges, reconciliations of forward-looking non-GAAP and other financial measures are not available without unreasonable effort. The non-GAAP measures described above are not measures that have standardized meaning prescribed by generally accepted accounting principles in the United States of America (U.S. GAAP) and are not U.S. GAAP measures. Therefore, these measures may not be comparable with similar measures presented by other issuers. A reconciliation of historical non-GAAP and other financial measures to the most directly comparable GAAP measures is available on the Company’s website. Additional information on non-GAAP and other financial measures may be found in the Company’s earnings news releases or in additional information on the Company’s website, www.sedarplus.ca or www.sec.gov. Unless otherwise specified, all dollar amounts in this presentation are expressed in Canadian dollars, all references to “dollars” or “$” are to Canadian dollars and all references to “US$” are to US dollars. 2
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3 Safety moment Building Evacuation Procedures
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Agenda 4 Welcome & Introduction Rebecca Morley 9:00 Strategic Overview & Priorities Greg Ebel 9:10 Liquids Pipelines Colin Gruending 9:30 Gas Transmission Cynthia Hansen 9:55 Gas Distribution & Storage Michele Harradence 10:20 Renewable Power Matthew Akman 10:40 Financial Outlook Pat Murray 11:00 Closing Remarks Greg Ebel 11:20 Eastern Time
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6 First-choice energy provider Strategically positioned to serve all forms of energy demand Visible growth through end of the decade Disciplined capital allocation L Liquids pipeline Natural Gas pipeline Liquids storage Natural Gas storage Wind farms - onshore & offshore Solar energy operations RNG LNG facility Gas Distribution & storage R L L UK France Germany
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7 Key accomplishments over the past two years Strong execution increased growth visibility and supported strong shareholder returns Execution on commitments Strategic extensions Closed and financed the $19B generational acquisition of three U.S. gas utilities Recorded strong business results and placed $7B of capital into service Transported record Mainline volumes Recycled ~$3B of capital Delivered ~$250M of cost optimizations Achieved financial guidance for the 19th consecutive year Increased dividend for the 30th consecutive year advancing Dividend Aristocrat status Added ~120 Bcf of natural gas storage through development and acquisitions Enhanced Permian crude oil footprint through acquisition and expansions Advanced Permian natural gas strategy through JV investment and acquisition Sanctioned gas pipeline projects serving coal-to-gas transitions in TN and NC Progressed N.A. onshore renewable power backlog by sanctioning 1.4 GW1 of new projects (1) Gross capacity; net is 1.2 GW
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8 (1) Includes hydro, nuclear, and biomass; (2) Source: S&P Global Commodity Insights, ©2025 by S&P Global Inc., shown in Million Tons of Oil Equivalent All forms of energy needed globally Diversified business mix is ideally positioned to meet growing demand Natural gas & oil remain essential energy for supporting economic expansion and population growth globally – Enbridge is connected to all operating USGC LNG terminals – Ingleside Energy Center is the largest crude export terminal in N.A. T oday 2030 2035 2040 Oil | Natural Gas | Renewables | Coal | Other 1 | S&P Inflections Scenario 2 Global Energy Demand Renewables are critical to facilitate energy transition and meet ambitious emissions targets – Growing portfolio diversified across technology and geography – Successful origination of blue-chip customers Enbridge’s strategy generates predictable cash flow and matches the pace of the energy transition
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2024 2040 9 (1) Source: S&P Global Commodity Insights, ©2025 by S&P Global Inc.; although renewable growth decreases natural gas average consumption rates, demand for reliable peak capacity expected to offset Significant natural gas demand growth in N.A. Reliable and affordable energy required to support growing demand Growing N.A. Natural Gas Demand 1 +23 Bcf/d +11 Bcf/d +7 Bcf/d +24 Bcf/d LNG & Mexico exports • 100% connected to USGC operating LNG export capacity Baseload gas-fired generation • 45% of all N.A. natural gas power generation within 50 miles of our system Data center opportunities • 29 new data centers (4 GW) within 50 miles of our system Coal-to-gas switching • 78 coal plants (80 GW) within 50 miles of our system N.A. natural gas opportunities 1
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10(1) Expected growth capex between 2028-2030 Four core franchises offer visible growth Business diversification extends growth through the decade ~$50B of growth opportunities through 2030 Liquids Pipelines ~$10B • Critical, demand-pull infrastructure • Capital efficient, low-multiple expansions Liquids pipeline Natural Gas pipeline Liquids storage Natural Gas storage Wind farms – onshore Solar energy operations RNG LNG facility Gas Distribution & storage R L Gas Transmission • Strategically positioned assets with unparalleled connectivity • Significant in-footprint, brownfield opportunities ~$23B Gas Distribution & Storage • Industry-leading geographically diversified footprint • Rate base investment supported by regulated returns ~$9B 1 Renewable Power • Electrification tailwinds support profitable long-term growth • Long-term PPAs with blue-chip customers ~$7B L L
