Enbridge Inc: Form 10-K for the period ended Dec 31, 2024

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 goals1. 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 groups1;
• 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 at https://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.

1All 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

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

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.

SUPPLY AND DEMAND

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

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.

COMPETITION

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.

SUPPLY AND DEMAND

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 Act and 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.

COMPETITION

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.

SUPPLY AND DEMAND

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

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.

COMPETITION

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.

SUPPLY AND DEMAND

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

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 enacted the 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.

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 Act and 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 (http://www.enbridge.com), on SEDAR+ at www.sedarplus.ca (http://www.sedarplus.ca) and on EDGAR at www.sec.gov (http://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 (http://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 (http://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 (http://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 (http://www.sedarplus.com). These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.

The following risk factors could materially and adversely affect our business, operations, financial results, market price or value of our securities. This list is not exhaustive, and we place no priority or likelihood based on order of presentation or grouping under sub-captions.

RISKS RELATED TO CLIMATE CHANGE

Climate change risks could adversely affect our reputation, strategic plan, business, operations and financial results, and these effects could be material.

Climate change is a systemic risk that presents both physical and transition risks to our organization. A summary of these risks is outlined below. Given the interconnected nature of climate change-related impacts, we also discuss these risks within the context of other risks impacting Enbridge throughout Item 1A. Risk Factors. Climate change and its associated impacts may also increase our exposure to, and magnitude of, other risks identified in Item 1A. Risk Factors. Our business, financial condition, results of operations, cash flows, reputation, access to and cost of capital or insurance, business plans and strategy may all be materially adversely impacted as a result of climate change and its associated impacts.

PHYSICAL RISKS

Climate-related physical risks, resulting from changing and more extreme weather, can damage our assets and affect the safety and reliability of our operations. Climate-related physical risks may be acute or chronic. Acute physical risks are those that are event-driven, including increased frequency and severity of extreme weather events, such as heavy snowfall, heavy rainfall, floods, landslides, fires, hurricanes, cyclones, tornados, tropical storms, ice storms, and extreme temperatures. Chronic physical risks are longer-term shifts in climate patterns, such as long-term changes in precipitation patterns, or sustained higher temperatures, which may cause sea level rises or chronic heat waves.

Our assets and operations are exposed to potential damage or other negative impacts from these kinds of events, which have in the past resulted and could in the future result in reduced revenue from business disruption or reduced capacity and may also lead to increased costs due to repairs and required adaptation measures. We have experienced operational interruptions and damage to our assets from such weather events in the past, and we expect to continue to experience climate-related physical risks in the future, potentially with increasing frequency or severity. Such events may also result in personal injury, loss of life.

TRANSITION RISKS

The transition to a lower-carbon economy involves policy, legal, technology and market changes which may, in turn, increase our cost of operations and influence stakeholder sentiment and decisions about Enbridge, including potentially reducing the demand for some of our services, which could result in a decrease in profitability or reduction in the value of our assets. Transition risks include the following categories:

• Policy and legal risks

Policy and legal risks may result from evolving government policy, legislation, regulations and regulatory decisions focused on climate change, as well as changing political and public opinion, stakeholder opposition, legal challenges, litigation and regulatory proceedings. Foreign and domestic governments and regulators continue to evaluate and implement policy, legislation, regulations and decisions aimed at mitigating the impacts of and adapting to climate change, including measures to reduce GHG emissions and shift to lower-carbon sources of energy. Such policies, laws and regulations vary at the federal, state, provincial and municipal levels in which Enbridge operates and are continually evolving. Rules, standards, and methodologies for setting climate-related goals and for measuring and reporting climate-related information are still developing. At the same time, we have seen the rise of anti-ESG activism, creating competing stakeholder priorities and increasing uncertainty. As a result, our climate-related goals and disclosures are based on assumptions that are subject to change. Collectively, these measures have resulted and are expected to continue to result in increased costs to us. Enbridge adheres to a number of carbon-pricing mechanisms, including explicit carbon prices (i.e., in BC) and implicit carbon prices (i.e., Canadian federal output-based pricing system). In Canada, the federal government has proposed new Clean Electricity Regulations and is considering options to cap and cut GHG emissions from the oil and gas sector, which may impact our business. Such evolving policy, legislation and regulation could impact commodity demand, and the overall energy mix we deliver and may result in significant expenditures and resources, as well as increased costs for our customers. In recent years, there has also been changing political and public opinion and stakeholder opposition in relation to parts of our business and industry, as well as an increase in climate-related litigation and regulatory action against companies, all of which could impact our reputation, strategy and financial results.

• Technology risks

Executing our strategic priorities, including participating in the energy transition over time and attaining our GHG emissions reduction goals, depends, in part, on technological improvements and innovation. This includes the development and use of emerging technologies, such as renewable power and other lower-carbon energy infrastructure. Such technological developments could require significant capital expenditures and resources and may, impact our competitiveness. GHG emissions reduction technology may not materialize as expected, which could make it more difficult to reduce emissions and meet our ESG goals.

• Market risks

Concerns about climate change, increased demand for lower-carbon forms of energy and new energy technologies, changing customer behavior, and reduced energy consumption could impact the demand for our services or our securities. In recent years, certain investors, lenders and insurers have taken or are contemplating actions to decrease the carbon intensity of their portfolios or reduce or cease support for the fossil fuel industry. Such measures could result in increased costs to manage these risks and could negatively impact our access to and cost of capital, as well as demand for, or value of, our securities or our services. Uncertainty in market signals, such as abrupt and unexpected shifts in energy costs and demands, including due to climate change concerns, could impact revenue through reduced throughput volumes on our pipeline transportation systems.

• Reputational risks

Companies across all sectors and industries are facing changing expectations and increased scrutiny from stakeholders related to their approach to climate change and GHG emissions. Companies in the energy industry are experiencing stakeholder opposition to their operations and infrastructure projects. Enbridge’s ESG goals, sustainability-related activities, commitments, and plans, including climate-related information and data, are based on various assumptions, estimates, judgments, risks, and uncertainties. Achieving these ESG goals and commitments will require collective efforts and actions from a wide range of stakeholders, much of which is beyond our control, and there can be no assurance that the impact of these efforts and actions will be realized. Our ESG goals and pathways for reducing operational emissions will continue to evolve and may need to be restated, modified, or recalibrated as data improves, standards, methodologies, metrics, and measurements mature, and as legislation, regulations, policies, and stakeholder sentiment evolve. If we experience challenges, or perceived challenges in achieving our climate-related goals, are not able to meet future climate-related, emissions, or other regulatory or reporting requirements, or are not able to meet or manage stakeholder expectations regarding climate change or disclosure of climate-change information (including potential allegations of greenwashing), it could negatively impact our reputation or investor sentiment and could expose us to government enforcement actions or litigation, which may, in turn, impact our business, operations or financial results.

RISKS RELATED TO OPERATIONAL DISRUPTION OR CATASTROPHIC EVENTS

Operation of complex energy infrastructure involves many hazards and risks that may adversely affect our business, financial results, the environment, relationships with stakeholders, and our reputation.

These operational risks include adverse weather conditions, natural disasters, accidents, the breakdown or failure of equipment, processes or human error, and lower than expected levels of operating capacity and efficiency. These operational risks could be catastrophic in nature.

Operational risk is also intensified by exposure to severe weather conditions and natural disasters, including those related to climate change, which may affect the safety and reliability of our operations, including, but not limited to heavy snowfall, heavy rainfall, floods, landslides, fires, hurricanes, cyclones, tornados, tropical storms, ice storms, and extreme temperatures, and chronic physical risks, such as long-term changes in precipitation patterns, or sustained higher temperatures.

Our assets and operations are exposed to potential damage or other negative impacts from these operational risks, which could result in reduced revenue from business disruption or reduced capacity and may also lead to increased costs due to repairs and required adaptation measures. Such events have led to, and could in the future lead to, rupture or release of product from our pipeline systems and facilities, resulting in damage to property and the environment, personal injury or loss of life. Such an incident has in the past, and could in the future, result in substantial losses for which insurance may not be sufficient or available and for which we may bear part or all of the cost, thereby negatively impacting earnings. Such incidents could also have lasting reputational impacts and could impair our relationships with various stakeholders. For pipeline and storage assets located near populated areas, including residential communities, commercial business centers, industrial sites and other public gathering locations, the level of damage resulting from these events could be greater.

We have experienced such events in the past and expect to continue to incur significant costs in preparing for or responding to operational risks and events. We expect to continue to experience climate-related physical risks, potentially with increasing frequency and severity, and we cannot guarantee that we will not experience catastrophic or other events in the future. In addition, we have in the past, and could in the future, be subject to litigation and significant fines and penalties from regulators in connection with any such events.

A service interruption could have a significant impact on our operations, and negatively impact financial results, relationships with stakeholders and our reputation.

A service interruption due to a major power disruption, curtailment of commodity supply, operational incident, security incident (cyber or physical), availability of gas supply or distribution, or other reasons, could have a significant impact on our operations and negatively impact financial results, relationships with stakeholders, our reputation or the safety of our end-use customers. Service interruptions that impact our crude oil and natural gas transportation services can negatively impact shippers’ operations and earnings as they are dependent on our services to move their product to market or fulfill their own contractual arrangements, and this has in the past led to and may again lead to claims against us. We have experienced, and may again experience, service interruptions, restrictions or other operational constraints, including in connection with the kinds of operational incidents referred to in the previous risk factor.

Our operations involve safety risks to the public and to our workers and contractors.

Enbridge assets may change over time and operate over a broad geographic area. These assets include liquids pipelines, gas transmission, and gas distribution systems which are operated near populated areas. A major incident involving these assets has resulted in and may again result in injury or loss of life to members of the public. In addition, given the natural hazards inherent in our operations, our workers and contractors are subject to personal safety risks. A public safety incident or an injury or loss of life to our workers or contractors, which we have experienced in the past and, despite the precautions we take, may experience in the future, could result in reputational damage to us, legal claims, material repair costs or increased operating and insurance costs.

Cyber attacks and other cybersecurity incidents pose threats to our technology systems and could materially adversely affect our business, operations, reputation or financial results.

Our business is dependent upon information systems and other digital technologies for controlling our plants, pipelines and other assets, processing transactions and summarizing and reporting results of operations. With the evolution of AI, our business has incorporated AI into our operations in order to gain efficiencies and productivity in our day-to-day operations, which has the potential to increase technology and cybersecurity risks. The secure processing, maintenance and transmission of information is critical to our operations.

