ENBRIDGE INC

Enbridge is a leading North American energy infrastructure company. Our core businesses include Liquids Pipelines, which consists of pipelines and terminals in Canada and the US that transport and export various grades of crude oil and other liquid hydrocarbons; Gas Transmission, which consists of investments in natural gas pipelines and gathering and processing facilities in Canada and the US; Gas Distribution and Storage, which consists of natural gas utility operations that serve residential, commercial and industrial customers in Canada and the US; and Renewable Power Generation, which consists primarily of investments in wind and solar assets, as well as geothermal and power transmission assets, in North America and Europe.

Enbridge is a public company, with common shares that trade on the Toronto Stock Exchange (TSX) and New York Stock Exchange (NYSE) under the symbol ENB. We were incorporated on April 13, 1970 under the Companies Ordinance of the Northwest Territories and were continued under the Canada Business Corporations Act on December 15, 1987.

A more detailed description of each of our businesses and underlying assets is provided below under Business Segments.

CORPORATE VISION AND STRATEGY

VISION

Enbridge through its diversified businesses, fuels people’s quality of life in a safe and socially responsible manner in North America and beyond. Our vision is to provide energy in a planet-friendly way, everywhere people need it. In pursuing this vision, we seek to play a critical role in enabling the economic and social well-being of society by providing access to affordable, reliable, and secure energy through our infrastructure which transports, distributes, and generates energy, including liquids, natural gas, renewable power, and low-carbon fuels. We recognize that the energy system is changing, and we aim to provide a bridge to a cleaner energy future in a socially-responsible way, including selectively investing in lower-carbon energy technologies.

We aim to be a first-choice investment, supported by our investor value proposition of predictable and stable cash flows, a strong investment grade balance sheet to facilitate growth, a history of dividend increases, and a diversified opportunity set of growth projects in multiple jurisdictions to support continued EBITDA and distributable cash flow per share growth. Our assets are underpinned by long-term contracts, regulated cost-of-service tolling frameworks, power purchase agreements (PPAs), and other low-risk commercial arrangements.

We strive to be the leading first-choice energy delivery company in North America and beyond—for customers, communities, investors, regulators, policymakers, and employees. We approach this goal with a focus on worker and public safety, stakeholder relations, customer service, community investment, sustainability leadership, and employee engagement and satisfaction. As part of our community engagement, we remain committed to meaningful dialogue with Indigenous peoples to achieve common goals and constructive outcomes from our projects and operations. We also are committed to advancing investment opportunities with Indigenous groups, as demonstrated by recent partnerships on our oil pipelines and in the development of renewable energy projects.

STRATEGY

Our strategy is underpinned by a deep understanding of both local and global energy supply and demand fundamentals. Through disciplined capital allocation, aligned with our outlook on energy markets, we have become an industry leader with a diversified portfolio of infrastructure super systems across the North American continent, creating a platform for incremental growth. Our robust pipeline of project development opportunities, the integration of recent strategic acquisitions, and ongoing efficiency improvements are expected to drive our business forward. We remain confident in our balanced growth strategy and expect to continue to invest in our diversified footprint of both conventional businesses and complementary lower-carbon platforms. This includes extension and expansion opportunities to meet LNG exports and offshore gas, as well as leveraging North American electrification trends, including the expansion of data centers, where we can provide integrated customer solutions through our natural gas and renewable power businesses. Additionally, we are committed to effectively managing our emissions from our operations and building lasting and inclusive relationships with our stakeholders, including Indigenous peoples, our customers and employees.

Our assets have reliably generated low-risk, resilient cash flows through many different commodity, economic, and geopolitical environments. We believe that our asset quality, diversity, and ability to provide comprehensive solutions to customers which leverages expertise across our four business lines are key differentiators that enable us to be flexible in an uncertain business environment.

In order to continue to be an industry leader and to create value over the short and long term, we maintain a robust strategic planning process. We regularly conduct scenario and resiliency analysis on both our assets and business strategy. We test various value enhancement and maximization options, and we regularly engage with our Board of Directors (the Board) to promote alignment and maintain active oversight. This Board participation includes updates and discussions throughout the year and a dedicated annual strategic planning session. Going forward, we will continue to use this comprehensive approach to guide our investment decisions.

Consistent with our strategy, we have progressed several of our priorities in 2024. For example:

•We completed the acquisition of the US Gas Utilities with operations in Idaho, North Carolina, Ohio, Utah and Wyoming, creating the largest natural gas utility franchise in North America, providing visible, low-risk, long-term, rate base growth.

•Our Liquids Pipelines business exported record volumes through our Enbridge Ingleside Energy Center (EIEC), received approval from the Canada Energy Regulator (CER) in 2024 for our Mainline Tolling negotiated settlement through to 2028, sanctioned an expansion of the Gray Oak pipeline and incremental capacity at the EIEC following successful open seasons, and acquired marine docks with land adjacent to EIEC, further advancing our Permian export strategy.

•Our Gas Transmission business reached a negotiated settlement with shippers on Texas Eastern, announced and closed the Whistler Parent JV, a joint venture formed by Enbridge, WhiteWater/I Squared Capital and MPLX LP, connecting Permian Basin natural gas supply to growing LNG and other US Gulf Coast demand, and achieved final investment decision on the Tennessee Ridgeline Expansion and Blackcomb Natural Gas Pipeline. We also expanded our footprint in the Gulf Coast by sanctioning the Canyon System Pipelines and the formation of a joint venture to service the Sparta offshore development to serve BP, Shell and Equinor Gulf Coast developments. We also expanded our exposure to LNG by sanctioning the Venice Extension Project, which supplies the Venture Global Plaquemines LNG facility. We continue to work with customers on opportunities to supply new gas-fired power generation relating to data centers and growth of electricity demand generally, and capitalize on strong gas fundamentals to deliver safe, reliable, and lower-carbon energy to North Americans while simultaneously growing LNG exports.

•Our Gas Distribution and Storage business continued to advance its incentive regulation rate application in Ontario by filing a settlement proposal for the second phase of our 2024 rebasing application with the Ontario Energy Board (OEB), added approximately 36,000 new customers across our Ontario utilities business, commenced the integration of the Acquisitions, including its three million customers, and capitalized on increasing electric power and industrial demand - for example, by contracting gas supply to provide 200 megawatts (MW) of data center power in Utah and building the Moriah Energy Center, a 2 billion cubic feet LNG facility, to enable system growth and maintain reliability in North Carolina. We remain committed to assessing low-risk, capital investment opportunities, and providing cost-effective, reliable and lower-carbon energy to customers in Ontario, Quebec, Ohio, North Carolina, Utah, Wyoming, and Idaho.

•Our Renewable Power Generation business continued to execute on growth opportunities, including through our onshore business with the sanctioning of Orange Grove Solar in Texas (backed by a PPA with AT&T), Sequoia Solar in Texas (backed by a PPA with AT&T and Toyota), completion of Fox Squirrel Solar Phase 2 and 3 in Ohio (backed by a PPA with Amazon), and the announcement of the Seven Stars Energy Project, our first renewable power indigenous partnership focused on wind energy generation in Saskatchewan. We also continued to progress opportunities in our Offshore Wind business in Europe, including placing the Fécamp project into service, delivering first power to the French grid from the Provence Grand Large floating offshore wind project and more recently, winning an offshore wind farm tender for a project in the Mediterranean Sea off the southern coast of France.

•We continued to make meaningful progress towards our ESG goals. We further strengthened our relationships with Indigenous communities across North America while advancing our reconciliation commitments as a part of our Indigenous Reconciliation Action Plan, meeting 12 of 22 commitments. We are striving to reduce emissions from our operations through multiple pathways, including system modernization, and continued investment in our lower-carbon businesses.

•We continue to recycle capital at attractive valuations; in 2024, this included completing the sale of our interests in the Alliance Pipeline and Aux Sable facility. We remain focused on disciplined capital allocation, portfolio optimization and diversification, the continued enhancement of our industry leading cash flow profile and financial strength and flexibility. In addition, we continue to prioritize operating cost reductions across our business to increase our competitiveness and profitability.

These achievements are discussed in further detail in Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Looking ahead, our near-term strategic priorities remain similar to past years. As always, proactively advancing the safety of our assets, protecting the environment, and maintaining system reliability remain our top priorities. We are focused on enhancing the value of our existing assets through further optimization, capitalizing on our extensive infrastructure to meet evolving customer needs, prioritizing in-franchise organic growth and export-driven opportunities, and continuing to develop lower-carbon platforms across all our businesses.

As an example, we are continuing to pursue opportunities related to electrification in North America, where we can utilize our existing gas transmission and distribution infrastructure to safely deliver gas to new and existing power plants being developed, given surging power demand. We are also pursuing opportunities to build new natural gas infrastructure along our network and within our gas distribution territories, combined with providing gas supply and storage to customers, to support this growth. To complement our natural gas offerings, we are also able to provide renewable energy solutions (electricity and renewable credits/offsets) to customers, which we view as a strategic competitive advantage, enabling us to expand our customer base and further extend our growth.

We expect to continue to invest on an attractive, risk-adjusted basis to advance our strategy and build a sustainable competitive advantage.

Our key strategic priorities include:

Safety and Operational Reliability

Safety and operational reliability are the foundation of our strategy. We strive to achieve and maintain industry leadership in all facets of safety - process, public, and personal - and ensure the highest standards of reliability and integrity across our system to protect our communities and the environment.

Extend Growth

The cornerstone of our growth lies in the successful execution of our slate of secured projects (currently $26 billion through 2029) on schedule and within estimated costs, while maintaining standards for safety, quality, customer satisfaction, and environmental and regulatory compliance. For a discussion of our current portfolio of capital projects refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Growth Projects - Commercially Secured Projects.

We continue to seek additional high-quality growth opportunities across all our platforms, and deploy capital towards optimal uses, prioritizing balance sheet strength, investment in low capital intensity growth, and regulated utility or utility-like projects. Our scale and diversification drive competitive advantages across the enterprise and generate opportunities for collaboration across the business units. The four business segments we operate share commercial advantages and strong stakeholder relationships that enable opportunities to cross-sell to customers across the business units, providing additional value and the potential for future growth. We will carefully assess our remaining investable capacity, deploying capital to the most value-enhancing opportunities available to us, including further organic growth, and complementary accretive "tuck-in" acquisitions that improve our competitive positioning or further strengthen our balance sheet.

Looking ahead, we see strong utilization of our network and opportunities for growth within each of our businesses. For example, we expect that:

•Our liquids pipelines infrastructure will remain a vital connection between key supply basins and demand-pull markets such as the refinery hubs in the US Midwest, eastern Canada, and the US Gulf Coast. We are advancing discussions with customers for additional Western Canadian Sedimentary Basin pipeline capacity in 2026 and beyond. We will continue to explore capital efficient growth opportunities via system expansions and optimization of operations. Our export infrastructure will also enable the transportation of crude oil, cleaner fuels, and other export opportunities. Building on our early experience, we expect that carbon capture and storage (CCS) offers the potential to provide additional new growth opportunities within our footprint in jurisdictions with supportive regulatory regimes.

•Our natural gas transmission business will seek extension and expansion opportunities driven by new load demand from gas-fired power generation (including for data centers, electrification, and reshoring), industrial growth, and coastal LNG plants. The strategic asset position we possess produces opportunities to accelerate growth and meet customer needs. Our rate regulated cost-of-service business model creates secured growth opportunities that yield predictable, low-risk cash flows. We are also focused on facilitating the connection of new gas supply to key demand centers and the build-out of our Permian gas value chain. Looking forward, we expect the integration of producing and blending RNG into our system to enhance asset longevity, enable us to offer differentiated lower-carbon solutions to customers and further decarbonize our gas offerings.

•Our North American gas distribution and storage business will continue to grow through customer additions and modernization investments. Data center driven demand presents an opportunity for the business to expand services by fueling natural gas power plants. We believe system and storage enhancements in the business will increase system flexibility, reliability, and price stability for customers.

•Our renewable power business continues to be well positioned to capitalize on the growth of renewables in North America and Europe through disciplined investment in diversified renewable technologies and selective development in supportive jurisdictions where we have an established presence. We will continue to leverage our strong internal capabilities and our existing partnerships to successfully execute our large development portfolio.

In addition, we aim to drive growth with a focus on optimization, modernization, productivity, and efficiency across all our businesses. Examples include: the application of drag-reducing agents and pump station modifications to optimize throughput on our liquids system, the execution of toll settlements and rate case filings to optimize revenue within our liquids pipeline and gas transmission franchises, the expansion of lower-carbon gas offerings to modernize and integrate value chains at our gas utilities, and the creation of sustainable cost savings across the organization through innovation, process improvement and system enhancements.

Maintain Financial Strength and Flexibility

Our financing strategies are designed to retain strong, investment-grade credit ratings so that we have the financial capacity to meet our capital funding needs and the flexibility to manage capital market disruptions. We expect that the current secured capital program can be readily financed through an equity self-funded model. For further discussion on our financing strategies, refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources.