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Sanctioned $8 B of capital in 2024 11 (1) Adjusted earnings before interest, taxes, depreciation and amortization (adjusted EBITDA), distributable cash flow (DCF), DCF/share and Debt-to-EBITDA are non-GAAP measures. Reconciliations to GAAP measures can be found at www.enbridge.com; (2) Common share dividends; (3) 2025e-2029e; assuming dividend per share growth up to cash flow growth guidance; (4) Total shareholder returns defined as share price appreciation plus reinvestment of dividends Disciplined capital allocation Strong financial position supports growth and return of capital to shareholders Committed to 4. 5 - 5. 0 X Debt/EBITDA 1 range Balance sheet strength • Low-risk, utility-like model generates stable cash flow • Regulated assets and negligible commodity exposure supports targeted leverage levels • Ongoing capital recycling program Further growth • Prioritizing low-multiple, brownfield opportunities • Executing $29B secured capital backlog • Optimizing costs through automation and scale Sustainable return of capital • Maintain 60-70% DCF1 payout range • Dividend Aristocrat • ~$35B2 returned to shareholders in the past 5 years; expect to return $40-45B3 over next 5 years • ~12% TSR4 since 2005 Delivered 37 % TSR 4 in 2024
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Stability Low-risk, utility-like business profile Strength Predictable cash flows support strong balance sheet Growth ~5% growth expected through the end of the decade Optionality T uck-ins and tax efficient lower-carbon opportunities 12 First-choice investment opportunity Value proposition supports delivery of attractive long-term shareholder returns Consistency 30 consecutive years of annual dividend increases Strong T otal Return Predictable Cash Flow Growth Low-Risk Business
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Liquids pipeline Liquids storage Refinery Regional Oil Sands Flanagan South | Spearhead Colin Gruending EVP & President, Liquids Pipelines Mainline Hardisty Edmonton Express Norman Wells Platte Bakken Line 5 Cushing Line 78 Line 9 Seaway Gray Oak Catus II EIEC DAPL ETCOP
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14 (1) 2024 adjusted earnings before interest, tax, depreciation and amortization (EBITDA); adjusted EBITDA is a non-GAAP measure. Reconciliations to GAAP measures can be found at www.enbridge.com; (2) EIEC volumes from Jun-Dec 2024 First-choice for Liquids delivery Critical, diversified demand-pull infrastructure with embedded long-term growth Execution of key priorities in 2024 Strong Mainline volumes (3.0+ MMbpd) Record volumes at EIEC and Gray Oak Sanctioned Gray Oak expansion Furthered EIEC strategy – adjacent dock acquisition and storage expansions Business highlights • System connects best basins in N.A. to demand-pull customers • Exceptional operational performance • Customer-focused approach • Significant embedded growth opportunities Scale of business Largest crude transportation business in N.A. $9.7B of EBITDA1 Leading export facility in N.A. 1.2MMbpd 2 loaded at Enbridge Ingleside Energy Center (EIEC) Longest crude system in N.A. ~18,000miles
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0 2 4 6 8 10 12 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025e 15 Reliable growth through all cycles Resilient track record of execution and EBITDA growth Liquids segmented EBITDA 1 ($B) Strong fundamentals support continued investment Growing WCSB, Bakken, and Permian franchises Contracted/regulated EBITDA, high returns, with negligible commodity exposure Security of supply and export role Unparalleled asset footprint generates opportunities Commodity Price Collapse COVID-19Alberta Forest Fires ~8% 10-year EBITDA CAGR Mainline Regional Oil Sands U.S. Gulf Coast & Mid-Con Other Systems 2025e Guidance (1) Adjusted EBITDA is a non-GAAP measure. Reconciliations to GAAP measures can be found at www.enbridge.com
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USGC Heavy Demand Opportunity 2023-2035 (MMbpd) System connects rising WCSB supply to growing global demand 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 16 (1) Enbridge estimate; (2) Based on Kpler data, 2023 waterborne imports; (3) Source: S&P Global Commodity Insights, ©2025 by S&P Global Inc.; (4) Including Enbridge owned Express-Platte pipelines Fundamentals support need for additional egress Further system capacity expected to be required Contracted4 Enbridge Mainline WCSB Supply1 Uncontracted Refinery Demand WCSB supply to grow by >1MMbpd by 2035 Additional Mainline capacity needed WCSB egress fully utilized >1MMbpd heavy demand opportunity via USGC Competitive path connected to global markets via USGC exports Replacing other heavy supply sources2 Asian Demand Growth3 Up to 0.8 ~0.3 WCSB requires ~1MMbpd of additional egress by 2035 2023 2035 WCSB Supply 1 (MMbpd) 6.0+ 4.9
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17 WCSB development pipeline Scale and connectivity provide vast opportunity set underpinned by attractive returns ~$4B of total WCSB growth opportunities Regional Oil Sands expansions • 150+ kbpd • $0.3B | 2026-2028 3 Southern Lights • 15 kbpd expansion completed • Less than $20M | 2025 2 Mainline / Market Access optimization – multi phase • Phase 1: 150kbpd | ~$1.5B | 2027 – FSP open season imminent • Up to 300 kbpd of opportunities 4 Express-Platte • 30+ kbpd expansion • ~$50M | 2026 • Further expansions being evaluated 5 Mainline capital investment • Up to $2.0B | 2025-2028 NEW • Supports operational efficiencies and system reliability • Earns 11.0-14.5% within ROE performance collar 1 4 2 5 3 Sanctioned In development Refinery Wabamun Carbon Hub • Phase I FID expected in 2025 • $0.3B | 2028 6 6 1