Cybersecurity risks have increased in recent years as a result of the proliferation of new technologies and the increased sophistication of cyber attacks and financially-motivated cybercrime, as well as international and domestic political factors, including geopolitical tensions, armed hostilities, war, civil unrest, sabotage, terrorism and state-sponsored or other cyber espionage. Human error or malfeasance can also contribute to a cyber incident, and cyber attacks can be internal as well as external and occur at any point in our supply chain. Because of the critical nature of our infrastructure and our use of information systems and other digital technologies to control our assets, we face a heightened risk of cybersecurity incidents, such as ransomware, theft, misplaced or lost data, programming errors, phishing attacks, denial of service attacks, acts of vandalism, computer viruses, malware, hacking, malicious attacks, software vulnerabilities, employee errors and/or malfeasance, or other attacks, security or data breaches or other cybersecurity incidents. Cyber threat actors have attacked and continue to threaten to attack energy infrastructure, including our assets, and various government agencies have increasingly stressed that these attacks are targeting critical infrastructure, including pipelines, public utilities, and power generation facilities, and are increasing in sophistication, magnitude, and frequency. Additionally, these risks may escalate during periods of heightened geopolitical tensions. In addition, new cybersecurity legislation, regulations and orders have been recently implemented or proposed, resulting in additional actual and anticipated regulatory oversight and compliance requirements, which will require significant internal and external resources. We cannot predict the potential impact to our business of potential future legislation, regulations or orders relating to cybersecurity.

We have experienced an increase in the number of attempts by external parties to access our systems or our company data without authorization, and we expect this trend to continue. Although we devote significant resources and security measures to prevent unwanted intrusions and to protect our systems and data, whether such data is housed internally or by external third parties, we and our third-party vendors have experienced, and expect to continue to experience, cyber attacks of varying degrees in the conduct of our business, including denial of service attacks. To date, these prior cyber attacks have not, to our knowledge, had a material adverse effect on our business, operations or financial results. However, we have experienced an increasing number of cybersecurity threats in recent years and there is a risk that any such incidents could have a material adverse effect on us in the future.

Our technology systems or those of our vendors or other service providers are expected to become the target of further cyber attacks or security breaches which could compromise our data and systems or our access thereto by us, our customers or others, affect our ability to correctly record, process and report transactions, result in the loss of information, or cause operational disruption or incidents. There can be no assurance that our business continuity plans will be completely effective in avoiding disruption and business impacts. Furthermore, we and some of our third-party service providers (who may in turn also use third-party service providers) collect, process or store sensitive data in the ordinary course of our business, including personal information of our employees, residential gas distribution customers, land owners and investors, as well as intellectual property or other proprietary business information of ours or our customers or suppliers. In light of the Acquisitions, due to their large residential customer bases, we and some of our third-party services providers will process increasing amounts of personal information.

As a result of the foregoing, we could experience loss of revenues, repair, remediation or restoration costs, regulatory action, fines and penalties, litigation, breach of contract or indemnity claims, cyber extortion, ransomware, implementation costs for additional security measures, loss of customers, customer dissatisfaction, reputational harm, liability under laws that protect the privacy of personal information, other adverse consequences, or other costs or financial loss. In light of the Acquisitions, these risks may be heightened, and the consequences magnified. Regardless of the method or form of cyber attack or incident, any or all of the above could materially adversely affect our reputation, business, operations or financial results.

In addition, a cyber attack could occur and persist for an extended period without detection. Any investigation of a cyber attack or other security incident may be inherently unpredictable, and it would take time before the completion of any investigation and availability of full and reliable information. During such time, we may not know the extent of the harm or how best to remediate it, and certain errors or actions could be repeated or compounded before they are discovered and remediated, all or any of which could further increase the costs and consequences of a cyber attack or other security incident, and our remediation efforts may not be successful. The inability to implement, maintain and upgrade adequate safeguards could materially and adversely affect our results of operations, cash flows, and financial condition. Moreover, recent rulemakings may require us to disclose information about a cybersecurity incident before it has been completely investigated or remediated in full or even in part. As cyber attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.

Furthermore, media reports about a cyber attack or other significant security incident affecting Enbridge, whether accurate or not, or, under certain circumstances, our failure to make adequate or timely disclosures to the public, law enforcement, other regulatory agencies or affected individuals following any such event, whether due to delayed discovery or otherwise, could negatively impact our operating results and result in other adverse consequences, including damage to our reputation or competitiveness, harm to our relationships with customers, partners, suppliers, investors, and other third parties, interruption to our management, remediation or increased protection costs, significant litigation or regulatory action, fines or penalties, all of which could materially adversely affect our business, operations, reputation or financial results.

Terrorist attacks and threats, escalation of military activity in response to these attacks or acts of war, other civil unrest or activism, or geopolitical uncertainty could adversely affect our business, operations or financial results.

Terrorist attacks and threats (which may take the form of cyber attacks, as outlined above), escalation of military activity, armed hostilities, war, sabotage, or civil unrest or activism may have significant effects on general economic conditions and may cause fluctuations in consumer confidence and spending and market liquidity, each of which could adversely affect our business. Future terrorist attacks, rumors or threats of war, actual conflicts involving the US or Canada, or military or trade disruptions may significantly affect our operations and those of our customers. Strategic critical infrastructure targets, such as energy-related assets, are at greater risk of cyber attack and may be at greater risk of other future attacks than other targets in the US and Canada. Enbridge’s infrastructure and projects under construction could be direct targets or indirect casualties of a cyber or physical attack. In addition, increased environmental activism against construction and operation of energy infrastructure could potentially result in work delays, reduced demand for our products and services, new legislation or public policy or increased stringency thereof, or denial or delay of permits and rights-of-way. Enbridge also faces risks related to international relations and geopolitical events. Factors such as political, economic, or social instability, trade disputes, increased tariffs, changes in laws, strict regulations, and shifts in political leadership can lead to higher commodity prices and affect energy availability and costs.

Pandemics, epidemics or infectious disease outbreaks may adversely affect local and global economies and our business, operations or financial results.

Disruptions caused by pandemics, epidemics or infectious disease outbreaks could materially adversely affect our business, operations, financial results and forward-looking expectations. Governments' emergency measures to combat the spread could include restrictions on business activity and travel, as well as requirements to isolate or quarantine. The duration and magnitude of such impacts will depend on many factors that we may not be able to accurately predict. COVID-19 and government responses interrupted business activities and supply chains, disrupted travel, and contributed to significant volatility in the financial and commodity markets.

Disruptions related to pandemics, epidemics or infectious disease outbreaks could have the effect of heightening many of the other risks described in this Item 1A. Risk Factors.

RISKS RELATED TO OUR BUSINESS AND INDUSTRY

There are utilization risks with respect to our assets.

With respect to our Liquids Pipelines assets, we are partially exposed to throughput risk on the Canadian Mainline, and we are exposed to throughput risk under certain tolling agreements applicable to other Liquids Pipelines assets, such as the Lakehead System. A decrease in volumes transported can directly and adversely affect our revenues and earnings. Factors such as changing market fundamentals, capacity bottlenecks, regulatory restrictions, maintenance and operational incidents on our system and upstream or downstream facilities, and increased competition can all impact the utilization of our assets. Market fundamentals, such as commodity prices and price differentials, weather, gasoline prices and consumption, tariffs, alternative and new energy sources and technologies, and global supply disruptions outside of our control can impact both the supply of and demand for crude oil and other liquid hydrocarbons transported on our pipelines.

With respect to our Gas Transmission assets, gas supply and demand dynamics continue to change due to shifts in regional and global production and consumption. These shifts can lead to fluctuations in commodity prices and price differentials, which could result in our system not being fully utilized in some areas. Other factors affecting system utilization include operational incidents, regulatory restrictions, system maintenance, and increased competition.

With respect to our Gas Distribution and Storage assets, customers of our gas distribution franchises are billed on both a fixed charge and volumetric basis and our ability to collect the total revenue requirement (the cost of providing service, including a reasonable return to the utility) in certain jurisdictions depends on achieving the forecast distribution volume established in the rate-making process. The probability of realizing such volume is contingent upon four key forecast variables: weather, economic conditions, pricing of competitive energy sources and growth in the number of customers. Weather is a significant driver of delivery volumes, given that a significant portion of our gas distribution customer base uses natural gas for space heating. Our ability to add new customers could be impacted by market conditions affecting housing activity such as interest rates, affordability levels, and energy transition. Sales and transportation service to large volume commercial and industrial customers are more susceptible to prevailing economic conditions. As well, the pricing of competitive energy sources affects volume distributed to these sectors, as some customers have the ability to switch to an alternate fuel. Even in those circumstances where we attain our respective total forecast distribution volume, our gas distribution business may not earn its expected ROE due to other forecast variables, such as fluctuations in the mix between higher- and lower-margin customers. All of our gas distribution businesses remain at risk for the actual versus forecast of large volume contract commercial and industrial volumes.

With respect to our Renewable Power Generation assets, earnings from these assets are highly dependent on weather and atmospheric conditions as well as continued operational availability of these energy producing assets. While the expected energy yields for Renewable Power Generation projects are predicted using long-term historical data, wind and solar resources are subject to natural variation from year-to-year and from season-to-season. Any prolonged reduction in wind or solar resources at any of the Renewable Power Generation facilities could lead to decreased earnings and cash flows. Additionally, inefficiencies or interruptions of Renewable Power Generation facilities due to operational disturbances or outages resulting from weather conditions or other factors, could also impact earnings.

Our assets vary in age and were constructed over many decades, which causes our inspection, maintenance or repair costs to increase.

Our pipelines vary in age and were constructed over many decades. Pipelines are generally long-lived assets, and pipeline construction, including coating techniques have changed over time. Depending on the era of construction and construction techniques, some assets require more frequent inspections, which have resulted in and are expected to continue to result in increased maintenance or repair costs in the future. Any significant increase in these expenditures could adversely affect our business, operations or financial results.

Competition may result in a reduction in demand for our services, fewer project opportunities or assumption of risk that results in weaker or more volatile financial performance than expected.

Our Liquids Pipelines business faces competition from competing carriers available to ship liquid hydrocarbons to markets in Canada, the US and internationally and from proposed pipelines that seek to access basins and markets currently served by our Liquids Pipelines. Competition among existing pipelines is based primarily on the cost of transportation, access to supply, the quality and reliability of service, contract carrier alternatives and proximity to markets. The commodities transported in our pipelines currently, or are increasingly expected to, compete with other emerging alternatives for end-users, including, but not limited to, electricity, electric batteries, biofuels, and hydrogen. Additionally, we face competition from alternative storage facilities. Our natural gas transmission and storage business competes with similar facilities that serve our supply and market areas in the transmission and storage of natural gas. The natural gas transported and distributed in our business also competes with other forms of energy available to our customers and end-users, including electricity, coal, propane, fuel oils, and renewable energy. Our Renewable Power Generation business faces competition in the procurement of long-term power purchase agreements and from other fuel sources in the markets in which we operate. Competition in all of our businesses, including competition for new project development opportunities, could have a negative impact on our business, financial condition or results of operations.

Completion of our secured projects and maintenance programs are subject to various regulatory, operational and market risks, which may affect our ability to drive long-term growth.

Our project execution continues to face challenges with intense scrutiny on regulatory and environmental permit applications, politicized permitting, public opposition including protests, action to repeal permits, and resistance to land access.