Disciplined Capital Allocation

We assess the latest fundamental trends, monitor the business landscape, and proactively conduct business development activities with the goal of identifying an industry-leading capital deployment opportunity set. We screen, analyze, and assess these opportunities using a disciplined investment framework with the objective of effectively deploying capital to grow while achieving attractive risk-adjusted returns, within our low-risk "utility-like" business model.

All investment opportunities are evaluated based on their potential to advance our strategy, mitigate risks, support our ESG goals, and create additional financial flexibility. Our primary emphasis in the near term is on low capital intensity opportunities to enhance returns across existing businesses (organic expansions and optimizations), system modernization, and utility rate-based investments. We also continue to assess other strong value-enhancing opportunities, including accretive acquisitions that can complement our portfolio.

In evaluating typical investment opportunities, we also consider other potential capital allocation alternatives. Other alternatives for capital deployment depend on our current outlook and include further debt reduction, dividend increases, and share buy-backs.

Participate in Energy Transition Over Time

As the global population grows and standards of living continue to improve around the world, we expect energy demand to rise. We, and our society, increasingly recognize the need for secure and reliable energy while concurrently reducing global greenhouse gas (GHG) emissions. Accordingly, energy systems around the world are being gradually reshaped as industry participants, regulators, and consumers seek to balance these factors. As a diversified energy infrastructure company, we believe that we are well positioned to play a role in the energy transition by lowering the emissions-intensity of the conventional fuels we transport and store, supporting the switching from higher emission energy sources to lower-carbon options for our customers, and selectively developing and constructing future lower-carbon energy infrastructure.

We believe that diversification and innovation will play a significant role in the energy transition. To date, we have made significant investments in natural gas infrastructure, emissions reduction technologies, and renewable energy assets, helping to decrease our emissions and further expand our platforms to support the global energy transition. Our focus areas in renewable energy remain in utility-scale onshore solar and wind projects, and integrated clean-energy offerings and solutions for customers. We are also participating in the development of other lower-carbon platforms like RNG, blue ammonia, CCS, and hydrogen gas (H2) where we can leverage our infrastructure, capabilities, and stakeholder relationships to accelerate growth and extend the value of our existing assets. Additionally, potential new investments are evaluated to assess their alignment with our GHG emissions reduction goals.

We work closely with our customers and stakeholders to maintain a pulse on the pace of the energy transition and are actively leveraging our execution capabilities and sustainability leadership to advance our positioning as a differentiated energy provider. We regularly test our assets under various transition scenarios to assess the resiliency of our business.

STRATEGIC ENABLERS

To successfully execute on our strategy and build competitive advantage, we focus on maintaining leading-edge capabilities in sustainability, talent, technology, operations, development, and growth capabilities.

Sustainability and Environmental, Social and Governance

Sustainability is integral to our ability to deliver energy in a safe and reliable manner. How well we perform as a steward of our environment; as a safe operator of essential energy infrastructure; as an inclusive employer; and as a responsible corporate citizen is inextricably linked to our ability to achieve our strategic priorities and create long-term value for all our stakeholders.

In 2024, we published our 23rd annual Sustainability Report outlining our progress against our ESG goals 1. In particular, we:

•achieved our goal to reduce the emissions intensity of our operations (Scope 1 and Scope 2) from our 2018 base level through modernization and innovation of our system, front of the meter renewables, and execution of additional renewable power PPAs;

•surpassed both of our Board composition goals, progressed our efforts to strengthen inclusion in our workforce to enhance our business, and empowered our workforce through employee resource groups 1;

•made progress towards our Indigenous Reconciliation Action plan, including meeting 12 of 22 commitments; and

•continued to drive improvements towards our goal of zero safety incidents and injuries and progressed implementation of robust cyber defense programs.

Since setting our ESG goals in 2020, we have made considerable progress integrating sustainability into our strategy, governance, operations, and decision-making. We have linked sustainability performance to incentive compensation and are making meaningful progress towards these goals by executing on our action plans.

We are undertaking the following additional actions in support of our ESG goals:

•proactively working with organizations that are advancing emissions measurement and reduction guidelines for the midstream sector;

•collaborating with key suppliers on emissions reduction plans;

•further developing lower-carbon energy partnerships to drive innovation across our businesses, with a focus on renewable power, RNG, H2 and CCS; and

•continuing to advance our commitment to meaningful reconciliation and to building respectful and collaborative Indigenous partnerships.

We provide annual progress updates in our annual Sustainability Report which can be found athttps://www.enbridge.com/sustainability-reports. Unless otherwise specifically stated, none of the information contained on, or connected to, the Enbridge website, including our annual Sustainability Report, is incorporated by reference in, or otherwise part of, this Annual Report on Form 10-K.

Operations & Development

As a major infrastructure developer and operator, Enbridge focuses on excellence in our business, specifically in safety, regulatory, project execution, and efficiency. Safety is foundational at Enbridge and our safety-first mindset reflects our commitment to protecting the public, our workers, the environment, and the health of our pipelines and facilities. We recognize the importance of having strong trusted relationships with our regulators as we plan and execute projects and sustain ongoing operations. We are committed to being proactive on regulatory matters at the federal, regional, and local levels to develop and maintain a safe and reliable energy system that our customers and the public can count on.

Robust project development, execution, governance, stakeholder relations, and supply chain processes are also key to delivering projects on time, at high quality, and within estimated costs. We continually seek ways to improve our organizational efficiency and effectiveness across all our core functions, including by streamlining structures, simplifying processes, improving accountability, and effectively managing risk to drive top-tier performance.

1 All percentages or specific goals regarding ESG are aspirational goals which we intend to achieve in a manner compliant with state, local, provincial and federal law, including, but not limited to, executive orders, US federal regulations, the Equal Employment Opportunity Commission, and the Department of Labor.

Talent

Our workforce is essential to our success and our focus remains on enhancing the capabilities and skills of our people. We are evolving our talent strategy enhancing our employee experience, and elevating our focus on learning and development. We value diversity of thought, and the focus on our approach to people leadership drives business performance. Furthermore, we strive to maintain industry-competitive compensation, flexibility, and retention programs that provide both short- and long-term performance incentives. We prioritize inclusion, along with our other business strategies because it is fundamentally important to our values and culture.

Technology

We recognize the vital role technology plays in helping us achieve our strategic objectives. We are committed to pursuing innovation and technology solutions that further our safety and reliability, maximize revenues, reduce costs, and enable transition to new, cleaner energy solutions. We continue to focus on resilience and reliability of our systems from a cybersecurity perspective and work to enhance our capabilities and educate our workforce to protect our critical infrastructure system from increasing threats. We also announced a collaboration with Microsoft leveraging artificial intelligence (AI) to drive advancements in safety, emissions reductions, and asset optimization.

Growth Capabilities

To achieve our vision and mission, we emphasize specific capabilities that will help us grow and build competitive advantage within our core and potential new businesses. We are increasing our focus on our customers so that we are responsive to their needs while also proactively helping them meet their decarbonization objectives. We are continuing to invest in leading corporate development capabilities to ensure we identify and execute on attractive capital recycling opportunities and acquisitions. Finally, we believe that the future energy system will not only continue to be highly integrated, but also become more complex. This will require an ecosystem of stakeholders to develop and manage from customers and lenders to equipment manufacturers and regulators. We believe it is critical to have strengths in partnership structuring and relationship management to build and maintain the robust energy infrastructure systems.

BUSINESS SEGMENTS

During 2024, our activities were carried out through four business segments: Liquids Pipelines, Gas Transmission, Gas Distribution and Storage, and Renewable Power Generation, as discussed below.

Liquids Pipelines consists of pipelines and terminals in Canada and the US that transport and export various grades of crude oil and other liquid hydrocarbons, which delivers approximately six million barrels per day (mmbpd) and is the largest global crude oil and liquids network.

MAINLINE SYSTEM

The Mainline System is a common carrier pipeline comprised of the Canadian Mainline and the Lakehead System. The Canadian Mainline transports various grades of crude oil and other liquid hydrocarbons within western Canada and from western Canada to the Canada/US border near Gretna, Manitoba and Neche, North Dakota and from the US/Canada border near Port Huron, Michigan and Sarnia, Ontario to eastern Canada. The Canadian Mainline includes six adjacent pipelines with a combined operating capacity of approximately 3.2 mmbpd that connect with the Lakehead System at the Canada/US border, as well as five pipelines that deliver crude oil and refined products into eastern Canada. Through our predecessors, we have operated, and frequently expanded, the Canadian Mainline since 1949. The Lakehead System is the portion of the Mainline System in the US. It is an interstate common carrier pipeline system regulated by the Federal Energy Regulatory Commission (FERC) and is the primary transporter of crude oil and liquid hydrocarbons from western Canada to the US.

Tolling Framework

The Mainline Tolling Settlement (MTS) is a negotiated settlement with a term of seven and a half years through the end of 2028 that covers both the Canadian and US portions of the Mainline, except for Lines 8 and 9 which are tolled on a separate basis. Enbridge filed an application with the CER for approval of the MTS on December 15, 2023 and the CER issued an order on March 4, 2024 approving Enbridge’s application as filed. The MTS provides for a Canadian Local Toll for deliveries within western Canada, as well as an International Joint Tariff (IJT) for crude oil shipments originating in western Canada, on the Canadian Mainline, and delivered into the US, via the Lakehead System, and into eastern Canada. Under the MTS, the Mainline operates as a common carrier system available to all shippers on a monthly nomination basis.

The MTS includes:

•an IJT, for heavy crude oil movements from Hardisty to Chicago, comprised of an initial Canadian Mainline Toll of $1.65 per barrel plus an initial Lakehead System Toll of US$2.57 per barrel, plus the applicable Line 3 Replacement surcharge;

•toll escalation for operation, administration, and power costs tied to US consumer price and US and Canadian power indices;

•tolls that are distance and commodity adjusted, and utilize a dual currency IJT; and

•a financial performance collar that provides incentives for Enbridge to optimize throughput and cost, but also provides downside protection in the event of extreme supply or demand disruptions or unforeseen operating cost exposure. This performance collar is intended to ensure the Mainline earns 11% to 14.5% returns, on a deemed 50% equity capitalization.

Approximately 70% of Mainline deliveries are tolled under this settlement, while approximately 30% of deliveries are tolled on a full path basis to markets downstream of the Mainline.

Lakehead System Local Tolls

Transportation rates are governed by the FERC for deliveries from the Canada/US border near Neche, North Dakota, Clearbrook, Minnesota and other points to principal delivery points on the Lakehead System. The Lakehead System periodically adjusts these transportation rates as allowed under the FERC’s index methodology and tariff agreements, the main components of which are index rates and the Facilities Surcharge Mechanism. Index rates, the base portion of the transportation rates for the Lakehead System, are subject to an annual inflationary adjustment which cannot exceed established ceiling rates as approved by the FERC. The Facilities Surcharge Mechanism allows the Lakehead System to recover costs associated with certain shipper-requested projects through an incremental surcharge in addition to the existing base rates and is subject to annual adjustment on April 1 of each year.

The Lakehead tolls are subject to an Offer of Settlement approved by the FERC on November 27, 2023 (Lakehead System Settlement). Lakehead System tolls were revised to reflect the terms of the Lakehead System Settlement effective December 1, 2023.

The Lakehead System Settlement includes:

•a resolution of litigation related to the index portion of the Lakehead System rate; and

•a depreciation truncation date of December 31, 2048 for the rate base applicable to the Index and Facilities Surcharge and agreement on the terms for future recovery through the Facilities Surcharge of costs related to two Line 5 projects: the Wisconsin Relocation Project and the Straits of Mackinac Tunnel.

REGIONAL OIL SANDS SYSTEM

The Regional Oil Sands System includes seven intra-Alberta long-haul pipelines: the Athabasca Pipeline, Waupisoo Pipeline, Woodland and Woodland Extension Pipelines, Wood Buffalo and Wood Buffalo Extension/Athabasca Twin pipeline system and the Norlite Pipeline System (Norlite), as well as two large terminals: the Athabasca Terminal located north of Fort McMurray, Alberta and the Cheecham Terminal, located south of Fort McMurray, Alberta. The Regional Oil Sands System also includes numerous laterals and related facilities which provide connectivity for several oil sands customers to the Edmonton and Hardisty areas.

The combined capacity of the intra-Alberta long-haul pipelines is approximately 1,120 thousand barrels per day (kbpd) to Edmonton and 1,415 kbpd into Hardisty, with Norlite providing approximately 218 kbpd of diluent capacity into the Fort McMurray region. We have a 50% interest in the Woodland Pipeline and a 70% interest in Norlite. The Regional Oil Sands System is anchored by long-term agreements with multiple oil sands producers that provide cash flow stability and also include provisions for the recovery of some of the operating costs of this system.