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Pipelines to Corpus Christi are fully utilized in 2025 given attractive pricing Permian egress constraints by 2028 present incremental pipeline opportunities Full-path from Permian to tidewater creates highly attractive, competitive offering EIEC Cactus II Corpus Christi TEXAS Freeport Gray Oak Eagle Ford Houston Permian Seaway 18(1) Source: S&P Global Commodity Insights, ©2025 by S&P Global Inc. Fundamentals support USGC growth Permian supply growth drives need for USGC exports and additional growth opportunities Permian supply growth supported by top-tier basin economics and U.S. policy Permian Supply 1 (MMbpd) 2023 2035 7.5 5.9 EIEC best advantaged to capture USGC export growth U.S. Gulf Coast WTI Exports 1 (MMbpd) 2023 2035 2.9 5.1 Expecting >2 MMbpd 1 of USGC export growth through 2035 ETCOP
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19 USGC development pipeline Integrated value chain enhances competitiveness and returns ~$8B of total USGC growth opportunities Gray Oak expansion • 120 kbpd • ~$50M | 2025-2026 1 EIEC phase VII storage expansion • ~2.5 MMbbls • ~$80M | 2026 2 Lower-carbon opportunities • ~$6.0B | 2029+ • Development of CCS pipelines & storage, and infrastructure to support blue ammonia production and export • Expanded collaboration with Yara to evaluate future ammonia production facilities in the USGC and ammonia import/export infrastructure globally 4 EIEC dock optimization & export optionality • ~$1.5B | 2027+ • Optimizing loading to use increased channel depth • Increased vessel loading capacity upon acquisition close • Further dock expansion capacity available • Developing NGL opportunities 3 3 4 2 1 EIEC Cactus II Corpus Christi Freeport Gray Oak Eagle Ford Houston Permian Seaway TEXAS EIEC docks Enbridge Ingleside Energy Center Acquired docks Future site for dock expansion Connectivity to new docks Sanctioned In development Refinery ETCOP
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20(1) Adjusted EBITDA is a non-GAAP measure. Reconciliations to GAAP measures can be found at www.enbridge.com Visible growth through end of the decade Diversified growth underpinned by attractive, executable, capital efficient returns • Southern Lights • Regional Oil Sands expansions • Mainline / Market Access optimization – multi phase • Express-Platte • Wabamun Carbon Hub • Gray Oak expansion • EIEC – storage expansion, dock optimization, export optionality • Lower-carbon opportunities US Gulf Coast (2025-2029+) WCSB (2025-2028+) Opportunities Avg. EV/EBITDA1 build multiple Serving new energy demandProjects ~4 - 6X ~ 4 - 9X ~$8B • Connecting growing supply • Delivering to resilient downstream refinery demand • Growing crude exports • Supporting system integrity and reliability • Investing in alternative fuels • Mainline capital investment ~$2B ~$2B 11.0-14.5% Performance ROE collar
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L Natural Gas pipeline Natural Gas storage Renewable Natural Gas LNG Terminal L Cynthia Hansen EVP & President, Gas T ransmission T-South Aitken Creek StorageT-North Woodfibre LNG Texas Eastern DBR Whistler Sabal Trail Algonquin Maritimes & Northeast East Tennessee Vector Valley Crossing Gulfstream Waha Storage Hub Nexus SESH L
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22 (1) Includes equity investments First-choice for natural gas delivery Strategically positioned network with unparalleled connectivity to growing demand Business highlights Last mile connectivity to key N.A. demand centers Safely and reliably transport energy to over 170 million people throughout N.A. Move 20% of gas consumed in the U.S. ~31 Bcf/d of peak deliveries ~$2.2B of Permian and offshore investment Successful rate case strategy adding ~US$0.2B of EBITDA through 2026 100% contract renewal rate in 2025 Execution of key priorities in 2024 Scale of business Extensive pipeline system connectivity throughout N.A. ~71,000 miles 1 Largest transporter of Gulf Coast offshore volumes ~60% of total natural gas production handled in Gulf Connected to operating USGC LNG export capacity 100%
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23 (1) Excluding Modernization investment of US$2.8B expected from 2025-2028; (2) Adjusted EBITDA is a non-GAAP measure. Reconciliations to GAAP measures can be found at www.enbridge.com; (3) Converted at USD/CAD foreign exchange rate of 1.35 Secured projects tied to growing demand Diversified growth of ~$12B1 driven by size and scope of the business • Appalachia to Market Phase II • Tennessee Ridgeline • Woodfibre LNG • Rio Bravo • Blackcomb • Sparta • Canyon • T-North Expansion (Aspen Point) • T-North Expansion (Birch Grove) NEW • T-South Expansion (Sunrise) Cost-of-service expansions (2026-2028) Attractive return, capital efficient (2025-2029) ~$6.0B 3 ~6-8X ~5 Bcf/d ~$5.5B 10-11X ~1Bcf/d Capital investment Avg. EV/EBITDA2 build multiple Serving new gas demandProjects
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24 (1) Canadian $ converted at USD/CAD foreign exchange rate of 1.35; (2) Adjusted EBITDA is a non-GAAP measure. Reconciliations to GAAP measures can be found at www.enbridge.com; (3) Based on 2023 FERC Form 2; (4) Settlement in principle reached on Algonquin Gas Transmission (AGT) & Maritimes & Northeast U.S. (M&N U.S.); subject to FERC approval; (5) US$55M beginning October 2024; increasing to US$80M beginning January 2026; (6) AGT rates effective Dec 1, 2024; M&N U.S. rates effective Jan 1, 2025; Base business growth Timely rate proceedings ensure cost recovery of investments in strategic assets $3.8B to be invested through 2028 on modernization Investment supports system safety and reliability Modernization drives emissions reduction Rate settlements ensure affordability, rate certainty, and fair returns ~$500M 1 of EBITDA2 added through successful rate proceedings in 2020-2023 T exas Eastern 3 Saltville 3 Storage AGT 4 M&N U.S. 4 Comeback requirement on East Tennessee pipeline in 2026 2024 2024/2026 5 2024/2025 6 Rates effective + EBITDA 2 /yr US$5M US$80M 5 ~US$70M