Continued challenges with global supply chains have created unpredictability in materials cost and availability. Labor shortages and inflationary pressures have increased the costs of engineering and construction services. Governments in Canada and the US have enacted or proposed legislation and policies that have the potential to disrupt global and North American supply chains, which may, in turn, disrupt our project execution. They have also enacted legislation and policies relating to forced labor and child labor in supply chains which require the company to, among other things, report on the steps taken in the previous year to mitigate the risk of forced labor or child labor in our supply chain, and these requirements continue to evolve and may impact our supply chain.

Other events that can delay, and have in the past delayed project completion and increased anticipated costs include contractor or supplier non-performance, extreme weather events or geological factors beyond our control.

The effects of US and Canadian Government policies on tariffs and trade relations between Canada and the US are uncertain and could adversely impact us.

The potential imposition of trade tariffs by the US on imports from Canada, together with retaliatory tariffs by Canada on imports from the US, and other potential measures, including tariffs, duties, fees, economic sanctions or other trade measures, present risks to our business operations. Such measures, the nature, extent and timing of which are uncertain, could lead to increased costs for us and our customers and reduced demand for Canadian energy. The potential for such measures introduces uncertainty in North American energy markets, possibly disrupting supply chains and access to capital markets and jeopardizing our competitiveness, and could significantly impact our business. The US Government has also stated its interest in renegotiating and altering the Agreement between the United States of America, Mexico and Canada (USMCA), which could further impact the energy market and our business.

Changing expectations of stakeholders and government policies regarding sustainability, ESG, climate change, and environmental protection practices continue to evolve and diverge, and an inability to meet these requirements and expectations could erode stakeholder trust and confidence, damage our reputation, influence actions or decisions about Enbridge and industry and have negative impacts on our business, operations or financial results.

Companies across all sectors and industries are facing changing expectations and increasing scrutiny from a wide range of stakeholders related to their approach to sustainability and ESG matters of greatest relevance to their business and to their stakeholders. Our and other energy companies’ customers, shareholders, employees and other stakeholders have diverse expectations, demands and perspective on these topics, which are continuing to evolve. For example, companies in the energy industry, including Enbridge, have experienced stakeholder opposition to their operations and infrastructure projects, as well as organized opposition to the fossil fuel industry in general. Changing expectations of our practices and performance across these areas may result in or create exposure to new or heightened risks, which may include higher costs, project delays or cancellations, loss of ability to secure new growth opportunities or permits, restrictions on or the cessation of operations due to increasing pressure on governments and regulators, public opposition including protests, activism and legal action, such as the legal challenges to the operation of Line 5 in Michigan and Wisconsin. We may not be able to meet the diverse expectations and demands of all of our stakeholders, which could result in adverse publicity, harm our reputation, lead to claims against us and affect our relationships with our customers and employees, and subject us to legal and operational risks, any of which could have a material adverse effect on our business.

Our operations, projects and growth opportunities require us to have strong relationships with key stakeholders, including local communities, Indigenous groups and others directly impacted by our activities, as well as governments, regulatory agencies, investors and investor advocacy groups, investment funds, financial institutions, insurers and others, some of whom are increasingly focused on sustainability and ESG practices and performance. Enhanced public awareness of climate change has driven an increase in demand for lower-carbon forms of energy. In recent years, certain investors have been increasing investments in lower-carbon assets and businesses while decreasing the carbon intensity of their portfolios through, among other measures, divestment of companies with higher exposure to GHG-intensive operations and products. Commercial and investment banks and insurers have been pressured to reduce or cease providing financing and insurance coverage to the fossil fuel industry. Managing these risks requires significant effort and resources. Potential impacts could also include changing investor sentiment, impaired access to and increased cost of capital, and adverse impacts to the demand for, or value of, our services or our securities.

In recent years, geopolitical uncertainty, slowing Canadian economy and continuing inflationary pressures have underscored the critical need for access to secure, affordable energy. The pace and scale of the transition to a lower-emission economy may pose a risk if Enbridge diversifies either too quickly or too slowly. Similarly, unexpected shifts in energy demands, including due to climate change concerns, can impact revenue through, for example, reduced throughput volumes on our pipeline transportation systems.

The costs associated with meeting our ESG goals, including our GHG emissions reduction goals, could be significant. There is also a risk that some or all of the expected benefits and opportunities of achieving our ESG goals may fail to materialize, may cost more than anticipated to achieve, may not occur within the anticipated time periods, may fail to meet changing stakeholder expectations or may be challenged. Similarly, there is a risk that emissions reduction technologies do not materialize as expected, making it more difficult to reduce emissions. If we experience challenges, or perceived challenges, in achieving our ESG goals, meeting climate-related regulatory or reporting requirements, or meeting or managing stakeholder expectations regarding sustainability and ESG issues, it could have a negative impact on our reputation or investor sentiment or expose us to government enforcement actions or litigation, which may, in turn, impact our business, operations or financial results.

Our forecasted assumptions may not materialize as expected, including on our expansion projects, acquisitions and divestitures.

We evaluate expansion projects, acquisitions and divestitures on an ongoing basis. Planning and investment analysis is highly dependent on accurate forecasting and the use of appropriate assumptions and to the extent that these assumptions do not materialize, financial performance may be lower or more volatile than expected. Volatility and unpredictability in the economy, both locally and globally, and changes in cost estimates, project scoping and risk assessment could result in a loss of profits. Similarly, uncertainty in market signals, such as abrupt and unexpected shifts in energy costs and demands, have impacted and may in the future impact revenue, for example, from reduced throughput volumes on our pipeline transportation systems.

We may encounter difficulties integrating the US Gas Utilities into our business in a successful manner, which may negatively affect the benefits we expect to obtain from the Acquisitions.

In 2024, we completed the Acquisitions of the US Gas Utilities.

The success of the Acquisitions will depend on, among other things, our ability to integrate the US Gas Utilities into our business in a manner that facilitates growth opportunities and achieves anticipated results. There is a significant degree of difficulty and management distraction inherent in the process of integrating an acquisition, including challenges integrating certain operations and functions, technologies, organizations, procedures, policies and operations, cultural differences, and the retention of key personnel. The integration may be complex and time-consuming and involve delays or additional and unforeseen expenses. The integration process and other disruptions resulting from the Acquisitions may also disrupt our ongoing business.

Any failure to realize the anticipated benefits of the Acquisitions, additional unanticipated costs or other factors could negatively impact our earnings or cash flows, decrease or delay any beneficial effects of the Acquisitions and negatively impact our business, financial condition and results of operations.

Our insurance coverage may not fully cover our losses in the event of an accident, natural disaster or other event, and we may encounter increased cost arising from the maintenance of, or lack of availability of, insurance.

Our operations are subject to many hazards inherent in our industry as described in this Item 1A. Risk Factors. We maintain an insurance program for Enbridge, our subsidiaries and certain of our affiliates, to mitigate a certain portion of our risks. However, not all potential risks arising from our operations are insurable or are insured by us as a result of lack of availability, high premiums or other reasons. Enbridge self-insures a significant portion of certain risks through our wholly-owned captive insurance subsidiaries, and Enbridge’s insurance coverage is subject to terms and conditions, exclusions and large deductibles or self-insured retentions, which may reduce or eliminate coverage in certain circumstances.

Enbridge’s insurance policies are generally renewed on an annual basis and, depending on factors such as market conditions, premiums, terms, policy limits and/or deductibles, can vary substantially. We can give no assurance that we will be able to maintain adequate insurance in the future at rates or on other terms that we consider commercially reasonable. In such a case, we may decide to self-insure additional risks.

A significant self-insured loss, uninsured loss, a loss significantly exceeding the limits of our insurance policies, a significant delay in the payment of a major insurance claim, or the failure to renew insurance policies on similar or favorable terms, could materially and adversely affect our business, financial condition and results of operations.

Our business is exposed to changes in market prices, including interest rates and foreign exchange rates. Our risk management policies cannot eliminate all risks and may result in material financial losses. In addition, any non-compliance with our risk management policies could adversely affect our business, operations or financial results.

Our use of debt financing exposes us to changes in interest rates on both future fixed rate debt issuances and floating rate debt. While our financial results are denominated in Canadian dollars, many of our businesses have foreign currency revenues or expenses, particularly the US dollar. Changes in interest rates and foreign exchange rates could materially impact our financial results.

We use financial derivatives to manage risks associated with changes in foreign exchange rates, interest rates, commodity prices, power prices and our share price, to reduce the volatility of our cash flows. Based on our risk management policies, substantially all of our financial derivatives are associated with an underlying asset, liability and/or forecasted transaction and are not intended for speculative purposes.

These policies cannot, however, eliminate all risk, including unauthorized trading. Although this activity is monitored independently by our risk management function, we can provide no assurance that we will detect and prevent all unauthorized trading and other violations, particularly if deception, collusion or other intentional misconduct is involved, and any such violations could adversely affect our business, operations or financial results.

To the extent that we hedge our exposure to market prices, we will forego the benefits we would otherwise experience if these were to change in our favor. In addition, hedging activities can result in losses that might be material to our financial condition, results of operations and cash flows. Such losses have occurred in the past and could occur in the future. See Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk and Item 8. Financial Statements and Supplementary Data for a discussion of our derivative instruments and related hedging activities.

We rely on access to short-term and long-term capital markets to finance capital requirements and support liquidity needs. Cost effective access to those markets can be affected, particularly if we or our rated subsidiaries are unable to maintain an investment-grade credit rating.

A significant portion of our consolidated asset base is financed with debt. The maturity and repayment profile of debt used to finance investments often does not correlate to cash flows from assets. Accordingly, we rely on access to both short-term and long-term capital markets as a source of liquidity for capital requirements not satisfied by cash flows from operations and to refinance investments originally financed with debt. Our senior unsecured long-term debt is currently rated investment-grade by various rating agencies. If the rating agencies were to rate us or our rated subsidiaries below investment-grade, our borrowing costs could increase, potentially significantly. Consequently, we could be required to pay a higher interest rate in future financings and our potential pool of investors and funding sources could decrease.

We maintain revolving credit facilities at various entities to backstop commercial paper programs, for borrowings and for providing letters of credit. These facilities typically include financial covenants and failure to maintain these covenants at a particular entity could preclude that entity from accessing the credit facility, which could impact liquidity. If our short-term debt rating were to be downgraded, access to the commercial paper market could be significantly limited. Although this would not affect our ability to draw under our credit facilities, borrowing costs could be significantly higher.

If we are not able to access capital at competitive rates or at all, our ability to finance operations and implement our strategy may be affected. An inability to access capital on favorable terms or at all may limit our ability to pursue enhancements or acquisitions that we may otherwise rely on for future growth or to refinance our existing indebtedness. Any downgrade or other event negatively affecting the credit ratings of our subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could increase our need to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing the liquidity and borrowing availability of the consolidated group.

Our Liquids Pipelines growth rate and results may be indirectly affected by commodity prices.