On October 5, 2022, we completed a transaction with Athabasca Indigenous Investments Limited Partnership (Aii), a newly created entity representing 23 First Nation and Metis communities, pursuant to which Aii acquired an 11.6% non-operating interest in the seven intra-Alberta long-haul pipelines in the Regional Oil Sands System.

GULF COAST AND MID-CONTINENT

Gulf Coast includes Flanagan South, Spearhead Pipeline, Seaway Crude Pipeline System (Seaway Pipeline), the Mid-Continent System (Cushing Terminal), Gray Oak, and the EIEC.

Flanagan South is a 950 kilometer (590 mile), 36-inch diameter interstate crude oil pipeline that originates at our terminal at Flanagan, Illinois, a delivery point on the Lakehead System, and terminates in Cushing, Oklahoma. Flanagan South has a capacity of approximately 700 kbpd.

Spearhead Pipeline is a long-haul pipeline that delivers crude oil from Flanagan, Illinois, a delivery point on the Lakehead System, to Cushing, Oklahoma. The Spearhead Pipeline has a capacity of approximately 193 kbpd.

We have a 50% interest in the 1,078 kilometer (670 mile) Seaway Pipeline, including the 805 kilometer (500 mile), 30-inch diameter long-haul system between Cushing, Oklahoma and Freeport, Texas, as well as the Texas City Terminal and Distribution System which serve refineries in the Houston and Texas City areas. Total aggregate capacity on the Seaway Pipeline system is approximately 950 kbpd. The Seaway Pipeline also includes 8.8 million barrels of crude oil storage tank capacity on the Texas Gulf Coast.

The Mid-Continent System is comprised of storage terminals at Cushing Terminal, consisting of over 110 individual storage tanks ranging in size from 78 to 570 thousand barrels. Total storage shell capacity of Cushing Terminal is approximately 26 million barrels. A portion of the storage facilities are used for operational purposes, while the remainder is contracted to various crude oil market participants for their term storage requirements. Contract fees include fixed monthly storage fees, throughput fees for receiving and delivering crude to and from connecting pipelines and terminals, and blending fees.

Gray Oak is a 1,368 kilometer (850 mile) crude oil system, transporting light crude oil, with origination points in the Eagle Ford and Permian Basins in West Texas. Gray Oak has delivery points at the US Gulf Coast and Houston refining region and currently has an average annual capacity of 900 kbpd; a planned expansion in 2025 will increase average annual capacity to 1,020 kbpd. Our effective economic interest in Gray Oak is 68.5% after our acquisition of Rattler Midstream’s 10% interest in the pipeline in 2023. We assumed operatorship of Gray Oak in April 2023.

In October 2021, we acquired 100% of Moda Midstream Operating, LLC, which includes the EIEC, the largest crude oil export terminal by volume in North America. EIEC has an export capability of 1.6 million barrels per day. In 2024 we added a further 2 million barrels of storage at EIEC, bringing EIEC’s total storage capability to 17.6 million barrels. We also own 100% interest in each of the 300-kbpd Viola pipeline, and the 350-thousand barrel Taft Terminal, both located near Corpus Christi, Texas. Additionally, in October 2024 we completed the acquisition of two marine docks and land adjacent to EIEC from Flint Hills Resources. This acquisition will add crude oil export capacity and streamline existing EIEC operations by increasing Very Large Crude Carrier windows on the primary facility docks. In November 2022, we acquired an additional 10% ownership interest in Cactus II Pipeline, a pipeline that travels from Wink to Ingleside within Texas, bringing our total non-operating ownership to 30%.

OTHER

Other includes Southern Lights Pipeline, Express-Platte System, Bakken System and Feeder Pipelines and Other.

The Southern Lights Pipeline is a single stream 180 kbpd 16/18/20-inch diameter pipeline that ships diluent from the Manhattan Terminal near Chicago, Illinois to three western Canadian delivery facilities, located at the Edmonton and Hardisty terminals in Alberta and the Kerrobert terminal in Saskatchewan. Both the Canadian portion and the US portions of the Southern Lights Pipeline receive tariff revenues under long-term contracts with committed shippers. The Southern Lights Pipeline capacity is 90% contracted with the remaining 10% of the capacity assigned for shippers to ship uncommitted volumes. A fully subscribed open season was completed in December 2023, which has ensured contract levels remain at 90% through mid-2030.

The Express-Platte System consists of the Express Pipeline and the Platte Pipeline, and crude oil storage of approximately 5.6 million barrels. It is an approximate 2,736 kilometer (1,700 mile) long crude oil transportation system, which begins at Hardisty, Alberta, and terminates at Wood River, Illinois. The 310 kbpd Express Pipeline carries crude oil to US refining markets in the Rocky Mountains area, including Montana, Wyoming, Colorado and Utah. The 145 to 164 kbpd Platte Pipeline, which interconnects with the Express Pipeline at Casper, Wyoming, transports crude oil predominantly from the Bakken shale and western Canada to refineries in the Midwest. The Express Pipeline capacity is typically committed under long-term take-or-pay contracts with shippers. A small portion of the Express Pipeline capacity and all of the Platte Pipeline capacity is used by uncommitted shippers who pay only for the pipeline capacity they actually use in a given month.

The Bakken System consists of the North Dakota System and the Bakken Pipeline System. The North Dakota System services the Bakken Basin in North Dakota and is comprised of a crude oil gathering and interstate pipeline transportation system. The gathering system provides delivery to Clearbrook, Minnesota for service on the Lakehead system or a variety of interconnecting pipelines. The interstate portion of the system has both US and Canadian components that extend from Berthold, North Dakota into Cromer, Manitoba.

Tariffs on the US portion of the North Dakota System are regulated by the FERC. The Canadian portion is categorized as a Group 2 pipeline, and as such, its tolls are regulated by the CER on a complaint basis.

We have an effective 27.6% interest in the Bakken Pipeline System, which connects the Bakken Basin in North Dakota to markets in eastern Petroleum Administration for Defense Districts (PADD) II and the US Gulf Coast. The Bakken Pipeline System consists of the Dakota Access Pipeline from the Bakken area in North Dakota to Patoka, Illinois, and the Energy Transfer Crude Oil Pipeline from Patoka, Illinois to Nederland, Texas. Current capacity is approximately 750 kbpd of crude oil with the potential to be expanded through additional pumping horsepower. The Bakken Pipeline System is anchored by long-term throughput commitments from a number of producers.

Feeder Pipelines and Other includes a number of liquids storage assets and pipeline systems in Canada and the US.

Key assets included in Feeder Pipelines and Other are the Hardisty Contract Terminal and Hardisty Storage Caverns located near Hardisty, Alberta, a key crude oil pipeline hub in western Canada and the Southern Access Extension (SAX) Pipeline which originates in Flanagan, Illinois and delivers to Patoka, Illinois. We have an effective 65% interest in the 300 kbpd SAX pipeline. The majority of the SAX Pipeline's capacity is commercially secured under long-term take-or-pay contracts with shippers.

Feeder Pipelines and Other also includes Patoka Storage, the Toledo pipeline system and the Norman Wells (NW) System. Patoka Storage is comprised of four storage tanks with 480 thousand barrels of shell capacity located in Patoka, Illinois. The 180 kbpd Toledo pipeline system connects with the Lakehead System and delivers to Ohio and Michigan. The 45 kbpd NW System transports crude oil from Norman Wells in the Northwest Territories to Zama, Alberta and has a cost-of-service rate structure based on established terms with shippers.

CRUDE OIL MARKETING

The Liquids Pipelines segment also includes the Crude Oil Marketing business in Canada and the US, which provides physical commodity marketing and logistical services to North American refiners, producers, and other customers. The business is primarily focused on servicing customers across the value chain and capturing value from quality, time, and location price differentials when opportunities arise. To execute these strategies, the Crude Oil Marketing business transports and stores on both Enbridge-owned and third-party assets using a combination of contracted pipeline, storage, railcar, and truck capacity agreements.

Competition for our liquids pipelines network comes primarily from infrastructure or logistics alternatives (e.g., rail or trucking) that transport liquid hydrocarbons from production basins in which we operate to markets in Canada, the US and internationally. Competition from existing pipelines, such as the recently completed Trans Mountain Pipeline expansion, is based primarily on access to supply, end use markets, the cost of transportation, contract structure and the quality and reliability of service. Additionally, volatile crude price differentials and insufficient pipeline capacity on either our or competitors' pipelines can make transportation of crude oil by rail competitive, particularly to markets not currently served by pipelines.

We believe that our liquids pipelines systems will continue to provide competitive and attractive options to producers in the Western Canadian Sedimentary Basin (WCSB), North Dakota, and the Permian Basin, due to our market access, competitive tolls and flexibility through our multiple delivery and storage points. We also employ long-term agreements with shippers, which mitigates competition risk by ensuring consistent supply to our liquids pipelines network. We have a proven track record of successfully executing projects to meet the needs of our customers.

Earnings from our Crude Oil Marketing business are primarily generated from arbitrage opportunities which, by their nature, can be replicated by competitors. An increase in market participants entering into similar arbitrage strategies could have an impact on our earnings. Efforts to mitigate competition risk include diversification of the marketing business by transacting at the majority of major hubs in North America and establishing long-term relationships with clients and pipelines.

We have an established and successful history of being the largest transporter of crude oil to the US, the world’s largest market for crude oil. We expect US demand for Canadian crude oil production will support the use of our infrastructure for the foreseeable future.

Under most base case forecasts, demand is expected to grow into the next decade, primarily driven by emerging economies in regions outside the Organization for Economic Cooperation and Development (OECD), such as India and broader Southeast Asia. In North America, demand growth for transportation fuels is expected to slow down over time due to vehicle fuel efficiency improvement and rising adoption of electric vehicles.

The Organization of Petroleum Exporting Countries is expected to continue to balance markets and manage prices with production quotas despite accelerated developments of offshore production in both Brazil and Guyana and continued growth from Canada and the US. In the US, growth will likely be driven by the Permian Basin, a large and cost competitive light crude oil resource base. In addition, heavy crude oil growth is expected from the WCSB as additional egress availability will likely support expansion of existing projects and some potential new greenfield facilities.

Our Mainline System was effectively fully utilized in 2024 delivering 3.1 mmbpd. Refinery demand in the upper Midwest PADD II market has been strong. On the US Gulf Coast, lower supply of heavy crude from Latin America and the Middle East continues to drive increased demand for Canadian heavy crude. Many of the refineries connected to the Mainline System are complex and competitive in the global context.

The anticipated combination of long-term demand growth in non-OECD nations, domestic demand contraction over time, and continued production growth in the Permian Basin and WCSB, highlights the importance of our strategic asset footprint and reinforces the need for additional export-oriented infrastructure. We believe that we are well positioned to meet these evolving supply and demand fundamentals through expansion of system capacity for incremental access to the US Gulf Coast, and through further development of our EIEC in Corpus Christi, including the full integration and optimization of the Flint Hills marine docks and land acquired in October 2024.

Opposition to fossil fuel development in conjunction with evolving consumer preferences and new technologies could underpin energy transition scenarios impacting long-term supply and demand of crude oil. We continue to closely monitor the evolution of all of these factors to be able to proactively adapt our business to help meet our customers’ and society’s energy needs.

These supply and demand dynamics are evolving, as the current political climate in Canada and the US continues to shift, including as a result of changes in governments and trade relations. We continue to monitor these developments together with their impact on our business.

Gas Transmission consists of our investments in natural gas pipelines and gathering and processing facilities in Canada and the US, including US Gas Transmission, Canadian Gas Transmission, US Midstream and Other assets.

US GAS TRANSMISSION

US Gas Transmission includes ownership interests in Texas Eastern Transmission, LP (Texas Eastern), Algonquin Gas Transmission, LLC (Algonquin), Maritimes & Northeast (M&N) (US and Canada), East Tennessee Natural Gas, LLC (East Tennessee), Gulfstream Natural Gas System, L.L.C. (Gulfstream), Sabal Trail Transmission, LLC (Sabal Trail), NEXUS Gas Transmission, LLC (NEXUS), Valley Crossing Pipeline, LLC (Valley Crossing), Southeast Supply Header, LLC (SESH), Vector Pipeline L.P. (Vector), Whistler Parent, LLC (Whistler Parent JV), Delaware Basin Residue, LLC (DBR) and certain other gas pipeline and storage assets. The US Gas Transmission business primarily provides transmission and storage of natural gas through interstate pipeline systems for customers in various regions of the northeastern, southern and midwestern US.

The Texas Eastern interstate natural gas transmission system extends from supply and demand centers in the Gulf Coast region of Texas and Louisiana to supply and demand centers in Ohio, Pennsylvania, New Jersey and New York. Texas Eastern's onshore system has a peak day capacity of 12.0 billion cubic feet per day (bcf/d) of natural gas on approximately 13,745 kilometers (8,541 miles) of pipeline and associated compressor stations. Texas Eastern is also connected to five affiliated storage facilities that are partially or wholly-owned by other entities within the US Gas Transmission business, including the Tres Palacios Holdings LLC (Tres Palacios) storage facility that we acquired on April 3, 2023.