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Cedar LNG Vancouver BC T-South T-North Montney Basin Pacific Trail LNG Canada Squamish Aitken Creek Gas Storage Deep Basin Kitimat 25 (1) US$1.5B converted at USD/CAD foreign exchange rate of 1.35; our equity contribution is approximately US$0.9 billion, with the remainder financed through non-recourse project level debt. Capital cost estimates will be updated prior to the 60% engineering milestone, at which point Enbridge's preferred return will be set; (2) Source: S&P Global Commodity Insights, ©2025 by S&P Global Inc. Western Canada growth drivers ~$8B under construction supported by growing LNG exports Expecting ~5Bcf/d 2 of WCSB production growth through 2040 5 1 3 4 T-North expansion (Aspen Point) | 2026 • Adds ~500 MMcf/d of capacity to serve growing demand 1 Projects 2 T-North expansion (Birch Grove) | 2028 NEW • Increases capacity by ~200 MMcf/d to serve growing demand 2 $1.2B $0.4B T-South expansion (Sunrise) | 2028 • 300 MMcf/d to deliver gas to Woodfibre and lower B.C. Mainland 3 $4.0B Woodfibre LNG | 2027 • 30% interest in 2.1 MTPA export facility 4 $2.0B 1 Aitken Creek expansion | Pending positive FID | 2028 • Additional storage connected to three major long-haul pipelines 5 40Bcf Sanctioned In development Investment approach • Long-lived resource with competitive break-even cost • Rate-regulated cost-of-service model; brownfield expansions • Focus on strengthening relationships with Indigenous groups Woodfibre LNG
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26 Execution of Permian strategy Strategic natural gas pipeline and storage network with embedded growth opportunities Whistler JV attractive entry point Financial and leverage accretive deal providing immediate cash flow Extends value chain from Permian to USGC Continued development of Rio Bravo pipeline (up to 4.5 Bcf/d) Sanctioned Blackcomb pipeline (up to 2.5 Bcf/d) Acquired 15% interest in DBR2 Header System Expected to unlock future growth opportunities, including embedded organic expansions Whistler Blackcomb DBR Texas Eastern Valley Crossing Tres Palacios Moss Bluff ADCC Waha Hub Future Growth2024 MAR JUL NOV Whistler JV Blackcomb DBR Rio Bravo Expecting ~5 Bcf/d 1 of Permian production growth through 2040 (1) Source: S&P Global Commodity Insights, ©2025 by S&P Global Inc.; (2) Delaware Basin Residue
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Rio Grande LNG Valley Crossing Texas Eastern LA Corpus Christi LNG ADCC Sparta Tres Palacios Canyon Freeport LNG Sabine Pass LNG Cameron LNG Calcasieu Pass LNG Delfin LNG MS Texas LNG Plaquemines LNG Rio Bravo Whistler Blackcomb TX 27 U.S. Gulf Coast competitive footprint Asset footprint connected to rising domestic and LNG demand drives growth Connected to 100% of operating USGC LNG terminals LNG Connectivity • Ability to deliver ~4 Bcf/d, accounting for ~7% of global volumes • Venice extension placed into service to serve Plaquemines LNG • Developing Blackcomb & Rio Bravo pipelines alongside partners 105Bcf of net working capacity Storage • Enbridge owns 622 Bcf of net working storage across N.A. (~20% located in USGC) • Recently completed 6.5 Bcf T res Palacios expansion • Exploring other expansions ~60% of total natural gas production handled in Gulf Offshore • Largest transporter of offshore volumes, delivering ~1 Bcf/d • Sanctioned Sparta and Canyon pipeline systems in deep water (6,000ft) • New projects have future expansion opportunities ENB connected/contracted LNG facilities In service Under construction In development
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TX Texas Eastern LA Venice Extension 28(1) Converted at USD/CAD foreign exchange rate of 1.35 Development pipeline – U.S. Gulf Coast Optionality and diverse range of growth opportunities Permian growth • Embedded future organic expansion opportunities within asset footprint • Egress from the Permian to support additional demand 1 Storage expansions • USGC expansion potential of up to 24 Bcf • Opportunities driven by increasing utility and power demand 2 LNG connectivity • VCP expansion to serve Texas LNG • Potential Texas Eastern expansion of up to 1.4 Bcf/d to serve new LNG capacity 3 Offshore growth • Expansion opportunities to support future production growth plans 5 Industrial growth • ~0.5 Bcf/d of lateral and mainline expansions to serve methanol and other industrial demand 4 ~$9B 1 of growth opportunities by 2030 5 2 3 4 1 $2-3B 1 of potential opportunities; FID in 6-18 months In development
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29 Well-positioned to serve power generation customers Opportunities driven by scale and connectivity of asset footprint 45% of all N.A. natural gas power generation within 50 miles of our system ~2.5 Bcf/d of coal-to-gas switching opportunities Pursuing ~10 direct connections to data centers Within 50 Miles of GTM Assets 29 1 New Data Centers 4 GW 78 1 Coal Plants 80 GW Coal Plants1 Data Center Under Construction1 Data Center Planned1 35+ opportunities to serve up to ~11 Bcf/d of new demand (1) Source: S&P Global Commodity Insights, ©2025 by S&P Global Inc.