Wide commodity price basis between Western Canada and global tidewater markets has negatively impacted producer netbacks and margins in the past that largely resulted from pipeline infrastructure takeaway capacity from producing regions in Western Canada and North Dakota, which are operating at capacity. A protracted long-term outlook for low crude oil prices could result in delay or cancellation of future projects.

The tight conventional oil plays of Western Canada, the Permian Basin, and the Bakken region of North Dakota, have short cycle break-even time horizons, typically less than 24 months, and high decline rates that can be managed through active hedging programs and are positioned to react quickly to market signals. Accordingly, during periods of comparatively low prices, drilling programs, unsupported by hedging programs, may be reduced, and as such, supply growth from tight oil basins may be lower, which could impact volumes on our pipeline systems.

Crude oil marketing generates margin by capitalizing on quality, time and location differentials when opportunities arise. Changing market conditions that impact the prices at which we buy and sell commodities have in the past limited margin opportunities and impeded our ability to cover capacity commitments and could do so again in the future. Other market conditions, such as backwardation, have likewise limited margin opportunities.

Our Gas Transmission results may be adversely affected by commodity price volatility.

Within our US Midstream assets, we hold a 13.2% effective economic interest in DCP, which is engaged in the businesses of gathering, treating, processing and selling natural gas and natural gas liquids. In addition, we own Tomorrow RNG, which operates landfill gas-to-RNG production facilities and Aitken Creek Gas Storage Facility, which operates an underground natural gas storage facility. The financial results of these businesses are directly and indirectly impacted by changes in commodity prices. To a lesser degree, the financial results of our Gas Transmission business is subject to fluctuation in power prices, which impact electric power costs associated with operating some of our compressor stations.

We are exposed to the credit risk of our customers, counterparties, and vendors.

We are exposed to the credit risk of multiple parties in the ordinary course of our business. Generally, our customers are rated investment-grade, are otherwise considered creditworthy, or provide us with security to satisfy credit concerns. However, we cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including possible declines in the creditworthiness of our customers, vendors, or counterparties. It is possible that payment or performance defaults from these entities, if significant, could adversely affect our earnings and cash flows.

Our business requires the retention and recruitment of a skilled and diverse workforce, and difficulties in recruiting and retaining our workforce could result in a failure to implement our business plans.

Our operations and management require the retention and recruitment of a skilled and diverse workforce, including engineers, technical personnel, other professionals and executive officers and senior management. Enbridge and our affiliates compete with other companies in the energy industry, and for some jobs the broader labor market, for this skilled workforce. If we are unable to retain current employees and/or recruit new employees of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased costs to retain and recruit these professionals.

RISKS RELATED TO GOVERNMENT REGULATION AND LEGAL RISKS

Many of our operations are regulated and failure to secure timely regulatory approval for our proposed projects, or loss of required approvals for our existing operations, could have a negative impact on our business, operations or financial results.

The nature and degree of regulation and legislation affecting permitting and environmental review for energy infrastructure companies in Canada and the US continues to evolve. In addition, within the US and in Canada, energy companies continue to face opposition from anti-energy/anti-pipeline activists, environmental groups, politicians and other stakeholders concerned with the safety of energy infrastructure and its potential environmental effects.

In the US, the EPA released rules to reduce methane emissions from the oil and gas sector, standards for reducing emissions from fossil fuel fired power plants, and rules to streamline the process for states and tribes to assume authority over the *Clean Water Act'*s section 404 permitting program for discharges of dredge and fill material. The Council for Environmental Quality (CEQ) issued its Phase 2 rule concerning analyses under the National Environmental Policy Act (NEPA), that may significantly change environmental scope and cost assessments for energy projects. The FERC has focused on the relationship between natural gas and electric power generation, particularly in connection with reliability issues during severe weather events. PHMSA issued rules updating requirements for sustainable and safe pipeline operation. Many regulations are being challenged in the courts, including the ability of the CEQ to promulgate regulations applicable to other federal agencies, and some have been overturned by reviewing courts. The new US administration may take further action to modify or reverse regulations that were promulgated by the current US administration.

In Canada, the Supreme Court of Canada issued a decision on the federal Impact Assessment Act (IAA), finding that it is largely outside of the federal Parliament's authority and that the IAA should focus more narrowly on effects within federal jurisdiction. The federal government amended the IAA in response to this decision; however, the scope and application of federal review of intraprovincial pipeline projects remains unclear. In November 2024, the Government of Alberta has again referred the issue to the Alberta Court of Appeal for hearing, to determine whether the IAA, as amended, is unconstitutional. As a result, the uncertainty for pipeline and other energy infrastructure projects in Canada is ongoing.

These actions could adversely impact permitting of a wide range of energy projects. We may not be able to obtain or maintain all required regulatory approvals for our operating assets or development projects. If there is a significant delay in obtaining any required regulatory approvals, if we fail to obtain or comply with them, or if laws or regulations change or are administered in a more stringent manner, the operations of existing facilities or the development of new facilities could be prevented, delayed or become subject to additional costs.

Our operations are subject to numerous environmental laws, regulations, and rules, including those relating to climate change, GHG emissions, climate-related disclosure, and anti-greenwashing, compliance with which may require significant capital expenditures, increase our cost of operations, affect or limit our business plans, expose us to environmental liabilities or litigation, and affect our reputation and relationships with stakeholders.

We are subject to numerous environmental laws and regulations affecting many aspects of our operations, including, but not limited to, air emissions, climate change, water, soil, land management, waste, hazardous substances, wildlife and protected species, biodiversity, noise, emergency response, and pollution. We are also subject to new and evolving laws, regulations and rules related to ESG and sustainability-related disclosure, including climate-related disclosure, and anti-greenwashing provisions, including recent amendments to Canadian competition legislation, which simultaneously increase stakeholder expectations to report environmental and climate-related information and also substantiate such information in accordance with standards that are still developing and evolving, and which may, in some cases conflict. Our exposure to these risks could result in adverse impacts to our reputation and relationships with stakeholders or increased costs, liabilities or litigation.

If we are unable to obtain or maintain all required environmental regulatory approvals and permits for our operating assets and projects, or if there is a delay in obtaining any required environmental regulatory approvals or permits, the operation of existing facilities or the development of new facilities could be prevented, delayed, or become subject to additional costs. Failure to comply with environmental laws, regulations, and rules may result in the imposition of civil or criminal fines, penalties and injunctive measures affecting our operating assets. We expect that changes in environmental laws, regulations, and rules, including those related to climate change, GHG emissions, climate-related disclosure, and anti-greenwashing, could result in a material increase in our cost of compliance with such laws and regulations, such as costs to monitor and report our emissions, install new emission controls to reduce emissions, and third-party substantiation, verification or assurance of our environmental data, the costs of which we may not be able to recover.

Our operations are subject to operational regulation and other requirements, including compliance with easements and other land tenure documents, and failure to comply with applicable regulations and other requirements could have a negative impact on our reputation, business, operations or financial results.

Operational risks relate to compliance with applicable operational rules and regulations mandated by governments, applicable regulatory authorities, or other requirements that may be found in easements, permits, or other agreements that provide a legal basis for our operations, breaches of which could result in fines, penalties, awards of damages, operational restrictions or shutdowns, and an overall increase in operating and compliance costs.

We do not own all of the land on which our pipelines, facilities and other assets are located, and we obtain the right to construct and operate our pipelines and other assets from third parties or government entities. In addition, some of our pipelines, facilities and other assets cross Indigenous lands pursuant to rights-of-way or other land tenure interests. Our loss of these rights, including through our inability to renew them as they expire, could have an adverse effect on our reputation, operations and financial results. We have experienced litigation in relation to Line 5 and other easements. Refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates.

Regulatory scrutiny of our assets and operations has the potential to increase operating costs or limit future projects. Regulatory enforcement actions issued by regulators for non-compliance can increase operating costs and negatively impact reputation. Potential regulatory changes and legal challenges could have an impact on our future earnings from operations and the cost related to the construction of new projects. Future actions of regulators may differ from current expectations, or future legislative changes may impact the regulatory environments in which we operate. While we seek to mitigate operational regulation risk by actively monitoring and consulting on potential regulatory requirement changes with the respective regulators directly, or through industry associations, and by developing response plans to regulatory changes or enforcement actions, such mitigation efforts may be ineffective or insufficient. While we believe the safe and reliable operation of our assets and adherence to existing regulations is the best approach to managing operational regulatory risk, the potential remains for regulators or other government officials to make unilateral decisions that could disrupt our operations or have an adverse financial impact on us.

Our operations are subject to economic regulation and failure to secure regulatory approval for our proposed or existing commercial arrangements could have a negative impact on our business, operations or financial results.

Our Liquids Pipelines, Gas Transmission, and Gas Distribution and Storage assets face economic regulation risk. Broadly defined, economic regulation risk is the risk that governments or regulatory agencies change or reject proposed or existing commercial arrangements or policies, including permits and regulatory approvals for both new and existing projects or agreements, upon which future and current operations are dependent. Our Mainline System, other liquids pipelines, gas transmission and distribution assets are subject to the actions of various regulators, including the CER, the FERC, the OEB, the Ohio Commission, the Utah Commission, the Wyoming Commission, the Idaho Commission, and the North Carolina Commission, with respect to the rates, tariffs, and tolls for these assets. The changing or rejection of commercial arrangements, including decisions by regulators on the applicable permits and tariff structure or changes in interpretations of existing regulations by courts or regulators, has had in the past, and could in the future have an adverse effect on our revenues and earnings.

Our Renewable Power Generation assets in Canada and the US are subject to directives, regulations, and policies of federal, provincial and state governments. These measures are variable and can change as a result of, among other things, tax rate changes and a change in the government, which can have a negative impact on our commercial arrangements.

Our Renewable Power Generation assets in Europe (France, Germany and the UK) are also subject to the directives, regulations and policies established and enforced by the EU and the UK government. These measures are variable and can include price controls, caps and demand reduction goals, all of which can have a negative impact on our revenues and earnings.

We are subject to changes in our tax rates, the adoption of new US, Canadian or international tax legislation or exposure to additional tax liabilities.

We are subject to taxes in the US, Canada and numerous foreign jurisdictions. Due to economic and political conditions, tax rates in various jurisdictions may be subject to significant change. Our effective tax rates could be affected by changes in the mix of earnings in countries with differing statutory tax rates, changes in the valuation of deferred tax assets and liabilities, or changes in tax laws or their interpretation.

We are also subject to the examination of our tax returns and other tax matters by the US Internal Revenue Service, the Canada Revenue Agency and other tax authorities and governmental bodies. We regularly assess the likelihood of an adverse outcome resulting from these examinations to determine the adequacy of our provision for taxes. There can be no assurance as to the outcome of these examinations. If our effective tax rates were to increase, particularly in the US or Canada, or if the ultimate determination of our taxes owed is for an amount in excess of amounts previously accrued, our financial condition and operating results could be materially adversely affected.