The Algonquin interstate natural gas transmission system connects with Texas Eastern’s facilities in New Jersey and extends through New Jersey, New York, Connecticut, Rhode Island and Massachusetts where it connects to M&N US. The system has a peak day capacity of 3.1 bcf/d of natural gas on approximately 1,817 kilometers (1,129 miles) of pipeline with associated compressor stations.

M&N US has a peak day capacity of 0.8 bcf/d of natural gas on approximately 552 kilometers (343 miles) of mainline interstate natural gas transmission system, including associated compressor stations, which extends from northeastern Massachusetts to the border of Canada near Baileyville, Maine. M&N Canada has a peak day capacity of 0.5 bcf/d on approximately 885 kilometers (550 miles) of interprovincial natural gas transmission mainline system that extends from Goldboro, Nova Scotia to the US border near Baileyville, Maine. We have a 78% interest in M&N US and M&N Canada.

East Tennessee’s interstate natural gas transmission system has a peak day capacity of 1.9 bcf/d of natural gas, crosses Texas Eastern’s system at two locations in Tennessee and consists of two mainline systems totaling approximately 2,449 kilometers (1,522 miles) of pipeline in Tennessee, Georgia, North Carolina and Virginia, with associated compressor stations. East Tennessee has an LNG storage facility in Tennessee and also connects to the Saltville storage facilities in Virginia.

Valley Crossing is an approximately 285 kilometer (177 mile) intrastate natural gas transmission system, with associated compressor stations. The pipeline infrastructure is located in Texas and provides market access of up to 2.6 bcf/d of design capacity to the Comisión Federal de Electricidad, Mexico’s state-owned utility.

Vector is an approximately 560 kilometer (348 mile) pipeline travelling between Joliet, Illinois in the Chicago area and Ontario. Vector can deliver 1.7 bcf/d of natural gas, of which 455 million cubic feet per day (mmcf/d) is leased to NEXUS. We have a 60% interest in Vector.

Gulfstream is an approximately 1,199 kilometer (745 mile) interstate natural gas transmission system with associated compressor stations. Gulfstream has a peak day capacity of 1.4 bcf/d of natural gas from Mississippi, Alabama, Louisiana and Texas, crossing the Gulf Coast to markets in central and southern Florida. We have a 50% interest in Gulfstream.

Sabal Trail is an approximately 832 kilometer (517 mile) interstate pipeline that provides firm natural gas transportation. Facilities include a pipeline, laterals and various compressor stations. The pipeline infrastructure is located in Alabama, Georgia and Florida, and adds approximately 1.0 bcf/d of capacity enabling the access of onshore gas supplies. We have a 50% interest in Sabal Trail.

NEXUS is an approximately 414 kilometer (257 mile) interstate natural gas transmission system with associated compressor stations. NEXUS transports natural gas from our Texas Eastern system in Ohio to our Vector interstate pipeline in Michigan, with peak day capacity of 1.4 bcf/d. Through its interconnect with Vector, NEXUS provides a connection to Dawn Hub, the largest integrated underground storage facility in Canada and one of the largest in North America, located in southwestern Ontario adjacent to the Greater Toronto Area. We have a 50% interest in NEXUS.

SESH is an approximately 462 kilometer (287 mile) interstate natural gas transmission system with associated compressor stations. SESH extends from the Perryville Hub in northeastern Louisiana where the shale gas production of eastern Texas, northern Louisiana and Arkansas, along with conventional production, is reached from six major interconnections. SESH extends to Alabama, interconnecting with 14 major north-south pipelines and three high-deliverability storage facilities and has a peak day capacity of 1.1 bcf/d of natural gas. We have a 50% interest in SESH.

The Whistler Parent JV holds a 100% interest in Whistler Pipeline, LLC (Whistler), a 450 mile intrastate pipeline with associated compressor stations that extends from the Permian Basin to Agua Dulce, Texas with a capacity of 2.5 bcf/d, a 70% interest in ADCC Pipeline, LLC (ADCC), a 40 mile pipeline that extends from Agua Dulce, Texas to Cheniere Energy’s Corpus Christi LNG export facility with a capacity of 1.7 bcf/d, and a 50% interest in Waha Gas Storage, LLC, a 2.0 bcf gas storage cavern facility connecting to key Permian egress pipelines including Whistler. We have a 19% interest in the Whistler Parent JV.

DBR holds a 100% interest in Agua Blanca, LLC, Waha Connector, LLC, and Gateway Pipeline, LLC, a combined network of pipelines that connects Permian supply to Whistler and other pipelines transporting natural gas from the Permian Basin to downstream markets, and the remaining 50% interest in Waha Gas Storage, LLC not held by Whistler Parent JV. We have a 15% interest in DBR.

Transmission and storage services are generally provided under firm agreements where customers reserve capacity in pipelines and storage facilities. The vast majority of these agreements provide for fixed reservation charges that are paid monthly regardless of the actual volumes transported on the pipelines, plus a small variable component that is based on volumes transported, injected or withdrawn, which is intended to recover variable costs.

Interruptible transmission and storage services are also available where customers can use capacity if it exists at the time of the request and are generally at a higher toll than long-term contracted rates. Interruptible revenues depend on the amount of volumes transported or stored and the associated rates for this service. Storage operations also provide a variety of other value-added services including natural gas parking, loaning and balancing services to meet customers’ needs.

CANADIAN GAS TRANSMISSION

Canadian Gas Transmission is comprised of Westcoast Energy Inc.’s (Westcoast) British Columbia (BC) Pipeline, and other minor midstream gas gathering pipelines. It also includes the Aitken Creek Gas Storage facility, located in BC, Canada, which we acquired on November 1, 2023.

The BC Pipeline provides natural gas transmission services, transporting processed natural gas from facilities located primarily in northeastern BC to markets in BC and the US Pacific Northwest. It has a peak day capacity of 3.6 bcf/d of natural gas on approximately 2,950 kilometers (1,833 miles) of transmission pipeline in BC and Alberta, as well as associated mainline compressor stations. BC Pipeline is regulated by the CER under cost-of-service regulation.

The majority of transportation services provided by Canadian Gas Transmission are under firm agreements, which provide for fixed reservation charges that are paid monthly regardless of actual volumes transported on the pipeline, plus a small variable component that is based on volumes transported to recover variable costs. Canadian Gas Transmission also provides interruptible transmission services where customers can use capacity if it is available at the time of request. Payments under these services are based on volumes transported.

US MIDSTREAM

US Midstream includes a 13.2% effective economic interest in DCP Midstream, LP (DCP). Prior to August 17, 2022, we had a 28.3% effective economic interest in DCP. DCP is a joint venture, with a diversified portfolio of assets, engaged in the business of gathering, compressing, treating, processing, transporting, storing and selling natural gas; producing, fractionating, transporting, storing and selling NGL; and recovering and selling condensate. DCP owns and operates more than 32 plants and approximately 86,016 kilometers (53,448 miles) of natural gas and NGL pipelines, with operations in nine states across major producing regions.

OTHER

Other consists primarily of our offshore assets. Enbridge Offshore Pipelines is comprised of 12 natural gas gathering and FERC regulated transmission pipelines and five oil pipelines. These pipelines are located in four major corridors in the Gulf Coast, extending to deepwater developments, and include almost 2,200 kilometers (1,365 miles) of underwater pipe and onshore facilities with total capacity of approximately 6.6 bcf/d.

In 2023, Enbridge acquired a 10% equity investment in Divert Inc., a RNG infrastructure company, which provides Enbridge with an option to invest up to $1.3 billion (US$1.0 billion) in food waste to RNG projects across the US.

On January 2, 2024, we acquired six Morrow Renewables operating landfill gas-to-RNG production facilities located in Texas and Arkansas. The acquired assets align with and advance our low-carbon strategy.

Our natural gas transmission and storage businesses compete with similar facilities that serve our supply and market areas in the transmission and storage of natural gas. The principal elements of competition are location, rates, terms of service, flexibility and reliability of service.

The natural gas transported in our business competes with other forms of energy available to our customers and end-users, including electricity, coal, propane, fuel oils, nuclear and renewable energy. Factors that influence the demand for natural gas include price changes, the availability of natural gas and other forms of energy, levels of business activity, long-term economic conditions, conservation, legislation, governmental regulations, the ability to convert to alternative fuels, weather and other factors.

Competitors predominantly include interstate/interprovincial and intrastate/intraprovincial pipelines or their affiliates and other midstream businesses that transport, gather, treat, process and market natural gas or NGL. Because pipelines are generally the most efficient mode of transportation for natural gas over land, the most significant competitors of our natural gas pipelines are other pipeline companies.

Our gas transmission assets make up one of the largest natural gas transportation networks in North America, driving connectivity between prolific supply basins and major demand centers within the continent. Our systems have been integral to the transition in supply and demand markets over the last decade, and we expect to continue to play a part as the energy landscape evolves.

Natural gas production in the Appalachian and Permian Basins has grown dramatically in the past decade. Today, these regions produce more than 54 bcf/d of natural gas on a combined basis. Improved technology and increased shale gas drilling have increased the supply of low-cost natural gas. As well, there has been, and continues to be, a corresponding increase in demand for our natural gas infrastructure in North America. Through a series of expansions and reversals on our core systems, combined with the execution of greenfield projects and strategic acquisitions, we have been able to meet the needs of both producers and consumers. Our US Gas Transmission systems were initially designed to transport natural gas from the Gulf Coast to the supply-constrained northeast markets. Our asset base now has the capability to transport diverse bi-directional supply to the northeast, southeast, Midwest, Gulf Coast and LNG markets on a fully subscribed and highly utilized basis.

The northeast market continues its role as a predominantly supply constrained region with steady demand. The bi-directional capabilities offered by our US Gas Transmission system allow us to deliver in an efficient manner to our regional customers. The region has seen an increase in natural gas supply due to the development of the Marcellus and Utica shales in the Appalachia region.

The southeast market is linked to multiple, highly liquid supply pools that include the Marcellus and Utica shale developments, offering consistent supply and stable pricing to a growing population of end-use customers across our multiple systems under long-term, utility-like arrangements.

With connectivity to Appalachian and western Canadian supply through our Westcoast Pipeline, the Midwest market has access to two of the lowest cost gas producing regions on the continent. As demand in the region is expected to remain stable over the next decade, maintaining this link will remain important. Flexibility in supply for this market is especially critical to maintaining liquidity and price stability as natural gas continues to replace coal-fired generation.

Gulf Coast demand growth is being driven by an increase in the volume of LNG exports, an ongoing wave of gas-intensive petrochemical facilities and additional pipeline exports to Mexico. Demand in these markets in the region is anticipated to grow by approximately 20 bcf/d through 2040. The Gulf Coast market has been the beneficiary of low-cost capacity on our assets as the relationship between supply and market centers has shifted. Such cost-effective capacity is difficult to access or replicate, offering existing shippers and transporters stability of capacity and utilization. Tide-water market access and proximity to Mexico continue to make this region a platform of global trade as pipeline and LNG exports continue their growth trajectory. In 2024, the US exported over 12 bcf/d of natural gas to LNG markets, primarily from the Gulf Coast region.

Western Canada is also a source of low-cost supply seeking access to premium markets in North America and globally. One of the few vital links to demand centers in the Pacific Northwest is our BC Pipeline, which is highly utilized. The continental supply profile has shifted to natural gas shale plays such as the Montney and Duvernay within western Canada. These plays are expected to fulfill an integral role as Canada enters the global market as an LNG exporter. Western Canada's production is forecasted to increase from 18 bcf/d in 2024 to 23 bcf/d by 2040. This growth will support an additional 5 bcf/d of LNG exports. These supply shifts have shaped our growth strategies and affect the nature of the projects anticipated in the capital expenditures discussed below in Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Growth Projects - Commercially Secured Projects.

Global energy demand is expected to increase approximately 20% by 2050, according to the recently released 2024 International Energy Agency (IEA) report, driven primarily by economic growth in non-OECD countries. According to the IEA Stated Policy Scenario, natural gas will play an important role in meeting this energy demand, and gas consumption is anticipated to grow by approximately 16% during this period as one of the world’s most significant energy sources. North American exports are expected to play a significant part in meeting global demand, underscoring the ability of our assets to remain highly utilized by shippers, and highlighting the need for incremental transportation solutions across North America, as well as for the further build-out of export facilities to meet international demand.

The long-term effects on global gas markets of the ongoing conflict in Ukraine remain uncertain. In 2022, Europe saw a sharp rise in natural gas prices due to a decrease in supply from Russia. Global LNG markets responded, and LNG cargoes were redirected from the Asian market to Europe which allowed Europe to meet peak demand during what turned out to be a mild winter. Natural gas storage volumes have been strong entering the 2024-2025 winter season in Europe, and mild winter temperatures have thus far helped to moderate prices. The outlook for gas prices remains somewhat volatile but is generally anticipated to see a gradual normalization as LNG export volumes are expected to ramp up in 2026-2027.