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30 (1) Texas Eastern (TETCO); (2) Converted at USD/CAD foreign exchange rate of 1.35 Development pipeline – power demand related Growth opportunities driven by rising power demand 2 1 4 3 5 ~11Bcf/d of opportunities TETCO lateral #2 5 TETCO1 lateral #1 Sabal Trail TETCO expansion 1 2 4 SESH expansion 3 Projects to serve: Regional baseload growth New gas-fired generation Coal-to-gas conversions Data centers Mid-stage (COD 2026-2032) Late-stage Potential FID in 6-18 months $1-2B 2 of late-stage opportunities Early-stage (COD 2026-2032) ~$14B 2 of growth opportunities by 2032 Late-stage – in development Mid-stage – opportunities Early-stage – opportunities
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31 (1) Converted at USD/CAD foreign exchange rate of 1.35; (2) Adjusted EBITDA is a non-GAAP measure. Reconciliations to GAAP measures can be found at www.enbridge.com Visible growth through end of the decade Potential to FID $3-5B1 of opportunities in next 6-18 months • Permian growth • Storage expansions • LNG connectivity • Industrial growth • Offshore growth • TETCO lateral #1 • TETCO expansion • SESH expansion • Sabal trail • TETCO lateral #2 • Mid-stage opportunities • Early-stage opportunities Power demand related (2026-2032) U.S. Gulf Coast (2026-2030) Opportunities Avg. EV/EBITDA2 build multiple Serving new gas demandProjects ~$9 B 1 ~12 Bcf/d ~ 6 -8X ~11Bcf/d ~$14B 1 ~ 6 -8X
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Michele Harradence EVP & President, Gas Distribution & Storage Enbridge Gas Utah Enbridge Gas Wyoming Enbridge Gas Idaho Enbridge Gas North Carolina Enbridge Gas Ohio Enbridge Gas Ontario Enbridge Gas Québec
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- 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 - 1.0 2.0 3.0 4.0 5.0 6.0 7.0 ENB Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 33 (1) Utility peers include Atmos, CenterPoint, NiSource, Sempra, Southern First-choice for natural gas distribution in N.A. Stable and visible growth underpinned by attractive risk-adjusted returns Business highlights Delivers affordable and reliable energy enabling economic growth 349 Bcf of storage supports reliability and affordability Incentive rate mechanisms and rate riders enhance capital efficiency of investment Largest gas utility in N.A. 1 Connected to ~7MM customers ~9.1Bcf/d of deliveries across N.A. $2-3B per year of utility growth capital expenditures Execution of key priorities in 2024 Completed ~$19B acquisition of three U.S. gas utilities ahead of expectations Invested $2.4B in critical infrastructure delivering safe, reliable, and affordable energy Added 75k customers across the utility footprint Enabled 4.3 GW of new power generation Customer (MM) Volumes (Tcf)
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34 (1) DCF per share and earnings per share (EPS) are non-GAAP measures. Reconciliations to GAAP measures can be found at www.enbridge.com; (2) U.S. gas utilities include Atmos, CenterPoint, NiSource, Sempra, Southern; (3) Source: FactSet as of February 28, 2025, using one-year forward P/E valuation Investment thesis for U.S. Gas Utilities playing out Opportunistic acquisition of “must have” infrastructure supported by rising valuations Rising gas and power demand from baseload growth, data centers, and coal-to-gas switching Need for safe, reliable, and affordable energy Generational acquisition of gas utilities… …at opportune time Acquired three premier utilities for $19B at historically attractive multiples All acquisitions closed in 2024 Accretive to DCF/sh and adjusted EPS in first full year of ownership1 Adds ~$1.8B of average utility growth capex per year ~16.5X Price Earnings 2023e Deal multiple ~19.1X 3 U.S. gas utilities average 2 10 years (Feb’15-Feb’25)
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35 Industry-leading utility platform Strong growth outlook through the end of the decade • Predictable, diversified, long-term investment in critical infrastructure • Limited capital, permitting, and inflation risk • Revenue decoupling from volumes in U.S. utilities • Ability to deliver operational efficiencies to preserve customer affordability Combined Rate Base Track record of reaching fair regulatory outcomes • Strong government and stakeholder relationships in supportive jurisdictions • Constructive regulatory regimes that deliver timely settlements to ensure fair return • Efficient filing of rate case applications include recovery of capital • Ongoing rate cases in Ontario and Ohio • Expect to file Utah and North Carolina rate cases in 2025 2025e 2026e 2027e 2028e ~$36B Growth CAGR may be extended and enhanced by: • Baseload need • Data center opportunities • Coal-to-gas switching projects 2029+ ~70% of capex is rider eligible
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36 (1) Formerly East Ohio Gas; (2) Formerly Questar; (3) Formerly Public Service Company of North Carolina; (4) Total population growth 2025-2029: Ontario based on Government of Ontario; Ohio, Utah, and North Carolina based on World Population Review; (5) U.S. capex converted at USD/CAD foreign exchange rate of 1.35; (6) Includes Wexpro Diversified growth drivers Enbridge Gas Utah 2 Salt Lake City Denver NV UT WY ID CO Enbridge Gas North Carolina 3 NC SC Charlotte Raleigh VA Enbridge Gas Ontario ONTARIO Toronto Hamilton MICHIGAN Enbridge Gas Ohio 1 Population growth (2025-2029) 4 ~5.5% ~1.0% ~5.1% ~6.2% Power demand growth opportunities Up to 0.7Bcf/d and $2.6B of capex Up to 0.5Bcf/d and $0.3B of capex Up to 1.2Bcf/d and $0.6B of capex Up to 0.6Bcf/d and $0.5B of capex Other demand drivers Industrial growth Emissions reduction Modernization Reliability New connections Modernization Emissions reduction Reliability Avg. annual growth capex (2025-2027) ~$1.1B ~$0.5B 5 ~$0.5B 5, 6 ~$0.8B 5 OHIO Cleve land Columbus Strong growth and execution capabilities across jurisdictions ~3Bcf/d of power demand opportunities across utility footprint