We are involved in numerous legal proceedings, the outcomes of which are uncertain, and resolutions adverse to us could adversely affect our financial results and reputation.

We are subject to numerous legal proceedings related to our business and operations. In recent years, there has been an increase in climate-related regulatory action and litigation, including against companies involved in the energy industry. There is no assurance that we will not be impacted by such regulatory action, litigation, or other legal proceedings. By its nature, litigation is subject to many uncertainties, and we cannot predict the outcome of individual matters with assurance. It is reasonably possible that the final resolution of some of the matters in which we are involved or new matters could require additional expenditures, in excess of established reserves, over an extended period of time and in a range of amounts that could adversely affect our financial results or adversely affect our reputation. Refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates for a discussion of certain legal proceedings with recent developments.

Cybersecurity risk management, strategy and governance

Oversight of cybersecurity is integrated into the responsibilities of the Board and its committees. The Board is responsible for identifying and understanding Enbridge’s principal risks and ensuring that appropriate systems are implemented to monitor, manage and mitigate those risks. The committees of the Board have oversight over risks within their respective mandates.

The Audit, Finance and Risk Committee (AFRC) provides primary oversight of cybersecurity matters, including with respect to financial risk and controls, integrity of financial data and public disclosures, and security of the cyber landscape across data and digital. Management provides quarterly cybersecurity reports to the AFRC and the Board and also reports to the Safety and Reliability Committee, as deemed necessary, on cybersecurity issues related to safety, reliability and operations.

Each year, management prepares and provides to the Board and its committees a corporate risk assessment (CRA), which analyzes and prioritizes enterprise-wide risks, highlighting top risks and trends (including cybersecurity). The annual CRA is an integrated enterprise-wide process which engages each part of our business to assess and rank risks based on impact and probability. We strive to ensure that mitigation measures are appropriately designed, prioritized and resourced. The CRA report is reviewed by the Board committees with responsibility for the risk categories relevant to their mandate and is provided to the Board, which coordinates Enbridge's overall risk management approach. Complementary to the CRA, management prepares and provides to the Safety and Reliability Committee an annual top operational risk report that highlights the highest consequence operational risks across Enbridge and includes further detail on the risks and their treatment. This information helps inform the Board about the potential impact of top operational risks and of treatments in place to manage those risks.

Cybersecurity has been identified as a top risk, as attacks against participants in our industry have continued to increase in sophistication and frequency over the years. Although we devote significant resources and security measures to prevent unwanted intrusions and to protect our systems and data, we (and our third-party vendors) have experienced, and expect to continue to experience, cyber attacks of varying degrees in the conduct of our business, including, for example, denial of service attacks. Cybersecurity risk is described in Item 1A. Risk Factors.

Enbridge’s management is responsible for the implementation of risk management strategies and monitoring performance. The technology and information services (TIS) function is centralized under the Senior Vice President & Chief Information Officer (CIO). We also engage independent third parties to assess our cybersecurity program, track their recommendations, and use those to further improve the program. Reporting to the CIO is the Chief Information Security Officer who is in charge of our cybersecurity program and oversees the 24x7x365 Security Operations Center (SOC).

We conduct continuous assessments of our cybersecurity standards, perform regular tests of our ability to respond and recover, and monitor for potential threats. To further mitigate threats, we collaborate with governments and regulatory agencies and take part in external events to learn and share. Our workforce participates in regular security awareness training, including exercises to build capabilities to identify and report suspect phishing emails to our SOC. In the last year, we continued to expand the cybersecurity training and simulated testing we administer to high-risk groups within the organization. A tailored cybersecurity training course has been implemented for team members in operational technology roles, and we have increased the frequency of phishing simulation tests.

We have a cybersecurity third-party risk management program, which is an evolving, cross-functional program to help assess and mitigate risks from third-party vendors and other service providers. Our cybersecurity team also uses several layers of defense and protection technologies, cybersecurity experts, and automated alerting and response mechanisms to reduce risk to Enbridge.

Although cybersecurity risks have not materially affected us, including our business strategy, results of operations or financial condition, to date, we have experienced an increasing number of cybersecurity threats in recent years. For more information about the cybersecurity risks we face, see the risk factor entitled "Cyber attacks and other cybersecurity incidents pose threats to our technology systems and could materially adversely affect our business, operations, reputation or financial results." in Item 1A. Risk Factors.

Descriptions of our properties and maps depicting the locations of our liquids, natural gas, and renewable power systems are included in Part I. Item 1. Business.

In general, our systems are located on land owned by others and are operated under easements and rights-of-way, licenses, leases or permits that have been granted by private landowners, Indigenous communities, public authorities, railways or public utilities. Our liquids pipeline systems have pumping stations, tanks, terminals and certain other facilities that are located on land that is owned by us and/or used by us under easements, licenses, leases or permits. Additionally, our natural gas pipeline systems have natural gas compressor stations, the vast majority of which are located on land that is owned by us. The remainder of these compressor stations and other assets, such as meter and valve stations, and underground gas storage fields, are used by us under easements, leases or permits.

Titles to Enbridge owned properties or affiliate entities may be subject to encumbrances in some cases. We believe that none of these burdens should materially detract from the value of these properties or materially interfere with their use in the operation of our business.

We are involved in various legal and regulatory actions and proceedings which arise in the ordinary course of business. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our consolidated financial position or results of operations. Refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates for discussion of certain legal proceedings with recent developments.

SEC regulations require the disclosure of any proceeding under environmental laws to which a governmental authority is a party unless the registrant reasonably believes it will not result in monetary sanctions over a certain threshold. Given the size of our operations, we have elected to use a threshold of US$1 million for the purposes of determining proceedings requiring disclosure. We have no such proceedings to disclose in this annual report.

INTRODUCTION

The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with "Forward-Looking Information" and "Non-GAAP and Other Financial Measures", Part I. Item 1A. Risk Factors and our consolidated financial statements and the accompanying notes included in Part II. Item 8. Financial Statements and Supplementary Data of this Annual Report on Form 10-K.

This section of our Annual Report on Form 10-K discusses 2024 and 2023 items and year-over-year comparisons between 2024 and 2023. For discussion of 2022 items and year-over-year comparisons between 2023 and 2022, refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report on Form 10-K for the year ended December 31, 2023.

RECENT DEVELOPMENTS

MAINLINE TOLLING AGREEMENT

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 Inc. (Enbridge) filed an application with the Canadian Energy Regulator (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. Refer to Part I. Item I. Business - Business Segments - Liquids Pipelines - Tolling Framework for detailed terms of the MTS.

ACQUISITIONS

US Gas Utilities

On September 5, 2023, Enbridge entered into three separate definitive agreements with Dominion Energy, Inc. to acquire The East Ohio Gas Company (EOG), Questar Gas Company (Questar) and its related Wexpro companies (Wexpro), and Public Service Company of North Carolina, Incorporated (PSNC) (together, the Acquisitions).

On September 30, 2024, we acquired all of the membership interests of Fall North Carolina Holdco LLC, which owns 100% of PSNC, for cash consideration of $2.7 billion (US$2.0 billion) (the PSNC Acquisition). PSNC is a public utility primarily engaged in the purchase, sale, transportation and distribution of natural gas to residential, commercial and industrial customers in North Carolina. PSNC operates under rates approved by the North Carolina Utilities Commission (North Carolina Commission). Subsequent to its acquisition, PSNC conducts business as Enbridge Gas North Carolina.

On May 31, 2024, we acquired all of the membership interests of Fall West Holdco LLC which owns 100% of Questar and Wexpro for cash consideration of $4.1 billion (US$3.0 billion) (the Questar Acquisition). Questar is a public natural gas utility providing distribution, storage and transmission services to residential, commercial and industrial customers in Utah, southwestern Wyoming and southeastern Idaho. The Utah Public Service Commission (Utah Commission), the Wyoming Public Service Commission (Wyoming Commission), and the Idaho Public Utilities Commission (Idaho Commission) have granted Questar the necessary regulatory approvals to serve these areas. Wexpro develops and produces cost-of-service gas reserves for Questar and operates under agreements with the states of Utah and Wyoming. Subsequent to its acquisition, Questar conducts business as Enbridge Gas Utah, Enbridge Gas Wyoming, and Enbridge Gas Idaho in those respective states.

On March 6, 2024, we acquired all of the outstanding shares of capital stock of EOG for cash consideration of $5.8 billion (US$4.3 billion) (the EOG Acquisition). EOG is a public natural gas utility providing distribution, storage and transmission services to residential, commercial and industrial customers in Ohio and is regulated by the Public Utilities Commission of Ohio (Ohio Commission). Subsequent to its acquisition, EOG conducts business as Enbridge Gas Ohio.

The Acquisitions further diversify, and are complementary to, our existing gas distribution operations.

Joint Venture with WhiteWater/I Squared and MPLX

On May 29, 2024, we formed a joint venture (the Whistler Parent JV) with WhiteWater/I Squared Capital (WhiteWater/I Squared) and MPLX LP (MPLX) that will develop, construct, own and operate natural gas pipeline and storage assets connecting Permian Basin natural gas supply to growing liquefied natural gas (LNG) and other US Gulf Coast demand. The Whistler Parent JV is owned by WhiteWater/I Squared (50.6%), MPLX (30.4%) and Enbridge (19.0%) and owns the following assets:

• a 100% interest in the Whistler Pipeline, a 450-mile intrastate pipeline transporting natural gas from the Waha Header in the Permian Basin to Agua Dulce, Texas;
• a 100% interest in the Rio Bravo Pipeline project, two new parallel 137-mile pipelines transporting natural gas from the Agua Dulce supply area to NextDecade's Rio Grande LNG project in Brownsville, Texas;
• a 70% interest in the ADCC Pipeline, a new 40-mile pipeline which was placed into service in July 2024 and is designed to transport 1.7 billion cubic feet per day (bcf/d) of natural gas from the terminus of the Whistler Pipeline in Agua Dulce, Texas to Cheniere's Corpus Christi LNG export facility; and
• a 50% interest in Waha Gas Storage, a 2.0 bcf gas storage cavern facility connecting to key Permian egress pipelines including the Whistler Pipeline.

In connection with the formation of the Whistler Parent JV, we contributed our 100% interest in the Rio Bravo Pipeline project and $487 million (US$357 million) of cash to the Whistler Parent JV. In addition to our 19.0% equity interest in the Whistler Parent JV, we received a special equity interest in the Whistler Parent JV which provides for a 25.0% economic interest in the Rio Bravo Pipeline project. This interest is subject to certain redemption rights held by Whitewater/I Squared and MPLX. After the closing on May 29, 2024, we accrued for our share of the post-closing mandatory capital expenditures of approximately US$150 million for the Rio Bravo Pipeline project. Additional capital expenditures to complete the Rio Bravo Pipeline project will be proportionate to our economic interest.