Europe continues to seek lower-carbon gas supplies and has accelerated plans to develop hydrogen as an alternative to natural gas. The global hydrogen market is still relatively immature, but with the introduction of new incentives, such as those in the US Inflation Reduction Actand the regulations enacted thereunder, hydrogen production at large scale is becoming increasingly commercialized, which has led to a growing export market. Given its proximity to low-cost natural gas supplies and suitable geologic storage for carbon dioxide, the US Gulf Coast is well positioned to be a leading export hub to supply blue hydrogen to international markets. Given these rapidly changing global fundamentals and coupled with growing appetite for lower-carbon hydrogen, we believe we are well positioned to provide value-added solutions to shippers and meet both regional and international demand.

Opposition to natural gas development, including new pipeline projects, exists in certain jurisdictions, which may challenge continued growth of the North American gas market and the ability to efficiently connect supply and demand. We are responding to the need for regional infrastructure with additional investments in Canadian and US gas transportation facilities. Progress on the development and construction of our commercially secured growth projects is discussed in Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Growth Projects - Commercially Secured Projects.

RNG is seen as a more environmentally friendly alternative to traditional natural gas, as it is derived from organic waste sources such as agricultural residues, food waste, and other organic waste material. The production process most commonly involves the anaerobic digestion of these organic materials, resulting in the generation of biogas composed primarily of methane. Unlike conventional natural gas, RNG is considered carbon-neutral or even carbon-negative, as the carbon dioxide that is ultimately released during combustion is offset by the carbon captured during the organic matter's growth. This closed-loop cycle can contribute to mitigating GHG emissions and help to address climate change concerns. RNG can be seamlessly integrated into existing natural gas infrastructure, offering a versatile energy source for heating, transportation, and electricity generation. As societies increasingly prioritize reducing emissions, RNG has the potential to play an important role in the transition towards a cleaner and more resilient energy future. Global RNG consumption is expected to increase with a 11% compound annual growth rate until 2050, according to IEA's recently released Stated Policy Scenario.

These supply and demand dynamics are evolving, as the current political climate in Canada and the US continues to shift, including as a result of changes in governments. We continue to monitor these developments together with their impact on our business.

Gas Distribution and Storage consists of our rate-regulated natural gas utility operations, which serves residential, commercial and industrial customers in Ontario, Quebec, Ohio, North Carolina, Utah, Wyoming, and Idaho as well as Wexpro Company (Wexpro), which develops and produces natural gas reserves on behalf of Enbridge Gas Utah, Enbridge Gas Wyoming, and Enbridge Gas Idaho. Our distribution systems, which are supported by storage and compression assets, carry natural gas from the point of local supply to customers across North America.

There are three principal interrelated aspects of the natural gas distribution business in which our franchises are directly involved: Distribution, Transportation and Storage. The number of customers, and approximate combined length of pipelines for each of our major distribution and transmission systems as at December 31, 2024 are as follows:

Our storage system principally consists of our assets at Dawn Hub and the Tecumseh Gas Storage facility.

Distribution

The principal source of revenue for Gas Distribution and Storage arises from the distribution of natural gas to customers. The services provided to residential, small commercial and industrial heating customers are primarily on a general service basis, without a specific fixed term or fixed price contract. The services provided to larger commercial and industrial customers are usually on an annual contract basis under firm or interruptible service contracts. Under a firm contract, we are obligated to deliver natural gas to the customer up to a maximum daily volume. The service provided under an interruptible contract is similar to that of a firm contract, except that it allows for service interruption at our option primarily to meet seasonal or peak demands. The respective regulator for each province or state approves rates for both contract and general services.

Customers have a choice with respect to natural gas supply. Customers may purchase and deliver their own natural gas to points upstream of the distribution system or directly into our distribution systems, or, alternatively, they may choose a system supply option, whereby customers purchase natural gas from our supply portfolio. A significant portion of our customers in Ohio participate in the Energy Choice program, under which residential customers are encouraged to purchase gas directly from retail suppliers or through a community aggregation program and have it delivered by us. Customers in our other franchise areas predominantly purchase gas from our diversified natural gas supply portfolio, which we maintain by acquiring supplies on a delivered basis, as well as acquiring supply from multiple supply basins across North America. Certain of our US Gas Utilities have a revenue decoupling mechanism whereby non-gas revenues are decoupled from the temperature-adjusted usage per customer, which allows for the collection of an allowed monthly revenue per customer and to promote energy conservation.

Transportation

Our gas utility franchises also offer transportation services to move gas through the areas we operate in to key markets throughout North America. Enbridge Gas Ontario contracts for firm transportation service, primarily with TransCanada Pipelines Limited, Vector and NEXUS, to meet its annual natural gas supply requirements. The transportation service contracts are not directly linked with any particular source of natural gas supply. Separating transportation contracts from natural gas supply provides flexibility in obtaining its own natural gas supply and accommodating the requests of its direct purchase customers for assignment of pipeline capacity.

In addition to contracting for transportation service, Enbridge Gas Ontario offers firm and interruptible transportation services on its own Dawn-Parkway pipeline system. Enbridge Gas Ontario’s transmission system also links an extensive network of underground storage pools at the Tecumseh Gas Storage facility and Dawn Hub (collectively, Dawn) to major Canadian and US markets, and forms an important link in moving natural gas from western Canada and US supply basins to central Canadian and northeastern US markets.

As the supply of natural gas in areas close to Ontario has continued to grow, there has been increased demand to access these diverse supplies at Dawn and transport them along the Dawn-Parkway pipeline system to markets in Ontario, eastern Canada and the northeastern US. A substantial amount of Enbridge Gas Ontario’s transportation revenue is generated by fixed annual demand charges.

Enbridge Gas Ohio system expansion projects over the last decade have provided the opportunity to offer transportation services as an attractive outlet for shale production, by virtue of its proximity to the Utica and Marcellus shale basins while enhancing on-system operational flexibility.

Storage

Our gas distribution business is highly seasonal as daily market demand for natural gas fluctuates with changes in weather, with peak consumption occurring in the winter months. Utilization of storage facilities permits us to take delivery of natural gas on favorable terms during off-peak summer periods for subsequent use during the winter heating season. This practice helps to minimize the annual cost of transportation of natural gas from its supply basins, assists in reducing our overall cost of natural gas supply and adds a measure of security in the event of any short-term interruption of transportation of natural gas to our franchise areas.

The storage facility at Dawn is located in southwestern Ontario and has a total working capacity of approximately 284 bcf in 33 underground facilities located in depleted gas fields. Dawn is the largest integrated underground storage facility in Canada and one of the largest in North America. Approximately 180 bcf of the total working capacity is available to Enbridge Gas Ontario for utility operations. There is approximately 60 bcf of underground storage in Ohio that provides additional flexibility for system reliability and managing the cost of supply for customers.

Dawn offers customers an important link in the movement of natural gas from western Canadian and US supply basins to markets in central Canada and the northeast US. Dawn's configuration provides flexibility for injections, withdrawals and cycling. Customers can purchase both firm and interruptible storage services at Dawn. Dawn offers customers a wide range of market choices and options with easy access to upstream and downstream markets. A substantial amount of Enbridge Gas Ontario’s storage revenue is generated by fixed annual demand charges.

Our gas distribution systems are regulated by the OEB, the Québec Régie de l’énergie, the Public Utilities Commission of Ohio (Ohio Commission), the North Carolina Utilities Commission (North Carolina Commission), the Utah Public Service Commission (Utah Commission), the Wyoming Public Service Commission (Wyoming Commission), and the Idaho Public Utilities Commission (Idaho Commission). Our gas distribution systems are not generally subject to third-party distribution competition within their franchise areas.

Our gas distribution business competes with other forms of energy available to customers and end-users, including electricity, coal, propane and fuel oils. Factors that influence the demand for natural gas include weather, price changes, the availability of natural gas and other forms of energy, the level of business activity, conservation, legislation, including the federal carbon pricing laws in Canada, governmental regulations, the ability to convert to alternative fuels, and other factors.

We anticipate that demand for natural gas in North America will stabilize over the long term with potential growth in peak day demands and from the data center build-out; however, there are risks to the natural gas market that may challenge its growth prospects.

Net-zero carbon policies, evolving customer preferences for lower-carbon fuels and more efficient technologies, combined with increasing opposition to natural gas development in certain parts of North America, may reduce the markets’ ability to efficiently deploy capital to connect supply and demand. We monitor these factors closely in order to align our business strategy with shifts in customer preferences and public policy requirements.

Enbridge continues to focus on promoting conservation and energy efficiency by undertaking activities focused on reducing natural gas consumption through various demand side management programs offered across all markets and sourcing supply with a smaller carbon footprint. In addition to our existing and proposed RNG programs, we are also continuing our efforts to source other lower-carbon supplies, such as hydrogen.

Supply and demand are also impacted by the legislative environments in which our franchises operate. For example, in 2024, Ontario passed Bill 165, the Keeping Energy Costs Down Act which reset the revenue horizon to 40 years for residential and small volume consumers and streamlined the regulatory process for pipelines between $2-$10 million. Ontario further demonstrated its support for gas in its vision paper for integrated energy planning where it confirmed its view that "Gas is a vital component of Ontario's energy mix". House Bill 507 was signed in Ohio officially defining natural gas as a "green energy". Ohio and Utah both passed bills in 2021 (House Bill 201 and House Bill 17, respectively) prohibiting bans on natural gas. The law prohibits municipalities and counties from enacting "an ordinance, a resolution, or a policy that prohibits, or has the effect of prohibiting, the connection or reconnection of an energy utility service." However, it does not block local or county officials from supporting electrification through incentives or restricting gas use in municipal or county buildings. In 2021, House Bill 951 was signed in North Carolina, directing the North Carolina Commission to develop a plan, known as the NC Carbon Plan, for a 70% reduction in carbon emissions in the electricity sector by 2030 that is driving coal-to-gas generation switching.

Over the past decade, growth in the North American gas supply landscape, driven mainly by the development of unconventional gas resources in the Montney, Permian, Marcellus and Utica supply basins, has resulted in lower annual commodity prices and narrower seasonal price spreads. Natural gas prices have been impacted by lower weather-related demand and higher North American inventory levels resulting in more stable and lower prices. Unregulated storage values are primarily determined by the difference in value between winter and summer natural gas prices.

Enbridge Gas Utah, Enbridge Gas Wyoming and Enbridge Gas Idaho have a cost-of-service agreement with Wexpro, which develops and produces natural gas reserves on behalf of the utility. Wexpro's production supplies up to 55% of annual demand for the utility (up to 65% if certain conditions are met and approvals obtained) and provides a physical hedge against commodity price volatility while maintaining the option to purchase from third-party suppliers at market rates through long-term contracts. Wexpro's operations stretch from the northern tip of the Greater Green River Basin in Pinedale, Wyoming, through the Vermillion Basin of Wyoming and Colorado, down to the Uinta Basin of Utah. Wexpro establishes its annual drilling program by forecasting the utility's consumption needs.

Operating since December 2022, Magna LNG is a 1.2 bcf LNG facility located in Magna, Utah. The facility provides system reliability for Enbridge Gas Utah's customers in Salt Lake City and the surrounding counties. LNG is produced primarily during the warmer months of the year and then stored to be used when needed for reliability.

Renewable Power Generation consists primarily of investments in wind and solar assets, as well as equity interests in geothermal power and power transmission assets. In North America, assets are primarily located in the provinces of Alberta, Ontario and Québec, and in the states of Colorado, Texas, Indiana, Ohio and West Virginia. In Europe, we hold equity interests in operating offshore wind facilities in the coastal waters of the United Kingdom, France, and Germany, as well as interests in several offshore wind projects under construction and active development in France and the United Kingdom.

Combined Renewable Power Generation investments represent approximately 3,500 MW of net generation capacity, which primarily consists of approximately:

•1,399 MW generated by North American wind facilities;

•621 MW generated by European offshore wind facilities;

•97 MW expected to be generated by the Calvados Offshore Wind Project in France, which is currently under construction; and

•440 MW generated by North American solar facilities in operation, with an additional 945 MW in projects in pre-construction and under construction.

The vast majority of the power produced from these facilities is sold under long-term PPAs.

JOINT VENTURES / EQUITY INVESTMENTS

Most of our investments in Canadian wind and solar assets and two of our US renewable assets are held within a joint venture in which we manage and operate a 51% interest. One of our US solar projects is held within a separate joint venture in which we hold a 50% interest.