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37 Long-term growth tailwinds Utilities are well-positioned to serve rising power demand from various sources ~50% driven by baseload growth and coal-to-gas switching Need for safe and reliable energy to support economic growth Low-risk investments in regulated rate base Earns predictable returns with constructive ROEs and equity ratios Up to ~$4B of growth through 2030 Late-stage (COD 2025-2027) Mid-stage (COD 2028-2030) 0.7 Bcf/d Enbridge Ontario 0.5 Bcf/d Enbridge Ohio 1.2 Bcf/d Enbridge Utah 0.6 Bcf/d Enbridge North Carolina 40+ opportunities to serve up to ~3 Bcf/d of new demand Opportunities Bcf/d $B Data centers 0.5 0.4 Total Up to 0.5 0.4 Opportunities Bcf/d $B Baseload 1.0 2.3 Data centers 1.0 0.9 Coal-to-gas 0.5 0.4 Total Up to 2.5 3.6
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38 (1) Expected to enter service in 2027/2028; (2) Expected growth capex between 2028-2030 Visible growth through end of the decade Expect to invest $2-3B in growth annually; capital efficient investment underpinned by strong risk-adjusted returns • CAD utility growth capital • Transmission/storage assets • New connections/expansions • U.S. utility growth capital • Moriah Energy Center • T151 phase 1 & phase 2 NEW • Late-stage opportunities • CAD utility growth capital • Transmission/storage assets • New connections/expansions • U.S. utility growth capital • Mid-stage opportunities Opportunities Rate-regulated ROEs Serving new gas demandProjects Rate base investment (2028-2030) Rate base investment (2025-2027) ~9-10.5% ~$9B $9B+ 2 • Delivering reliable and affordable energy • ~9.1 Bcf/d delivered to customers • Diversified growth across all multiple jurisdictions • ~70% of capital is rider eligible • Opportunity to deliver another ~3 Bcf/d ~9-10.5%
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Neal Hot Springs Lac Alfred Massif-du-Sud St. Robert GreenwichChin ChuteMagrath Blackspring Ridge Cedar Point Keechi Chapman Ranch Magic Valley New CreekWildcat Talbot Cruickshank Underwood Alberta Solar One Silver State North Orange Grove Adams Portage Fox Squirrel Flanagan Heidlersburg LambertvilleTilbury Sarnia Amherstburg Sequoia TORONTO NEW YORK HOUSTON CALGARY Germany France UK Spain LONDON PARIS Hohe See Albatros Rampion FécampCalvados Saint-Nazaire Provence Grand Large Wind Solar Geothermal Matthew Akman EVP & President, Power
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2.2 3.6 6.6 2015 2020 2025+ 40(1) Gross capacity; (2) Gross capacity; net is 3.5 GW; includes 1.4 GW gross under construction (1.0 GW net) First-choice for Renewable Power Well-positioned for growth through disciplined investment 0.9 GW1 brought into service Sanctioned ~$2.6B of new solar projects Secured 3 new blue-chip customer relationships Business highlights Diversified asset footprint Decades of execution experience Economies of scale Attractive risk-adjusted returns Strong fundamentals despite U.S. policy uncertainty Operating capacity (GW) 6.6 GW 2 in operation and under construction 4.4 GW 1 under development 23 years of experience $1-2B of growth opportunities per year Execution of key priorities in 2024
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2014 2019 2024 41 (1) Clean Energy Buyers Association – Deal Tracker; announced PPAs as of 9/30/2024 for projects in US; (2) Gross capacity; net is 0.3 GW Rising power demand supports long-term growth Positive fundamentals underpin large opportunity set Partnered with EDF Renewables to complete a phased 577 MW2 solar farm in Ohio to help Amazon meet its net-zero commitments Announced one of the largest N.A. solar facilities in ERCOT to support AT&T and Toyota for US$1.1B U.S. corporate renewable energy demand 1 (GW) • Corporate demand driven by manufacturing growth, new data centers, and electrification of the grid • 1.3 GW of average annual growth over the past decade • 25 states have clean electricity initiatives supporting renewable demand growth • Since the U.S. election, there has been no visible slowdown in procurements of renewable energy Sanctioned a US$0.3B solar project in Texas to provide renewable energy to AT&T Fox Squirrel Solar Orange Grove Solar Sequoia Solar Sanctioned U.S. onshore projects
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42 (1) Source: Canada Energy Regulator Electricity Capacity (Current Measures), 2024-2035; (2) Source: Ohio Public Utilities Commission 2020-2039 plan; (3) Source: PacifiCorp Integrated Resource Plan (Draft), 2024-2035; (4) Source: Duke Energy Carolinas Resource Plan, 2024-2035 Strategically located to capture new demand Complementary franchises positioned to capture power demand growth Regional integrated resource plans – growth in capacity (GW) All forms of energy will be required • Gas and renewables capacity expected to grow by ~22 GW and ~37 GW, respectively, in operated utility regions • Customers are requesting reliable and affordable solutions that also help lower emissions • Offering a “one-stop-shop” approach for diversified energy needs • Leveraging expertise, experience, and relationships to capture opportunities • Several conversations are ongoing with customers with a potential investment of up to ~$2.5B Ontario 1 +6.8 +4.5 Ohio 2 +5.5 +6.7 Rocky Mountain West 3 +0.6 +11.0 Carolinas 4 +8.9 +14.7 Total +21.8 +36.9 Natural Gas Wind/Solar
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0 2 4 6 8 10 12 In Operation Under Construction In Development 43 (1) Gross capacity; net is ~8 GW; (2) Adjusted EBITDA is a non-GAAP measure. Reconciliations to GAAP measures can be found at www.enbridge.com Growing renewables portfolio Visible development pipeline sustains expected profitable growth European Offshore Wind N.A. Onshore Wind N.A. Solar Disciplined capital allocation Development pipeline through 2030 is focused on N.A. onshore Strong relationships with customers and partners Advantaged interconnection status on a portfolio basis; many agreements in hand Strong EBITDA2 CAGR of ~14% over the past 5 years Renewable asset portfolio (Gross GW) Potential growth to ~11GW 1 by 2030