Acquisition of Renewable Natural Gas (RNG) Facilities

On January 2, 2024, through a wholly-owned US subsidiary, we acquired six Morrow Renewables operating landfill gas-to-RNG production facilities (Tomorrow RNG) located in Texas and Arkansas for total consideration of $1.3 billion (US$1.0 billion), of which $584 million (US$439 million) was paid at close and an additional deferred consideration is payable within two years with a fair value of $757 million (US$568 million). The acquired assets align with and advance our lower-carbon strategy.

ASSET MONETIZATION

Disposition of Alliance Pipeline and Aux Sable Interests

On April 1, 2024, we closed the sale of our 50.0% interest in the Alliance Pipeline, our interest in Aux Sable (including a 42.7% interest in Aux Sable Midstream LLC and Aux Sable Liquid Products L.P., and a 50.0% interest in Aux Sable Canada LP) and our interest in NRGreen Power Limited Partnership (NRGreen) to Pembina Pipeline Corporation (Pembina) for $3.1 billion, including $327 million of non-recourse debt. A gain on disposal of $1.1 billion before tax, which is net of $1.0 billion of the goodwill from our Gas Transmission segment allocated to the disposal group, is included in Gain on disposition of equity investments in the Consolidated Statements of Earnings for the year ended December 31, 2024.

GAS TRANSMISSION RATE PROCEEDINGS

Texas Eastern

In May 2024, Texas Eastern Transmission, LP (Texas Eastern) reached a negotiated settlement with customers to increase rates starting October 1, 2024 with additional increases on January 1, 2026. Texas Eastern filed a Stipulation and Agreement with the Federal Energy Regulatory Commission (FERC) on June 3, 2024 and received approval on July 31, 2024 from the FERC of its uncontested settlement with customers.

Algonquin

Algonquin Gas Transmission, LLC (Algonquin) filed a rate case on May 30, 2024. On June 28, 2024, the FERC issued an order accepting and suspending tariff records, subject to refund, conditions, and establishing hearing procedures. In December 2024, Algonquin reached a settlement in principle with customers which will be filed for FERC approval in the first quarter 2025. If approved, rates will be effective December 1, 2024.

Maritimes & Northeast Pipeline

Maritimes & Northeast Pipeline (M&N) US filed a rate case on May 30, 2024. On June 27, 2024, the FERC issued an order accepting and suspending tariff records, subject to refund, conditions, and establishing hearing procedures. In December 2024, M&N US reached a settlement in principle with customers which will be filed for FERC approval in the first quarter 2025. If approved, rates will be effective January 1, 2025.

GAS DISTRIBUTION AND STORAGE RATE APPLICATIONS

Incentive Regulation Rate Application

In October 2022, Enbridge Gas Inc. (Enbridge Gas Ontario) filed its application with the Ontario Energy Board (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.

Enbridge Gas Ohio

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 and Capital Expenditure Program. 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.

FINANCING UPDATE

We completed long-term debt issuances totaling US$5.7 billion and $1.8 billion during the year ended December 31, 2024.

On the March 8, 2024 call date, we redeemed at par all of the outstanding US$700 million three-year callable, 5.97% senior notes that carried an original maturity date in March 2026.

During our annual renewal process, we renewed and extended approximately $17.6 billion of our credit facilities with maturities ranging from 2025-2029. We also increased our letter of credit facilities by approximately $346 million and entered into new term loans with maturities ranging from 2029-2049 totaling approximately $542 million.

On May 15, 2024, we established an at-the-market equity issuance program (ATM Program) which provided us with additional flexibility to fund the Acquisitions. From May 15, 2024 to July 31, 2024, 51,298,629 common shares were issued on Canadian and US exchanges at average prices of CAD$48.72 and US$35.77 per common share for aggregate gross proceeds of $2.50 billion. On August 1, 2024, we terminated the ATM Program.

On September 8, 2023, we closed a public offering of 102,913,500 common shares at a price of $44.70 per share for gross proceeds of $4.6 billion which were also used to finance a portion of the aggregate cash consideration payable for the Acquisitions discussed in Note 6 - Acquisitions and Dispositions.

Our 2024 financing activities have provided significant liquidity that we expect will enable us to fund our current portfolio of capital projects and acquisitions without requiring access to the capital markets for the next 12 months should market access be restricted or pricing be unattractive. Refer to Liquidity and Capital Resources.

As at December 31, 2024, after adjusting for the impact of floating-to-fixed interest rate swap hedges, less than 5% of our total debt is exposed to floating rates. Refer to Part II. Item 8. Financial Statements and Supplementary Data - Note 23 - Risk Management and Financial Instruments for more information on our interest rate hedging program.

RESULTS OF OPERATIONS

(millions of Canadian dollars, except per share amounts)

1 Non-GAAP financial measures.

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Year ended December 31, 2024 compared with year ended December 31, 2023

Earnings attributable to common shareholders decreased by $1.1 billion due to certain infrequent or other non-operating factors, primarily explained by the following:

• a non-cash, net unrealized loss of $2.1 billion ($1.6 billion after-tax) in 2024, compared with a net unrealized gain of $1.2 billion ($911 million after-tax) in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange, interest rate, and commodity price risk;
• the absence in 2024 of a gain of $151 million ($129 million after-tax) net of a deferred tax adjustment of $69 million recognized as a result of the discontinuation of regulatory accounting for Southern Lights Pipeline;
• an asset impairment loss of $137 million ($103 million after-tax) related to the Big Sandy Pipeline;
• severance costs of $105 million ($79 million after-tax) as a result of a workforce reduction in February 2024;
• $137 million ($114 million after-tax) of integration and transaction costs incurred related to the Acquisitions in 2024, as compared to $31 million ($24 million after-tax) of transaction costs in 2023;
• the absence of the receipt of a litigation claim settlement of $68 million ($52 million after-tax); and
• an impairment loss of $55 million ($49 million after-tax) related to certain renewable assets.

The factors above were partially offset by:

• a gain on sale of $1.1 billion ($765 million after-tax) related to the disposition of interests in the Alliance Pipeline, Aux Sable and NRGreen;
• the absence in 2024 of:
• a realized loss of $638 million ($479 million after-tax) due to termination of foreign exchange hedges, as foreign exchange risks inherent within the Competitive Tolling Settlement (CTS) framework are not present in the negotiated MTS;
• an impairment of $281 million ($232 million after-tax) recognized to certain capital projects, capital costs and pension balances in the fourth quarter of 2023 as a result of the OEB's Phase 1 Decision;
• a provision adjustment of $124 million ($95 million after-tax) related to a litigation matter;
• an asset retirement loss of $86 million ($65 million after-tax) related to our Alberta Regional Oil Sands System; and
• a deferred tax recovery of $141 million in 2024 due to change in state apportionment as a result of the Acquisitions.

The non-cash, unrealized derivative fair value gains and losses discussed above generally arise as a result of our comprehensive economic hedging program to mitigate foreign exchange, interest rate and commodity price risks. This program creates volatility in reported short-term earnings through the recognition of unrealized non-cash gains and losses on derivative instruments used to hedge these risks. Over the long-term, we believe our hedging program supports the reliable cash flows and dividend growth upon which our investor value proposition is based.

After taking into consideration the factors above, the remaining $294 million increase in earnings attributable to common shareholders is primarily explained by the following significant business factors:

• contributions from Enbridge Gas Ohio, Enbridge Gas Utah and Wexpro, and Enbridge Gas North Carolina, and higher distribution charges resulting from increases in customer base and higher demand in the contract market from Enbridge Gas Ontario in our Gas Distribution and Storage segment;
• higher contributions from our Gas Transmission segment primarily due to favorable contracting and lower operating costs in our US Gas Transmission assets, and acquisitions of Tres Palacios and Aitken Creek in 2023, Tomorrow RNG, and Whistler Parent JV in 2024;
• higher contributions from our Renewable Power Generation segment due to the generation of investment tax credits from our investment in Fox Squirrel Solar and the acquisition of an additional 24.45% interest in the Hohe See and Albatros Offshore Wind Facilities in November 2023;
• higher contributions from our Liquids Pipelines segment due to lower Mainline power costs and discontinuation of rate-regulated accounting of Southern Lights Pipeline as at December 31, 2023; and
• higher investment income in Eliminations and Other from the pre-funding of the Acquisitions and from our wholly-owned insurance subsidiaries; partially offset by
• full year of lower Mainline system tolls in our Liquids Pipelines segment as a result of revised tolls effective July 1, 2023 and lower Line 3 Replacement (L3R) surcharge;
• lower contributions from Alliance Pipeline and Aux Sable from our Gas Transmission segment due to the sale of our interest in these investments in April 2024;
• higher interest expense primarily due to higher average principal outstanding resulting from the Acquisitions;
• higher depreciation and amortization expense mainly driven by acquisitions we completed in 2023 and 2024, as mentioned above;
• higher income tax expense largely driven by higher earnings and higher US minimum tax; and
• higher realized foreign exchange loss on hedge settlements in Eliminations and Other in 2024.

REVENUES

We generate revenues from three primary sources: transportation and other services, gas distribution sales and commodity sales.

Transportation and other services revenues of $19.7 billion, $19.2 billion and $17.9 billion for the years ended December 31, 2024, 2023 and 2022, respectively, were earned from our crude oil and natural gas pipeline transportation businesses and also include power generation revenues from our portfolio of renewable and power generation assets. For our transportation assets operating under market-based arrangements, revenues are driven by volumes transported and the corresponding tolls for transportation services. For assets operating under take-or-pay contracts, revenues reflect the terms of the underlying contract for services or capacity. For rate-regulated assets, revenues are charged in accordance with tolls established by the regulator and, in most cost-of-service based arrangements, are reflective of our cost to provide the service plus a regulator-approved rate of return.

Gas distribution sales revenues of $6.8 billion, $5.4 billion and $6.2 billion for the years ended December 31, 2024, 2023 and 2022, respectively, were recognized in a manner consistent with the underlying rate-setting mechanism mandated by the regulator. Revenues generated by the gas distribution businesses are primarily driven by volumes delivered, which vary with weather and customer composition and utilization, as well as regulator-approved rates. The cost of natural gas is passed through rates to customers and does not ultimately impact earnings due to its flow-through nature.

Commodity sales revenues of $27.0 billion, $19.0 billion and $29.2 billion for the years ended December 31, 2024, 2023 and 2022, respectively, were generated primarily through our crude oil marketing, natural gas and power marketing businesses. This includes the purchase and sale of crude oil, natural gas, power and NGL to generate a margin, which is typically a small fraction of gross revenue. Sales revenue generated from these operations reflect activity levels which are driven by differences in commodity prices between locations, grades and points in time, rather than on absolute prices. Commodity sales revenues also include revenue generated from our Tomorrow RNG business. Any residual commodity margin risk is closely monitored and managed. Revenues from these operations depend on activity levels, which vary from year-to-year depending on market conditions and commodity prices.

Our revenues also include changes in unrealized derivative fair value gains and losses related to foreign exchange and commodity price contracts used to manage exposures from movements in foreign exchange rates and commodity prices. The mark-to-market accounting creates volatility and impacts the comparability of revenues in the short-term, but we believe over the long-term, the economic hedging program supports reliable cash flows.