We also own interests in European offshore wind facilities through the following joint ventures:

•a 24.9% interest in Rampion Offshore Wind, located in the United Kingdom;

•a 49.9% interest in Hohe See and Albatros Offshore Wind, located in Germany;

•a 25.5% interest in the Saint-Nazaire Offshore Wind Project, located in France;

•a 25% interest in the Provence Grand Large Floating Offshore Wind Project, located in France;

•a 17.9% interest in the Fécamp Offshore Wind Project, located in France; and

•a 21.7% interest in the Calvados Offshore Wind Project, under construction in France.

Renewable Power Generation operates in the North American and European power markets, which are subject to competition and supply and demand fundamentals for power in the jurisdictions in which it operates. The majority of our revenue is generated from long-term PPAs (or has been substantially hedged). As such, financial performance is not significantly impacted by fluctuating power prices arising from supply/demand imbalances or the actions of competing facilities during the term of the applicable contracts. However, the renewable energy sector includes large utilities, small independent power producers and private equity investors, which are expected to aggressively compete for new project development opportunities and for the right to supply customers when contracts expire.

To grow in an environment of heightened competition, we strategically target regions with commercial constructs consistent with our low risk business model. In addition, we leverage our expertise in developing and constructing large-scale infrastructure projects.

Renewable power generation in North America and Europe is expected to grow significantly over the next 20 years due to growing power demand and the replacement of retiring fossil fuel-based sources of electricity generation.

Strong load growth across North America is anticipated, driven by growing data center power demand and other large industrial load, as well as the continued electrification within the residential, transportation and industrial sectors. Furthermore, voluntary GHG emissions reduction targets are becoming increasingly expected by stakeholders, which is driving significant demand from corporate electricity end-users for cleaner electricity and environmental attributes.

In response to the growing demand outlook, North America requires significant new generation capacity from preferred technologies. Gas-fired and renewable energy facilities, including solar and wind (which make up the bulk of our renewable power assets), are generally the preferred sources to meet the increased load and replace coal-fired generation due to their lower-carbon intensities. Governments are also proposing tax incentives to support low-emission and renewable energy generation resource development. As renewable energy takes an increasing share of certain states’ and provinces’ electricity grids, governments are also proposing tax incentives for natural gas and battery development to help firm the variable generation on the grid.

Falling capital and operating costs of wind and solar, combined with their improving capacity factors, are expected to continue the ongoing trend of making renewable energy more competitive and support investment over the long-term, regardless of available government incentives. Generation from wind and solar sources is expected to more than triple over the next two decades in North America. Aside from the construction of new wind and solar facilities, other growth opportunities include repowering projects to increase output from and extend the project-life of our existing facilities.

In Europe, the renewable energy outlook is robust. Demand for electricity is expected to gradually increase over the next two decades, driven by electrification of transportation and buildings, and the desire to reduce reliance on gas sourced from Russia. Energy efficiency gains are expected to temper, but not eliminate, demand growth. Renewable power is expected to play a significant role in Europe’s ability to meet its aggressive lower-carbon and renewable energy targets.

We, through our European joint ventures, continue to invest in offshore wind projects in the United Kingdom, France and Germany, and to explore opportunities to meet the growing demand.

Eliminations and Other includes operating and administrative costs that are not allocated to business segments, the impact of foreign exchange hedge settlements and the activities of our wholly-owned captive insurance subsidiaries. The principal activity of our captive insurance subsidiaries is providing insurance and reinsurance coverage for certain insurable property and casualty risk exposures of our operating subsidiaries and certain equity investments. Eliminations and Other also includes new business development activities and corporate investments, and natural gas and power marketing and logistical services to North American refiners, producers, and other customers.

REGULATION

GOVERNMENT REGULATION

Pipeline Regulation

Our Liquids Pipelines and Gas Transmission assets are subject to numerous operational rules and regulations mandated by governments and applicable regulatory authorities, breaches of which could result in fines, penalties, operating restrictions and an overall increase in operating and compliance costs.

In the US, our interstate pipeline operations are subject to pipeline safety laws and regulations administered by the Pipeline and Hazardous Materials Safety Administration (PHMSA), an agency within the US Department of Transportation (DOT). These laws and regulations require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our interstate pipelines. These laws and regulations, among other things, include requirements to monitor and maintain the integrity of our pipelines and to operate them within permissible design limits such as pressures.

PHMSA continues to review existing regulations and establish new regulations to support safety and environmental standards that are designed to improve operations integrity management processes and reduce methane emissions. In this climate of increasingly stringent regulation, pipeline failure or failures to comply with applicable regulations could result in reduction of allowable operating pressures as authorized by PHMSA, which would reduce available capacity on our pipelines. Should any of these risks materialize, it may have an adverse effect on our operations, capital expenditures, earnings, cash flows, financial condition and competitive advantage.

Our ability to establish transportation and storage rates on our US interstate natural gas facilities is subject to regulation by the FERC, whose rulings and policies could have an adverse impact on the ability to recover the full cost of operating these pipeline and storage assets, including a reasonable rate of return. Regulatory or administrative actions by the FERC such as rate proceedings, applications to certify construction of new facilities, and depreciation and amortization policies, can affect our business, including decreasing tariff rates and revenues and increasing our costs of doing business.

In Canada, our pipelines are subject to safety regulations administered by the CER or provincial regulators. Applicable legislation and regulations require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our pipelines. Among other obligations, this regulatory framework imposes requirements to monitor and maintain the integrity of our pipelines.

As in the US, laws and regulations addressing enhanced pipeline safety in Canada have been enacted over the past few years and are continuously being monitored. These changes demonstrate an increased focus on the implementation of management systems to address key areas, such as emergency management, integrity management, safety, security and environmental protection. The CER has authority to impose administrative monetary penalties for non-compliance with the regulatory regime it administers, as well as to impose financial requirements for future abandonment and major pipeline releases.

A key component of pipeline safety and reliability is the approach to integrity management that uses reliability targets and safety case assessments. A long history of extensive inline inspection has provided detailed knowledge of the assets in our pipeline systems. Our pipelines are assessed and maintained in a proactive manner in order to meet reliability targets. Furthermore, the integrity management program has an independent step to check the results of integrity assessments to validate the effectiveness of the program so that the operational risk remains as low as reasonably practicable throughout the integrity inspection and assessment cycle. As inspection technology, pipeline materials and construction practices improve with time, and new data on threats and pipeline condition are gathered, our methods of maintaining fitness for service evolves, with a strong focus on continuous improvement. Similar to the US regulatory landscape for integrity management, a significant release could likely lead the CER to impose pressure restrictions which may have an adverse effect on our operations, capital expenditures, earnings, cash flows, financial condition and competitive advantage.

Our pipelines also face economic regulatory risk. Broadly defined, economic regulatory risk is the risk that governments or regulatory agencies reject or revise proposed commercial arrangements, applications or policies, upon which future and current operations are dependent. Our pipelines are subject to the actions of various regulators, including the CER and the FERC, with respect to tariffs and tolls. The rejection or revision of applications for approval of new tariff structures or proposed commercial arrangements and changes in interpretation of existing regulations by courts or regulators could have an adverse effect on our revenues and earnings.

Crude Oil Marketing Business

The Crude Oil Marketing business is regulated by government authorities in the areas of commodity trading, import and export compliance and the transportation of commodities. Non-compliance with governing rules and regulations could result in fines, penalties and operating restrictions. These consequences would have an adverse effect on operations, earnings, cash flows, financial condition and competitive advantage. Mitigation of these potential risks is managed by a regulatory compliance program.

In the US, commodity marketing is regulated by the Commodity Futures Trading Commission, the FERC, the SEC, the Federal Trade Commission, the various commodity exchanges, the US Department of Justice and state regulators. In Canada, provincial and other territorial securities regulators similarly regulate commodity marketing within Canada. These various regulators enforce, among other things, the prohibition of market manipulation, fraud and disruptive trading.

The transportation of crude oil and natural gas liquids by railcar or truck is regulated by the US DOT, Transport Canada and provincial regulation. Each jurisdiction requires compliance with security, safety, emergency management, and environmental laws and regulations related to ground transportation of commodities. Risks associated with transportation of crude or natural gas liquids include unplanned releases, which may require remediation of the affected area. The Crude Oil Marketing business engages third parties, such as Emergency Response Assistance Canada, the Chemical Transportation Emergency Center and the Canadian Transport Emergency Center to assist in such remediation.

Gas Distribution and Storage - Canada

Enbridge Gas Ontario's operations are regulated by the OEB and Enbridge Gaz Quebec's operations are regulated by the Québec Régie de l’énergie. To the extent that the regulators’ future actions are different from current expectations, the timing and amount of recovery or refund of amounts recorded in the Consolidated Statements of Financial Position, or amounts that would have been recorded in the Consolidated Statements of Financial Position in the absence of the effects of regulation, could be different from the amounts that are eventually recovered or refunded.

In October 2022, Enbridge Gas Ontario filed its application with the OEB to establish a 2024 through 2028 Incentive Regulation (IR) rate setting framework. The application initially sought approval in two phases to establish 2024 base rates (Phase 1) on a cost-of-service basis and to establish a price cap rate setting mechanism (Phase 2) to be used for the remainder of the IR term (2025-2028). A third phase (Phase 3) has been established with the OEB as part of the Phase 1 Partial Settlement Proposal (Phase 1 Settlement). Phase 3 will address cost allocation and the harmonization of rates and rate classes between legacy rate zones, and is anticipated to be completed in 2025.

In August 2023, the OEB approved the Phase 1 Settlement and in December 2023, the OEB issued its Decision and Order on the remaining unsettled items in Phase 1 (Phase 1 Decision). These decisions include the following findings or orders:

•energy transition risk requires us to carry out a risk assessment to consider further risk mitigation measures in three areas: system access and expansion capital spending, system renewal capital spending and depreciation policy;

•all new small volume customers wishing to connect to natural gas are to pay their full connection costs as an upfront charge (the revenue horizon was set to zero years), rather than through rates over time effective January 2025;

•approval of a harmonized depreciation methodology that reduced the amount of depreciation sought and adjusted asset lives including extensions of service life for certain asset classes;

•the removal of $84 million of undepreciated integration capital costs from 2024 rate base; and

•an increase in equity thickness from 36% to 38% effective 2024.

Enbridge Gas Ontario filed a Notice of Appeal with the Ontario Divisional Court in January 2024 regarding various aspects of the Phase 1 Decision and subsequently filed an amended Notice of Appeal in December 2024 (Amended Appeal). The Amended Appeal focused on two aspects of the Phase 1 Decision: asset class average useful lives for depreciation purposes, and equity thickness. In January 2024, Enbridge Gas Ontario filed a Notice of Motion with the OEB requesting the OEB to review and vary the Phase 1 Decision which was subsequently amended in May 2024 (Amended Motion). The Amended Motion focused on two aspects of the Phase 1 Decision: asset class average useful lives for depreciation purposes, and the recoverability of integration capital. In October 2024, the OEB issued a decision on the Amended Motion and determined that only the issue of integration capital met the threshold to warrant a review. We are currently awaiting an OEB decision on the issue of integration capital.

In May 2024, Bill 165, the Keeping Energy Costs Down Act, received royal assent, giving the Government of Ontario time-limited authority to set the revenue horizon for small volume customers, effectively reversing that aspect of the OEB's Phase 1 Decision. Regulations are now in place setting the revenue horizon for new customer connections to 40 years.

In November 2024, the OEB issued its Decision approving the Phase 2 Partial Settlement Proposal (Phase 2 Settlement). The Phase 2 Settlement establishes a price cap IR rate setting mechanism to be used for establishing rates for 2025 – 2028. The price cap mechanism will establish new rates each year through an annual base rate adjustment to migrate an incremental $50 million in capitalized overheads to operating and maintenance costs, annual base rate escalation at inflation less a 0.28% productivity factor, annual updates for certain costs to be passed through to customers, and where applicable, it will provide for the recovery of material unexpected events and discrete incremental capital investments beyond those that can be funded through base rates. The price cap mechanism includes the continuation and establishment of certain deferral and variance accounts, as well as an earnings sharing mechanism that requires Enbridge Gas Ontario to share equally with customers any earnings in excess of 100 basis points over the allowed return on equity (ROE), and 90% of any earnings in excess of 300 basis points over the allowed ROE. Issues not addressed as part of the Phase 2 Settlement proceeded to hearing in December 2024 and a decision is expected in the second quarter of 2025.

Gas Distribution and Storage - US

Our US utilities operations are regulated by the Ohio Commission, the Utah Commission, the Wyoming Commission, the Idaho Commission, and the North Carolina Commission, as well as PHMSA and the US DOT.

Gas Regulation in Ohio

Enbridge Gas Ohio is subject to regulation of rates and other aspects of its business by the Ohio Commission. When necessary, Enbridge Gas Ohio seeks general base rate increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the cost-of-service by rate class. A straight-fixed-variable rate design, in which the majority of operating costs are recovered through a monthly charge rather than a volumetric charge, is utilized to establish rates for a majority of Enbridge Gas Ohio’s customers, pursuant to a 2008 rate case settlement.