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44 (1) Source: Clear Energy Associates (CEA); (2) Source: LevelTen Energy Strong risk-adjusted returns supported by blue-chip customers Projects generate attractive returns with execution reliability for customers • Economies of scale provide purchasing power • Ability to use attractive tax attributes; no tax equity partners required • Solar panel prices have decreased by ~33% over the past 24 months1 • Solar offtake prices have increased by ~35% over the past 24 months2 • Effective risk management Factors underpinning attractive returns PPA customers supporting new development
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Germany France UK 45 (1) Net capacity; gross is 2.0 GW European update Disciplined utility-like investment over time; retaining long-term optionality Strong European fundamentals One European project under construction Long-term optionality with multiple under development Disciplined, utility-like investment No new FIDs in the near-term 2018 2019 2020 2022 2024 2024 2027e Hohe See Rampion Saint- Nazaire Fécamp Provence Grand Large CalvadosAlbatros Future development In operation Under construction Long-term contracts with inflation protection No speculative bids on leases Strong partners Utilization of promotes and re-financings drive solid returns higher 0.6GW 1 brought into service since 2018 Project in-service Business growth underpinned by strict investment criteria
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46 (1) Net capacity Visible growth through end of the decade Executing on growth commitments and poised to continue to deliver • Clear Fork Solar • Cowboy Solar • Seven Stars • Cone Wind • Easter Wind • Water Valley • Plummer Solar • Vermilion Solar • Leaf River Wind • Vermilion Wind Mid-stage development (2026-2030) Late-stage Development (2026-2027) Opportunities Returns Serving new power demandProjects ~$3.0B ~1.6GW1 Mid-teens ~1.5GW1 ~$4.0B Mid-teens
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48 (1) Distributable cash flow (DCF) and adjusted EBITDA are non-GAAP measures. Reconciliations to GAAP measures can be found at www.enbridge.com Attractive accretion and build multiples Renewable projects compete for capital across the enterprise • No impact to EBITDA1 for wholly owned investments • T ax attributes recorded as reduction of current tax • Fox Squirrel investment tax credit recognition in EBITDA was due to equity investment accounting treatment Illustrative DCF 1 accretion… DCF Utilization of tax attributes EBITDA Interest Cash tax Higher DCF EBITDA Interest Lower cash tax ~10-12X EV/EBITDA1 …at attractive build multiples Recognition of tax attributes Cash flow • Elevated EV/EBITDA multiples do not consider cash tax savings • Tax attributes generate value that should be considered in project economics ~7-9X
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Pat Murray EVP & Chief Financial Officer
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50 (1) Earnings per share (EPS), distributable cash flow (DCF) and DCF per share are non-GAAP measures. Reconciliations to GAAP measures can be found at www.enbridge.com; (2) Investment grade or equivalent; (3) Includes Mainline Tolling Agreement which has a performance collar allowing the Mainline to earn between 11% and 14.5% ROE; (4) DBRS: (low), S&P BBB+, Fitch: BBB+, Moody’s Baa2 Stable business model Low-risk business profile drives predictable results Predictable cash flows Guidance range Actual results 19th Consecutive year of achieving financial guidance of customers are Investment Grade 2 >95% of EBITDA from assets with inflation protection80% cost-of-service / contracted cash flows 3 98% Investment Grade credit ratings 4 BBB+ Average Adjusted EPS 1 DCF/share 1 2006 2024 Financial Crisis Commodity Price Collapse Alberta Forest Fires COVID Rising Inflation
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51 (1) Distributable cash flow (DCF), DCF per share, and Debt-to-EBITDA are non-GAAP measures. Reconciliations to GAAP measures can be found at www.enbridge.com; (2) Common share dividends; (3) 2025e-2029e; assuming dividend per share growth up to cash flow growth guidance Capital allocation priorities Maintaining ideal balance between growth and returning capital to shareholders • T arget leverage range of 4.5x to 5.0x D/EBITDA1 • Industry-leading business risk profile • Ongoing capital recycling program Protect balance sheet Sustainable return of capital • Dividend payout range of 60% to 70% of DCF1 • One of few midstream Dividend Aristocrats – 30 years of consecutive increases – $35B2 returned to shareholders since 2020; expect to return $40-45B3 over next 5 years Further growth • Driving visible organic growth • Prioritize capital efficient opportunities • Strategically deploy excess investment capacity • Opportunistic tuck-ins
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52 (1) Illustrative free cash flow defined as DCF less common share dividends. Free cash flow (FCF), Adjusted EBITDA, distributable cash flow (DCF), DCF per share, and Debt-to-EBITDA are non-GAAP measures. Reconciliations to GAAP measures can be found at www.enbridge.com Investment capacity FCF 1 before capex 5% EBITDA1 growth enhances balance sheet capacity $4 - 5 B ~ $ 5 B Annual investment capacity Creates $9-10B of balance sheet capacity Equity-self funding $9-10 billion of annual investment capacity $6 - 7 B Allocated to: • Organic Projects • Rate Base Growth • Accretive Tuck - ins • Debt Reduction ~ $4 B GTM Modernization $4 - 5 B Organic Projects $1-2B Excess Capacity Utility Growth Foundational Allocation • Recurring, annual rate base investment Opportunistic Allocation • New organic projects • Accretive tuck-ins Excess Allocation • LP / GTM brownfield expansions • Renewable power investments Mainline Investment