BUSINESS SEGMENTS

LIQUIDS PIPELINES

Year ended December 31, 2024 compared with year ended December 31, 2023

EBITDA was negatively impacted by $71 million due to certain infrequent or other non-operating factors, primarily explained by the following:

• a non-cash, net unrealized gain of $2 million in 2024, compared with a net unrealized gain of $615 million in 2023, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks; and
• the absence in 2024 of both a gain of $151 million recognized as a result of Southern Lights' discontinuation of regulatory accounting and the receipt of a litigation claim settlement of $68 million, partially offset by
• the absence in 2024 of both a realized loss of $638 million due to termination of foreign exchange hedges, as foreign exchange risks inherent within the CTS framework are not present in the negotiated MTS and an asset retirement loss of $86 million related to our Alberta Regional Oil Sands System; and
• a net positive adjustment to crude oil inventory of $15 million in 2024, compared with a net negative adjustment of $16 million in 2023.

After taking into consideration the factors above, the remaining $219 million increase is primarily explained by the following significant business factors:

• lower Mainline power costs from operational efficiencies and lower Alberta mill rates;
• higher contributions from the Southern Lights Pipeline due primarily to the discontinuation of rate-regulated accounting as at December 31, 2023;
• higher contributions from the Gulf Coast and Mid-Continent System due primarily to higher volumes on the Flanagan South Pipeline driven by the open season commitments that commenced in the first quarter of 2024, and the Enbridge Ingleside Energy Center due to higher demand and new storage contracts that commenced in the second quarter of 2024; and
• the favorable effect of translating US dollar EBITDA at a higher average exchange rate in 2024, as compared to 2023, partially offset by
• full year of lower Mainline System tolls as a result of revised tolls effective July 1, 2023 and a lower L3R surcharge.

GAS TRANSMISSION

Year ended December 31, 2024 compared with year ended December 31, 2023

EBITDA was positively impacted by $1,008 million due to certain infrequent or other non-operating factors primarily explained by the following:

• a gain on sale of $1,063 million on the disposition of interests in the Alliance Pipeline and Aux Sable; and
• the absence in 2024 of both a negative provision adjustment of $124 million related to a litigation matter and an impairment loss of $82 million related to certain Offshore equity investments, partially offset by
• an asset impairment loss of $137 million related to the Big Sandy Pipeline;
• a non-cash, net unrealized loss of $3 million in 2024, compared with a net unrealized gain of $32 million in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage commodity price risk;
• a non-cash revaluation loss of $33 million to the gas inventory at Aitken Creek; and
• a loss of $29 million as a result of the contribution of our 100% interest in the Rio Bravo Pipeline project to the Whistler Parent JV.

After taking into consideration the factors above, we saw a $384 million increase, primarily explained by the following significant business factors:

• favorable contracting and lower operating costs on our US Gas Transmission assets;
• contributions from the acquisitions of Tres Palacios in the second quarter of 2023, Aitken Creek in the fourth quarter of 2023, Tomorrow RNG in the first quarter of 2024 and Whistler Parent JV in the second quarter of 2024; and
• the favorable effect of translating US dollar EBITDA at a higher average exchange rate in 2024, compared to the same period in 2023, partially offset by
• lower contributions from Alliance Pipeline and Aux Sable due to the sale of our interests in these investments in April 2024.

GAS DISTRIBUTION AND STORAGE

Year ended December 31, 2024 compared with year ended December 31, 2023

EBITDA was positively impacted by $281 million due to the absence in 2024 of an impairment of $281 million recognized to certain capital projects, capital costs and pension balances in the fourth quarter of 2023 as a result of the OEB's Phase 1 Decision.

After taking into consideration the factors above, the remaining $996 million increase is primarily explained by contributions from Enbridge Gas Ohio, Enbridge Gas Utah and Wexpro, and Enbridge Gas North Carolina since their acquisitions in 2024. In addition, the increase is also explained by:

• higher distribution charges resulting from increases in customer base and higher demand in the contract market at Enbridge Gas Ontario, partially offset by
• warmer than normal weather in 2024, when compared with the normal weather forecast embedded in rates, which negatively impacted Enbridge Gas Ontario 2024 EBITDA by approximately $58 million period over period.

RENEWABLE POWER GENERATION

Year ended December 31, 2024 compared with year ended December 31, 2023

EBITDA was positively impacted by $295 million due to certain infrequent or non-operating factors, primarily explained by:

• the absence in 2024 of an impairment loss of $261 million to Chapman Ranch wind facilities;
• a non-cash, net unrealized loss of $13 million in 2024, compared with a net unrealized loss of $72 million in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks; and
• a gain on sale of $29 million related to disposition of our interest in NRGreen, partially offset by
• an impairment loss of $55 million related to certain assets.

After taking into consideration the positive factors above, the remaining $289 million increase is primarily explained by the following significant business factors:

• contributions from our investment in Fox Squirrel Solar as a result of the generation of investment tax credits;
• higher contribution from the Hohe See and Albatros Offshore Wind Facilities as a result of the November 2023 acquisition of an additional 24.45% interest in these facilities; and
• strong wind resources at European offshore wind facilities.

ELIMINATIONS AND OTHER

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. Eliminations and Other also includes our natural gas and power marketing businesses and the impact of new business development activities and corporate investments.

Year ended December 31, 2024 compared with year ended December 31, 2023

EBITDA was negatively impacted by $3,098 billion due to certain infrequent or non-operating factors, primarily explained by:

• a non-cash, net unrealized loss of $2.2 billion in 2024, compared with a net unrealized gain of $688 million in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks;
• severance costs of $105 million as a result of a workforce reduction in February 2024;
• $137 million of integration and transaction costs incurred related to the Acquisitions in 2024, as compared to $31 million of transaction costs in 2023; and
• a non-cash, net unrealized loss of $15 million in 2024, compared with a net unrealized gain of $35 million in 2023, reflecting changes in the mark-to-market value of equity fund investments held by our wholly-owned captive insurance subsidiaries.

After taking into consideration the non-operating factors above, we saw a $278 million increase in EBITDA that is primarily explained by:

• higher investment income from the pre-funding of the Acquisitions and from our wholly-owned captive insurance subsidiaries; and
• timing of certain operating and administrative cost recoveries from the business units, partially offset by
• higher realized foreign exchange loss on hedge settlements in 2024.

GROWTH PROJECTS - COMMERCIALLY SECURED PROJECTS

The following table summarizes the status of our material commercially secured projects, organized by business segment:

1These amounts are estimates and are subject to upward or downward adjustment based on various factors. Where appropriate, the amounts reflect our share of joint venture projects.

2Expenditures to date and status of the project are determined as at December 31, 2024.

3Includes the US$37 million Gator Express Project placed into service in August 2023. Total estimated capital cost consists of the reversal and expansion of Texas Eastern's Line 40.

4Our equity contribution is approximately US$0.9 billion, with the remainder financed through non-recourse project level debt. Capital cost estimates will be updated in 2025, at which point Enbridge's preferred return will be set.

5Previously approved PSNC projects that were acquired by Enbridge through the Acquisitions.

6Includes approved capital costs for the second phase of the project which involves installation of additional compression to add capacity and is expected to go into service in 2028.

7Our equity contribution is approximately $0.3 billion, with the remainder financed through non-recourse project level debt.

Risks related to the development and completion of growth projects are described under Part I. Item 1A. Risk Factors.

The following commercially secured growth projects are currently in various stages of construction:

GAS TRANSMISSION

• Texas Eastern Venice Extension Project – A reversal and expansion of Texas Eastern’s Line 40 from its existing New Roads compressor station to a new delivery point with the proposed Gator Express pipeline just south of Texas Eastern’s Larose compressor station. The project is expected to deliver 1.5 bcf/d of natural gas to Venture Global Plaquemines LNG, LLC’s LNG export facility located in Plaquemines Parish, Louisiana and is underpinned by long-term take or pay contracts.
• Texas Eastern Modernization – This program is the modernization of compression facilities in Pennsylvania and New Jersey to increase safety and reliability and reduce associated greenhouse gas emissions at multiple sites on our Texas Eastern system. The program is expected to be completed in stages over a period of years beginning in 2024.
• T-North Expansion (Aspen Point) – An expansion of Westcoast Energy Inc.'s (Westcoast) British Columbia (BC) Pipeline in northern BC that includes pipeline looping, additional compressor units and other ancillary station modifications to support 535 million cubic feet per day (mmcf/d) of additional capacity. The expansion is to serve growing regional demand for natural gas and potential west coast LNG exports and will be underpinned by a cost-of-service commercial model with a target in-service date of 2026. T-North Expansion received regulatory approval from the CER in December 2024.
• Tennessee Ridgeline Expansion – The Tennessee Ridgeline Expansion project is an expansion of the East Tennessee Natural Gas (ETNG) system that will provide additional natural gas for the Tennessee Valley Authority (TVA) to support the replacement of an existing coal-fired power plant as TVA continues to transition its power generation mix towards lower-carbon fuels. The proposed scope includes the installation of approximately 125 miles of 30-inch pipeline looping, one electric-powered compressor station, and an 8-megawatt behind-the-meter solar array.
• Woodfibre LNG Project – Construction of liquefaction and floating storage facilities in Squamish, BC, and an expansion of the BC Pipeline System. Construction of the facilities is executed by our partner; Enbridge holds a non-controlling interest in this project. The project is expected to be placed into service in 2027.
• T-South Expansion (Sunrise) – An expansion of Westcoast's BC Pipeline's T-South section that includes pipeline looping, additional compressor units and other ancillary station modifications to support 300 mmcf/d of additional capacity. The expansion is driven primarily by an anticipated shortfall in capacity to deliver gas to the BC Lower Mainland and US Pacific Northwest markets following the commencement of deliveries to the Woodfibre LNG project, which is expected to come into service in 2027. The project is underpinned by a cost-of-service commercial model and is expected to be placed in service in 2028. We filed the regulatory application with the CER in May 2024.
• Canyon System Pipelines – The project includes the construction of two new offshore pipelines in the US Gulf Coast to deliver natural gas and crude oil from BP Exploration & Production Company's Kaskida offshore project. The development includes a new 24/26-inch oil pipeline which will connect to Shell Pipeline Company LP's Green Canyon 19 Platform, and a 12-inch gas pipeline connecting to Enbridge's Magnolia Gas Gathering System.
• Moriah Energy Center – Moriah Energy Center is an LNG facility that is under construction in Person County, North Carolina with 2 bcf storage capacity. The facility is required to ensure system reliability and address supply constraints due to customer growth and will be designed with trucking capabilities to support other LNG facilities. The construction started in first quarter of 2024 and is expected to achieve completion in 2027.
• T-15 Reliability Project – The T-15 Reliability Project includes the construction of 45 miles of transmission pipe, a compressor station and associated metering and regulation facilities in Rockingham, Caswell, and Person counties in North Carolina. The project is expected to start construction in 2026 and to achieve two-phased project completion in 2027 and 2028.