The Ohio Commission has also approved several stand-alone cost recovery mechanisms to recover specified costs and a return for infrastructure, information technology and integrity or compliance-related projects between general base rate cases.

In October 2023, Enbridge Gas Ohio filed its base rate case and schedules with the Ohio Commission. Enbridge Gas Ohio proposed a non-fuel, base rate annual revenue increase of $212 million, projected to be effective January 2025. The base rate increase was proposed to recover the significant investment in distribution infrastructure for the benefit of Ohio customers. The proposed rates would have provided for an ROE of 10.40% compared to the currently authorized ROE of 10.38%. In addition, Enbridge Gas Ohio requested approval for an alternative rate plan for the continuation and modification of certain programs, including Pipeline Infrastructure Replacement (PIR) and Capital Expenditure Program (CEP). On December 18, 2024, Enbridge Gas Ohio filed a Notice of Intent to Modify Filed Positions. The Notice of Intent indicated a willingness to accept a reduced annual revenue requirement increase (from $212 million to $60 million) and, if the reduced position were adopted, to forgo filing a new base rate case until October 31, 2027. The hearing began on January 13, 2025, and remains underway.

In 2008, PIR was introduced, aimed at replacing approximately 25% of its pipeline system. The Ohio Commission has approved Enbridge Gas Ohio’s PIR program for capital investments through 2026 with 3% increases of annual capital expenditures per year.

In 2011, CEP was introduced, which enables Enbridge Gas Ohio to defer depreciation expense, property tax expense and carrying costs at the debt rate of 6.5% on capital investments not covered by its PIR program to expand, upgrade or replace its infrastructure and information technology systems, as well as investments necessary to comply with the Ohio Commission or other government regulation.

Gas Regulation in Utah, Wyoming, and Idaho

Enbridge Gas Utah, Enbridge Gas Wyoming, and Enbridge Gas Idaho are subject to regulation of rates and other aspects of its business by the Utah Commission, the Wyoming Commission, and the Idaho Commission, respectively. The Idaho Commission has contracted with the Utah Commission for rate oversight of Enbridge Gas Idaho’s operations in a small area of southeastern Idaho. When necessary, Enbridge Gas Utah, Enbridge Gas Wyoming and Enbridge Gas Idaho seek general base rate increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the cost-of-service by rate class. Base rates are designed primarily based on rate design methodology in which the majority of operating costs are recovered through volumetric charges. The volumetric charges for the residential and small commercial customers in Utah and Wyoming are subject to revenue decoupling and adjusted for changes in usage per customer.

Gas Regulation in North Carolina

Enbridge Gas North Carolina is subject to regulation of rates and other aspects of its business by the North Carolina Commission. When necessary, Enbridge Gas North Carolina seeks general base rate increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the cost-of-service by rate class. Base rates for Enbridge Gas North Carolina are designed primarily based on rate design methodology in which the majority of operating costs are recovered through volumetric charges. The volumetric charges for the residential and commercial customers are subject to revenue decoupling and adjusted for changes in usage per customer.

The North Carolina Commission has approved a standalone cost recovery mechanism to recover specified capital costs and a return for pipeline integrity management infrastructure projects between general base rate cases.

Renewable Power Generation

Renewable Power Generation is subject to numerous operational rules and regulations mandated by governments and applicable regulatory authorities. Breaches of these rules and regulations could result in fines, penalties, operating restrictions and an overall increase in operating and compliance costs.

The North American Electric Reliability Council (NERC) is an international regulatory authority responsible for establishing and enforcing reliability standards to reduce risks to the reliability and security of the grid in Canada, the US, and Mexico. It is subject to oversight from the FERC in the US and provincial governments in Canada. The FERC has authority over many markets in the US and is tasked with ensuring safe, reliable, and secure interstate transmission of electricity, natural gas, and oil. This includes establishing reliability standards, market rates, and determining certain pricing aspects of transmission development and access, among others. NERC and FERC standards and pricing decisions are also updated from time to time and could impact our operations, capital expenditures, earnings, and cash flows, though some of these impacts could be positive for our business.

At the US federal level, our Renewable Power Generation assets are subject to legislation overseen by the US Fish and Wildlife Service, which is aimed at reducing the impact of development and human activity on wildlife, along with other federal environmental permitting legislation. These federal environmental laws are subject to change from time to time, which could require Enbridge to obtain new permits, update practices, or amend operations and operating expenditures.

In Canada, the Federal Government does not generally regulate the electricity sector, though it has imposed a federal carbon price on other sectors via its output-based pricing system and has proposed a Clean Electricity Regulation (CE Regulation) that would require Canada’s electricity grid to reach net-zero by 2050 with initial limitations beginning in 2035. The CE Regulation came into effect in December 2024.

Policy changes may also impact our existing assets and the opportunity for new developments. For example, the US enactedthe Inflation Reduction Act in August 2022, establishing long-term transferable production and investment tax credits for renewable power generation, battery storage projects and for related manufacturing supply chains. Similarly, Canada has passed legislation enabling the Clean Technology Investment Tax Credit (ITC) and published a draft Clean Electricity ITC legislation anticipated to be enacted in mid-2025 focusing on non-taxable entities. Both of these credits would provide refundable ITCs for renewable power generation and battery storage projects. Changes to these programs, including as a result of a change in administration, could impact development plans.

Renewable Power Generation is also subject to provincial and state regulations governing the energy resource mix on the grid, emissions levels of the electricity grid, and market regulations related to emergency operations, extreme weather preparedness, and market participation, among others. These regulations may change from time to time, which could impact Enbridge’s operations and increase the costs of participating in regional electricity markets. In 2023, the Texas legislature proposed firming requirements that would require new wind and solar projects to be paired with batteries or other dispatchable power supply either on or offsite to enable more firm supply. These requirements were not enacted; however, they remain an important consideration going forward and heading into the 2025 legislative session. Other state and provincial governments are also prioritizing reliability and more dispatchable generation characteristics in their markets.

Our Renewable Power Generation assets in France and Germany each have federal policies in place and are subject to directives and regulations established and enforced by the European Union (EU). These include the Renewable Energy Directive, the European Green Deal, and ongoing work on financing mechanisms and transmission directives and programs. The EU is also responsible for establishing environmental protection rules and permitting standards. During 2022, member states of the EU introduced extraordinary and temporary measures to address high energy prices including caps and demand reduction goals. As the minimum PPA prices in Germany and France are still honored, there are no negative implications to our PPA prices. The federal policies and regulations in place are subject to change from time to time, which could impact our operations and related expenditures; however, the EU’s general direction is to facilitate increased renewable power integration to its grid.

The United Kingdom (UK) government is responsible for establishing renewable energy and carbon pricing policies for the entire UK, as well as long-term electricity sector planning and procurement mechanisms and structure for auctions that are administered at the national level, e.g., England, Scotland, within the UK. Each country within the UK is also responsible for establishing its own environmental and permitting regulations. This process is still ongoing following Brexit and, in some cases, continues to result in more volatile merchant power prices; however, expanded interconnectors to Europe and policies aimed at increasing domestic renewable capacity are in progress. Governments have introduced temporary price controls and other measures, beginning on January 1, 2023, to address the significant increase in energy prices. The impact of merchant exposure on our Renewable Power Generation assets in the UK is limited by fixed revenue payments backed by the UK government.

ENVIRONMENTAL REGULATION

Pipeline Regulation

Our Liquids Pipelines and Gas Transmission assets are subject to numerous federal, state and provincial environmental laws and regulations affecting many aspects of our present and future operations, including air emissions, water quality, water discharge and waste. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits and other approvals.

In particular, in the US, compliance with the Clean Air Act (CAA) regulatory programs may cause us to incur significant capital expenditures to obtain permits, evaluate off-site impacts of our operations, install pollution control equipment, and otherwise assure compliance. Some equipment in states in which we operate are affected by the Good Neighbor Rule establishing new emission limits for nitrogen oxides. The precise nature of these compliance obligations at each of our facilities has not been finally determined and may depend in part on future regulatory changes. In addition, compliance with new and emerging environmental regulatory programs may significantly increase our operating costs compared to historical levels.

In the US, climate change action is evolving at federal, state and regional levels. On March 8, 2024, the Environmental Protection Agency (EPA) released a final rule to minimize methane emissions for new and existing crude oil and natural gas facilities. Pursuant to federal regulations, we are currently subject to an obligation to report our GHG emissions through the Mandatory Greenhouse Gas Reporting Program at facilities that exceed the reporting threshold of 25,000 metric tons of carbon dioxide equivalent per year. This program was revised to include additional sources and new measurement and calculations methodologies for the oil and gas sector on May 14, 2024, and effective for reporting year 2025. These changes were designed to comply with the Inflation Reduction Act’s requirement to revise the program to utilize more empirical data. This data is used to calculate a fee under the Methane Emissions Reduction Program through the Methane Waste Emission Charge that was finalized and published on November 18, 2024. In addition, several states have joined regional GHG initiatives, and a number are developing their own programs that would mandate reductions in GHG emissions. Public interest groups and regulatory agencies are increasingly focusing on the emission of methane associated with natural gas development and transmission as a source of GHG emissions. Based on proposed changes to measure, report and mitigate GHG emissions the expectation is that there will be a significant increase in costs to maintain and report compliance for businesses in our industry.

Canada has adopted a pan-Canadian approach to pricing carbon emissions to incent GHG emission reductions across all sectors of the economy. This approach was adopted in 2016 and entails both a consumer price on carbon, and an intensity-based system for industry which addresses competitiveness and carbon leakage. Provinces and territories may implement their own system of carbon pricing provided it meets the federal benchmark (and if they fail to do so the federal system will be imposed on them). In March 2022, Canada published its 2030 Emissions Reduction Plan (ERP) which builds on the Pan-Canadian Framework, and Net-Zero Emissions Accountability Act, and details the roadmap for Canada to meet its domestic climate target of a 40-45% reduction in GHG emissions by 2030 and attaining net-zero emissions by 2050. The ERP details the complementary policies and programs that Canada will enact to enable it to meet its domestic climate goal. Effective April 1, 2024, the federal carbon price was increased to $65 per tonne of carbon dioxide equivalent (tCO2e). This will increase by $15 per tonne each year and rise to $170 per tCO2e in 2030.

Two pending regulations in Canada that are expected to impact our operations include the amended federal methane regulations and the proposed volatile organic compounds (VOC) regulations. The amended methane regulations are part of Canada's broader effort to achieve at least a 75% reduction in methane emissions from the oil and gas sector by 2030, relative to 2012 levels. These regulations would impact Enbridge’s Gas Transmission assets to build upon the current regulations to further reduce methane emissions by limiting venting and increasing leak detection. The proposed VOC regulations, if adopted, would impact Enbridge’s Liquids Pipelines assets, specifically petroleum liquid storage tanks and loading operations, by requiring emission control equipment on in-scope storage tanks and loading racks. Both regulations are expected to be finalized in the first quarter of 2025; we continue to monitor these developments, including any potential impacts to our business.

Gas Distribution and Storage

Our Gas Distribution and Storage operations, facilities and workers are subject to municipal, provincial, state and federal legislation which regulates the protection of the environment and the health and safety of workers. Environmental legislation primarily includes regulation of spills and emissions to air, land and water; hazardous waste management; the assessment and management of excess soil and contaminated sites; protection of environmentally sensitive areas, and species at risk and their habitats; and the reporting and reduction of GHG emissions.

Gas distribution system operation, as with any industrial operation, has the potential risk of abnormal or emergency conditions, or other unplanned events that could result in releases or emissions exceeding permitted levels. These events could result in injuries to workers or the public, adverse impacts to the environment, property damage and/or regulatory infractions including orders and fines. We could also incur future liability for soil and groundwater contamination associated with past and present site activities.

In addition to gas distribution, we also operate gas storage facilities in Ontario and Ohio, and our Wexpro business develops and produces natural gas reserves. Environmental risk associated with these facilities has the potential for unplanned releases, which could require remediation of the affected area. There would also be potential for fines and orders under environmental legislation, and potential third-party liability claims by any affected landowners.

The gas distribution system and our other operations must maintain environmental approvals and permits from regulators to operate. As a result, these assets and facilities are subject to periodic inspections and/or audits. Reports are submitted to our regulators as required to demonstrate compliance with environmental requirements. Failure to maintain regulatory compliance could result in operational interruptions, fines, and/or orders for additional pollution control technology or environmental mitigation.

As environmental regulations continue to evolve and become more stringent, the cost to maintain compliance and the time required to obtain approvals continues to increase. A recent example includes the implementation of the new excess soil management requirements (Ontario Regulation 406/19) which has resulted in an increase in soil management costs and effort.