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2026 20272025 2028+ 53(1) Adjusted EBITDA is a non-GAAP measure. Reconciliations to GAAP measures can be found at www.enbridge.com; (2) Illustrative; capital entering service includes proportional capital from Rio Bravo and Blackcomb pipelines Growth outlook: secured backlog ~$23 billion of projects entering service through 2027 drives annual EBITDA1 growth • App to Market 2 • Orange Grove • Gray Oak Expansion • EIEC VII Storage • T ennessee Ridgeline • Aspen Point • Sequoia • Woodfibre LNG • Calvados ~$9B ~$9B Capital entering service by year 2 Excess Allocation Foundational Allocation • Sunrise • Birch Grove • Sparta • Canyon $7B ~$5B • Moriah • T15 Foundational Allocation ~$4 billion of annual rate base investment
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54 Flexible opportunity set ~$50 billion of opportunities adds growth visibility to back-end of the decade Permian expansions Power demand related projects Opportunistic renewable power investment Mainline investment Future WCSB/USGC expansions Foundational investment Diversified: • Commodity • Location • Regulatory jurisdictions 2025 2026 2027 2028 2029 2030 U.S. Gulf Coast investment Lower Carbon Liquids Pipelines RenewablesGas Transmission Gas Distribution
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55 Growth outlook: optimization and efficiency Increasing Asset Availability • Deliveries as a % of 3-Yr Average: – Mainline 103% 2 – US Gas Transmission 104% – Gray Oak Pipeline 115% Scale and T echnology : • Supply chain economies of scale • Power cost optimization Enhancing Acquired Assets • Ingleside: ~8x 4 • Aitken Creek: ~7x 4 • Tres Palacios: ~5x 4 Asset optimization and cost efficiency driving recurring EBITDA growth Rate Escalation: • Mainline inflators • Enbridge Gas Ontario IRM1 • Rate cases $600 - 90 0 M of EBITDA 3 optimizations expected to be realized in 2025 to 2027 (1) Incentive rate-making mechanism; (2) Normalized for Line 3 Replacement expansion; (3) Adjusted EBITDA is a non-GAAP measure. Reconciliations to GAAP measures can be found at www.enbridge.com; (4) Enterprise value over forward adjusted EBITDA, adjusted for incremental spend
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56 (1) Adjusted EBITDA, earnings per share (EPS), and distributable cash flow (DCF) are non-GAAP measures. Reconciliations to GAAP measures can be found at www.enbridge.com; (2) U.S. gas utilities acquisitions drove higher than average EBITDA growth in 2024 and is expected to do so in 2025 Growth outlook Reaffirming growth outlook; EBITDA, EPS and DCF growth rates converge to 5% in 2027 EBITDA 1 EPS 1 DCF 1 2023-26 Post 2026 7-9 % CAGR 2 5% 4-6% CAGR 5% 5%3% CAGR Cash tax rate levels out Drivers Dividend Up to 3% Up to 5% $600-900M of EBITDA optimizations expected to be realized in 2025 to 2027 $23B of secured growth capital expected to enter service through 2027
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57 Long-term value creation 30-year history of annual dividend increases underpinned by steady growth 30 Y ears of dividend increases $3.77 /share 1995 2025e 4% CAGR since 2019 ENB Midstream S&P 500 Utilities TSX 12.3% 11.7% 10.4% 8.8% 8.1% Price | Dividends 12% T otal shareholder return1 since 2005 (1) Total shareholder returns defined as share price appreciation plus reinvestment of dividends
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59 (1) Our equity contribution is approximately US$0.9 billion, with the remainder financed through non-recourse project level debt. Capital cost estimates will be updated prior to the 60% engineering milestone, at which point Enbridge's preferred return will be set; (2) Pending outcome of Motion to Review with Ontario Energy Board and appeal to Ontario Divisional Court; (3) Calvados is financed primarily through non-recourse project level debt. Enbridge’s equity contribution will be $0.3B; (4) Rounded, USD capital has been translated to CAD using an exchange rate of $1 U.S. dollar = $1.35 Canadian dollars. Euro capital has been translated to CAD using an exchange rate of €1 Euro = $1.45 Canadian dollars; (5) As at December 31, 2024 Secured capital program Project Expected ISD Capital ($B) Liquids Pipelines Gray Oak & Ingleside Expansion 2025-2026 0.1 USD Enbridge Houston Oil Terminal 2026 0.3 USD Mainline Capital Investment NEW 2025-2028 2.0 CAD Gas Transmission Modernization Program 2025-2028 2.8 USD Appalachia to Market Phase II 2025 0.1 USD Longview RNG 2025 0.1 USD Lexington RNG 2026 0.1 USD Tennessee Ridgeline 2026 1.1 USD T-North Expansion (Aspen Point) 2026 1.2 CAD Woodfibre LNG1 2027 1.5 USD Sparta 2028 0.2 USD T-South Expansion (Sunrise) 2028 4.0 CAD T-North Expansion (Birch Grove) NEW 2028 0.4 CAD Canyon 2029 0.7 USD Gas Distribution & Storage CAD Utility Growth Capital2 2025-2027 1.7 CAD Transmission/Storage Assets2 2025-2027 0.4 CAD New Connections/Expansions2 2025-2027 0.8 CAD U.S. Utility Growth Capital 2025-2027 3.1 USD Moriah Energy Center (Enbridge Gas North Carolina) 2027 0.6 USD T15 (Enbridge Gas North Carolina) 2027-2028 0.7 USD Renewables Calvados Offshore3 2027 1.0 CAD Orange Grove Solar 2025 0.3 USD Sequoia Solar 2025-2026 1.1 USD Total secured capital program $29B4 Capital spent to date $5B5 Diversified secured capital program with limited inflation risk
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61 First-choice energy provider Strategically positioned to serve all forms of energy demand Visible growth through end of the decade Disciplined capital allocation L Liquids pipeline Natural Gas pipeline Liquids storage Natural Gas storage Wind farms - onshore & offshore Solar energy operations RNG LNG facility Gas Distribution & storage R L L UK France Germany