As in previous years, in 2024 we reported operational GHG emissions, including emissions from stationary combustion, flaring, venting and fugitive sources to Environment and Climate Change Canada, the Ontario Ministry of Environment, Conservation and Parks, and a number of voluntary reporting programs. In accordance with the provincial GHG regulations, stationary combustion and flaring emissions related to storage and transmission operations were verified in detail by a third-party accredited verifier with no material discrepancies found.

Under the federal government's Greenhouse Gas Pollution Pricing Act, a carbon charge took effect on April 1, 2019 at a rate of 3.91 cents/cubic meter (m3) of natural gas and is applicable to the majority of customers. Enbridge Gas Ontario is registered as a natural gas distributor with the Canada Revenue Agency and remits the federal carbon charge on a monthly basis. The charge increases annually on April 1 of each year, and rose to 15.25 cents/m3 in 2024. The federal carbon price increases by $15 per tCO2e each year, and is scheduled to rise to $170 per tCO2e in 2030, which would equate to a federal carbon charge of 32.40 cents/m3 in 2030.

Effective January 1, 2022, Enbridge Gas Ontario transitioned from the federal output-based pricing system to the Ontario Emissions Performance Standards (EPS). Enbridge Gas Ontario is registered with the Ontario Ministry of the Environment, Conservation and Parks (MECP) as a covered facility under the EPS and has an annual compliance obligation for its facility-related stationary combustion and flaring emissions associated with its transmission and storage operations. Enbridge Gas Ontario must remit payment annually on the portion of emissions that exceed its total annual emissions limit.

In June 2024, the MECP launched the Emissions Performance Program (EPP), a program funded by compliance payments collected from EPS. The EPP allows EPS facilities to apply for funding to support projects that reduce eligible GHG emissions at the eligible EPS facility. Enbridge Gas Ontario has identified projects that are potentially eligible for EPP funding and is working with the MECP to submit EPP applications.

Enbridge Gas Ontario applies to the OEB annually through a Federal Carbon Pricing Program application for approval of just and reasonable rates effective April 1 each year to recover the costs associated with the Federal Carbon Charge and EPS Regulation as a pass-through to customers.

Our US gas distribution operations are subject to various federal and state laws and regulations governing the management, storage, treatment, reuse, and disposal of waste materials and hazardous substances. These include the Resource Conservation and Recovery Act of 1976, Comprehensive Environmental Response, Compensation, and Liability Act, the Emergency Planning and Community Right-to-Know Act of 1986, and the Toxic Substances Control Act of 1976. Wexpro's operations and construction activities, related to oil and gas production and gas storage wells, generate waste. Completion water is disposed of at commercial disposal facilities, while produced water is either hauled for disposal, evaporated, or injected into company and third party-owned underground injection wells. Wells drilled in tight-gas-sand and shale reservoirs require hydraulic-fracture stimulation to achieve economic production rates and recoverable reserves. The majority of Wexpro's current and future production and reserve potential comes from reservoirs that need hydraulic-fracture stimulation to be commercially viable. Currently, all well construction activities, including hydraulic-fracture stimulation and the management and disposal of hydraulic fracturing fluids, are regulated by federal and state agencies that review and approve all aspects of gas and oil well design and operation.

In 2025, we will report 2024 operational GHG emissions, including emissions from combustion, venting, and fugitive sources, for the first time for our newly acquired US Gas Utilities to the Environmental Protection Agency under the Greenhouse Gas Reporting Program.

Renewable Power Generation

Our Renewable Power Generation assets are subject to a combination of federal, state, provincial and local government agencies. These regulations and laws associated with these agencies affect the development and operations of our renewable power assets and generally require us to assess the environmental landscape and obtain and comply with a variety of environmental licenses, permits and other approvals.

In Canada, our Renewable Power Generation assets are subject to the federal Species at Risk Actand provincial regulations that are aimed at mitigating the effects of development and human activity on wildlife. At the US federal level, our assets are subject to legislation overseen by the US Fish and Wildlife Service, which is similarly aimed at reducing the impact of development and human activity on wildlife, along with other federal environmental permitting legislation. These environmental laws (federal, state and provincial) are subject to change from time to time which could require Enbridge to obtain new permits, update practices, or amend operations and operating expenditures.

The regulatory landscape continues to evolve to address new developments within this relatively new industry. In the summer of 2023, the Federal Government of Canada introduced its draft CE Regulation that are intended to achieve a net-zero electricity grid by 2050 with initial limitations beginning in 2035. The Federal Government of Canada released finalized regulations on December 17, 2024 setting limits on GHG emissions from almost all electricity generation units that use fossil fuels. The finalized regulations also include a compliance credit system, and opportunities for credit trading and pooling within federal and provincial frameworks, intended to provide flexibility for operators to meet the new standards.

Similarly, in April 2024, the US EPA finalized regulations for coal-fired and new natural gas-fired power plants designed to reduce emissions 75 percent below 2005 levels by 2035. These regulations require covered facilities to reduce carbon dioxide emissions equivalent to a 90 percent carbon capture and sequestration rate by 2032. Facilities with less than 40 percent capacity rates would be required to adhere to less stringent requirements, including enhanced energy efficiency. These government policies are rapidly evolving, including as a result of changes in governments. We continue to monitor these developments, together with their impact on our business.

Enbridge’s Renewable Power Generation resources are substantially non-emitting.

HUMAN CAPITAL RESOURCES

WORKFORCE SIZE AND COMPOSITION

As at December 31, 2024, we had approximately 14,500 regular employees, including approximately 2,600 unionized employees across our North American operations. This total includes approximately 3,500 employees who joined in 2024 following the close of the Acquisitions of the US Gas Utilities. Overall headcount rises to just over 16,000 if temporary employees and contractors are included. We have a strong preference for direct employment relationships but where we have collectively bargained-for employees, we have mature working relationships with our labor unions and the parties have traditionally committed themselves to the achievement of renewal agreements without a work stoppage.

SAFETY

We believe all injuries, incidents and occupational illnesses are preventable. Our overall focus on employee and contractor safety, continues to result in strong performance compared against industry benchmarks and we are actively engaged in continuous improvement exercises as we pursue our goal of zero incidents.

PRODUCTIVITY AND DEVELOPMENT

We continually invest in our people’s personal and professional development and productivity because we recognize their success is our success. Employees are provided access to leading productivity tools and technology, and can opt in to a range of development and growth opportunities through a variety of channels, which encourages employees to build new skills needed for our core and emerging lines of business and the broader energy transition.

EXECUTIVE OFFICERS

The following table sets forth information regarding our executive officers as at February 14, 2025:

Gregory L. Ebel was appointed President and Chief Executive Officer (CEO) on January 1, 2023. Mr. Ebel is also a member of the Enbridge Board of Directors. Mr. Ebel served as Chair of the Enbridge Board of Directors following the merger of Enbridge and Spectra Energy Corp (Spectra Energy) in 2017 until January 1, 2023. Prior to that time, he served as Chairman, President and CEO of Spectra Energy from 2009 until February 27, 2017. Previously, Mr. Ebel also served as Spectra Energy’s Group Executive and Chief Financial Officer beginning in 2007, President of Union Gas Limited from 2005 until 2007, and Vice President, Investor & Shareholder Relations of Duke Energy Corporation from 2002 until 2005.

Patrick R. Murray was appointed Executive Vice President & Chief Financial Officer (CFO) on July 1, 2023. Mr. Murray has oversight of Enbridge’s financial affairs including investor relations, financial reporting, financial planning, treasury, tax, insurance, risk and audit management functions. He also leads Enbridge’s technology and information services teams. Prior to assuming his current role, Mr. Murray was Senior Vice President & Chief Accounting Officer of Enbridge from June 2020 to June 2023, Vice President, Financial Planning & Analysis and Controller from June 2019 to May 2020, and Vice President, Financial Planning & Analysis from February 2017 to June 2019. Mr. Murray joined Enbridge over 27 years ago and has held a variety of roles within internal audit, corporate accounting, investor relations, treasury, and corporate development during that time.

Colin K. Gruending was appointed Executive Vice President and President, Liquids Pipelines on October 1, 2021. Mr. Gruending is responsible for the overall leadership and operations of Enbridge’s Liquids Pipelines business. Previously, he served as our Executive Vice President and Chief Financial Officer from June 2019 to October 2021; Senior Vice President, Corporate Development and Investment Review from May 2018 to June 2019; and Vice President, Corporate Development and Investment Review from February 2017 to May 2018.

Cynthia L. Hansen was appointed Executive Vice President and President, Gas Transmission on March 1, 2022. Ms. Hansen is responsible for the overall leadership and operations of Enbridge’s natural gas pipeline and midstream business across North America. Previously, she served as our Executive Vice President, Gas Distribution and Storage from June 2019 to March 2022 and as Executive Vice President, Utilities and Power Operations from February 2017 to June 2019. Ms. Hansen is also the Executive Sponsor for Asset and Work Management Transformation across Enbridge, working with other business unit leaders.

Michele E. Harradence was appointed Executive Vice President & President, Gas Distribution and Storage on March 5, 2023. She is responsible for the overall leadership and operations of Enbridge’s Gas Distribution and Storage business across North America. Prior to assuming her current role, Ms. Harradence was Senior Vice President & President, Gas Distribution and Storage from March 2022 to March 2023. Prior thereto, she was Senior Vice President and Chief Operations Officer of Enbridge’s Gas Transmission and Midstream business unit from June 2019 to March 2022 and Senior Vice President Operations, Gas Transmission and Midstream from February 2017 to June 2019.

Matthew A. Akman was appointed Executive Vice President, Corporate Strategy & President, Power on March 5, 2023. Mr. Akman is responsible for the overall leadership and operations of Enbridge’s power business and also leads our new energy technologies and corporate strategy efforts. Prior to assuming his current role, Mr. Akman was Senior Vice President, Corporate Strategy & President, Power from January 2023 to March 2023. Prior thereto, he was Senior Vice President, Strategy, Power & New Energy Technologies from October 2021 to December 2022, and Senior Vice President, Strategy & Power from June 2019 to October 2021. Mr. Akman joined Enbridge in early 2016 as our head of Corporate Strategy and also previously held responsibilities for Corporate Development and Investor Relations.

Reginald D. Hedgebeth was appointed Executive Vice President, External Affairs and Chief Legal Officer on January 1, 2024. Mr. Hedgebeth leads our legal, public affairs, communications & sustainability, corporate security and aviation teams across the organization. Prior to joining Enbridge, Mr. Hedgebeth served as Chief Legal Officer of Capital Group from January 2021 to June 2023, Executive Vice President, General Counsel and Chief Administrative Officer of Marathon Oil Corporation from April 2017 to December 2020 and, prior to its merger with Enbridge in 2017, General Counsel, Corporate Secretary and Chief Ethics and Compliance Officer for Spectra Energy.

Maximilian G. Chan was appointed Senior Vice President & Corporate Development Officer on March 1, 2022. He was later appointed to the Executive Leadership team on May 8, 2023. Mr. Chan is responsible for the oversight of mergers and acquisitions, capital allocation, investment review, integration and corporate growth objectives. Prior to assuming his current role, Mr. Chan was Vice President, Treasury and Head of Enterprise Risk for Enbridge from February 2020 to March 2022, and Vice President, Treasury from July 2018 to February 2020.

Laura J. Sayavedra was appointed Senior Vice President, Safety, Projects & Chief Administrative Officer on January 1, 2024. Ms. Sayavedra is responsible for the oversight of our safety, capital project execution, human resources, real estate and supply chain management functions. Prior to assuming her current role, Ms. Sayavedra was Senior Vice President, Safety & Reliability, Projects and Unify from March 2022 to December 2023. Prior to that, she led Finance Transformation at Enbridge, and prior to its merger with Enbridge in 2017, was also Vice President & Treasurer for Spectra Energy, and CFO of Spectra Energy Partners LP. She has held various finance, strategy, and business development executive leadership roles.

ADDITIONAL INFORMATION

Additional information about us is available on our website at www.enbridge.com, on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov. The aforementioned information is made available in accordance with legal requirements and is not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K. We make available free of charge, through our website, annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as well as proxy statements, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Reports, proxy statements and other information filed with the SEC may also be obtained through the SEC’s website (www.sec.gov).

ENBRIDGE GAS INC.

Additional information about Enbridge Gas Inc. (operating as Enbridge Gas Ontario) can be found in its annual information form, financial statements and MD&A for the year ended December 31, 2024, which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to Enbridge Gas Ontario and are publicly available on SEDAR+ at www.sedarplus.ca. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.

ENBRIDGE PIPELINES INC.

Additional information about Enbridge Pipelines Inc. (EPI) can be found in its annual information form, financial statements and MD&A for the year ended December 31, 2024, which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to EPI and are publicly available on SEDAR+ at www.sedarplus.ca. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.

WESTCOAST ENERGY INC.

Additional information about Westcoast Energy Inc. (Westcoast) can be found in its financial statements and MD&A for the year ended December 31, 2024, which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to Westcoast and are publicly available on SEDAR+ at www.sedarplus.com. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.