RENEWABLE POWER GENERATION

• Fox Squirrel Solar – Fox Squirrel Solar is a fully contracted, ground-mounted solar facility in Ohio with expected installed capacity of approximately 577 megawatts (MW). All three phases of the project are currently in service. Project revenues are underpinned by a 20-year fixed price power purchase agreement (PPA).
• Sequoia Solar Project – Sequoia Solar Project is an 815-megawatt solar farm located approximately 150 miles west of Dallas, Texas. The two-phased project is expected to achieve project completion in 2025 and 2026. Project revenues are underpinned by long-term fixed price PPAs.
• Calvados Offshore Wind Project – Calvados is an offshore wind project located off the northwest coast of France that is expected to generate approximately 448 MW. Project revenues are underpinned by a 20-year fixed price PPA.

OTHER ANNOUNCED PROJECTS UNDER DEVELOPMENT

The following project has been announced by us, but has not yet met our criteria to be classified as commercially secured:

RENEWABLE POWER GENERATION

Seven Stars Energy Project

On June 24, 2024, Enbridge and Six Nations Energy Development LP, a newly-created consortium of Cowessess, George Gordon, Kahkewistahaw, Pasqua and White Bear First Nations, as well as Métis Nation-Saskatchewan, announced plans to advance development of a new wind energy project southeast of Weyburn, Saskatchewan. The Seven Stars Energy Project (the Project) is expected to produce 200 MW of wind power. It will be developed, constructed and operated by Enbridge.

Financial participation of the partners is expected to be supported, in part, by loan guarantees of up to $100 million from the Saskatchewan Indigenous Investment Finance Corporation. Our Indigenous partners have an opportunity to acquire equity ownership of at least 30% in the Project.

The Project is targeted to be operational in 2027, subject to finalizing commercial agreements, securing the necessary environmental and regulatory approvals, and meeting investment criteria.

We also have a portfolio of additional projects under development that have not yet progressed to the point of commercial securement.

LIQUIDITY AND CAPITAL RESOURCES

The maintenance of financial strength and flexibility is fundamental to our growth strategy, particularly in light of the significant number and size of capital projects and acquisitions currently secured or under development. Access to timely funding from capital markets could be limited by factors outside our control including, but not limited to, financial market volatility resulting from economic and political events both inside and outside North America. To mitigate such risks, we actively manage financial plans and strategies to ensure we maintain sufficient liquidity to meet routine operating and future capital requirements.

In the near term, we generally expect to utilize cash from operations together with commercial paper issuance and/or credit facility draws and the proceeds of capital market offerings to fund liabilities as they become due, finance capital expenditures and acquisitions, fund debt retirements and pay common and preference share dividends. We target maintaining sufficient liquidity through the use of committed credit facilities with a diversified group of banks and financial institutions to enable us to fund all anticipated requirements for approximately one year without accessing the capital markets.

Material contractual obligations arising in the normal course of business primarily consist of long-term contracts, annual debt maturities and related interest obligations, rights-of-way and leases. See Part II. Item 8. Financial Statements and Supplementary Data - Note 17 - Debt and Note 26 - Leases for amounts outstanding at December 31, 2024, related to debt and leases, respectively.

Long-term contracts are contracts that we have signed for the purchase of services, pipe and other materials totaling $10.8 billion which are expected to be paid over the next five years. Remaining long-term contracts primarily consist of the following purchase obligations: firm capacity payments for natural gas and crude oil transportation and storage contracts, natural gas purchase commitments, service and product purchase obligations and power commitments.

Our financing plan is regularly updated to reflect evolving capital requirements and financial market conditions and identifies a variety of potential sources of debt and equity funding alternatives.

CAPITAL MARKET ACCESS

We ensure ready access to capital markets, subject to market conditions, through maintenance of shelf prospectuses that allow for issuance of long-term debt, equity and other forms of long-term capital when market conditions are attractive. In accordance with our funding plan, we completed the following long-term debt issuances totaling US$5.7 billion and $1.8 billion in 2024:

(in millions of Canadian dollars, unless stated otherwise)

82

Credit Facilities, Ratings and Liquidity

To ensure ongoing liquidity and to mitigate the risk of capital market disruption, we maintain ready access to funds through committed bank credit facilities and actively manage our bank funding sources to optimize pricing and other terms. The following table provides details of our committed credit facilities, inclusive of term loans, at December 31, 2024:

1Maturity date is inclusive of the one-year term out option for certain credit facilities.

2Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.

In March 2024, we entered into a delayed-draw term loan facility in support of sustainable retrofit projects for large buildings using decarbonization solutions for $200 million which matures in March 2049.

In June 2024, we entered into a five-year, non-revolving term loan facility of US$250 million which matures in June 2029.

In July 2024, we renewed approximately $8.8 billion of our 364-day extendible credit facilities, extending the maturity dates to July 2026, which includes a one-year term out provision from July 2025. We also renewed approximately $7.8 billion of our five-year credit facilities, extending the maturity dates to July 2029. Further, we extended the maturity dates of our three-year credit facilities to July 2027.

In July 2024, Enbridge Gas Ontario extended the maturity date of its 364-day extendible credit facility to July 2026, which includes a one-year term out provision from July 2025.

In July 2024, Enbridge Pipelines Inc. extended the maturity date of its 364-day extendible credit facility to July 2026, which includes a one-year term out provision from July 2025.

In January 2024 and October 2024, we entered into new letters of credit facilities and increased our letter of credit facilities by $146 million and $200 million, respectively.

In addition to the committed credit facilities noted above, we maintain $1.4 billion of uncommitted demand letter of credit facilities, of which $931 million was unutilized as at December 31, 2024. As at December 31, 2023, we had $1.1 billion of uncommitted demand letter of credit facilities, of which $572 million was unutilized.

As at December 31, 2024, our net available liquidity totaled $14.4 billion (2023 - $23.0 billion), consisting of available credit facilities of $12.6 billion (2023 - $17.1 billion) and unrestricted Cash and cash equivalents of $1.8 billion (2023 - $5.9 billion) as reported in the Consolidated Statements of Financial Position.

Our credit facility agreements and term debt indentures include standard events of default and covenant provisions, whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at December 31, 2024, we were in compliance with all debt covenants and expect to continue to comply with such covenants.

Cash flow growth, ready access to liquidity from diversified sources and a stable business model have enabled us to manage our credit profile. We actively monitor and manage key financial metrics with the objective of sustaining investment grade credit ratings from the major credit rating agencies and ongoing access to bank funding and term debt capital on attractive terms. Key measures of financial strength that are closely managed include the ability to service debt obligations from operating cash flow and the ratio of debt to EBITDA.

Credit Ratings Action

On March 29, 2024, Moody's Investor Service (Moody's) downgraded Enbridge's credit ratings for our senior unsecured debt ratings to Baa2 from Baa1. Moody's also downgraded the credit ratings of our subsidiaries: Enbridge Energy Partners, L.P. (EEP), Enbridge Energy Limited Partnership, Spectra Energy Partners, LP (SEP) and Texas Eastern. The outlooks of all five entities were changed to stable from negative.

In June 2024, Standard & Poor's Global revised Enbridge's and EEP's outlooks from negative to stable.

On June 28, 2024, Morningstar DBRS (DBRS) upgraded Enbridge's credit ratings for our senior unsecured debt ratings to A (low) from BBB (high). DBRS also updated the credit rating of EEP to A (low) with a stable trend.

There are no material restrictions on our cash. Total Restricted cash of $92 million, as reported in the Consolidated Statements of Financial Position, primarily includes cash collateral and future pipeline abandonment costs collected and held in trust. Cash and cash equivalents held by certain subsidiaries may not be readily accessible for alternative use by us.

Excluding current maturities of long-term debt, as at December 31, 2024 and 2023, we had negative and positive working capital positions of $2.9 billion and $3.0 billion, respectively. In 2024, the major contributing factor to the negative working capital position was the current liabilities associated with our growth capital program compared to a positive working capital position in 2023, due to the increase in cash associated with pre-funding of the Acquisitions.

SOURCES AND USES OF CASH

Significant sources and uses of cash for the years ended December 31, 2024 and 2023 are summarized below:

Operating Activities

Typically, the primary factors impacting cash provided by operating activities year-over-year include changes in our operating assets and liabilities in the normal course due to various factors, including the impact of fluctuations in commodity prices and activity levels on working capital within our business segments, the timing of tax payments, as well as timing of cash receipts and payments generally. Refer to Part II. Item 8. Financial Statements and Supplementary Data - Note 28. Changes in Operating Assets and Liabilities. Cash provided by operating activities is also impacted by changes in earnings and certain infrequent or other non-operating factors, as discussed under Results of Operations, as well as Distributions from equity investments.

Investing Activities

Cash used in investing activities primarily relates to capital expenditures to execute our capital program, which is further described in Growth Projects - Commercially Secured Projects. The timing of project approval, construction and in-service dates impacts the timing of cash requirements. Cash used in investing activities is also impacted by acquisitions and dispositions as discussed under Recent Developments, and changes in contributions to, and distributions from, our equity investments.

A summary of cash additions to property, plant and equipment for the years ended December 31, 2024, 2023 and 2022 is set out below:

2024

The increase in cash used in investing activities primarily resulted from the following factors:

• the acquisitions of EOG, Questar, PSNC, and Tomorrow RNG in 2024;
• increased capital expenditures from the acquisitions of EOG, Questar, and PSNC and from growth projects in our Gas Transmission segment; and
• the acquisition of an equity interest in the Whistler Parent JV and Delaware Basin Residue, LLC and contributions to our Fox Squirrel Solar investment in 2024.

The factors above were partially offset by proceeds received from the dispositions of our interests in the Alliance Pipeline, Aux Sable, and NRGreen in 2024.

2023

The increase in cash used in investing activities primarily resulted from the following factors:

• the absence in 2023 of the proceeds received from the completion of a joint venture merger transaction for DCP Midstream, LLC in August 2022; and
• higher cash outflows related to acquisitions in 2023 when compared to 2022.

The factors above were partially offset by higher distributions in 2023 mainly related to our investment in NEXUS Gas Transmission, LLC.

Financing Activities

Cash provided by financing activities primarily relates to issuances and repayments of external debt, as well as transactions with our common and preference shareholders relating to dividends, share issuances, share redemptions and common share repurchases under our NCIB. Cash provided by financing activities is also impacted by changes in distributions to, and contributions from, noncontrolling interests.

The increase in cash provided by financing activities primarily resulted from the following factors:

• net commercial paper and credit facility draws in 2024 when compared to net repayments during the same period in 2023;
• the ATM program, resulting in the issuance of 51,298,629 common shares for aggregate net proceeds of $2.5 billion in 2024; and
• lower net repayments of short-term borrowings in 2024 when compared to the same period in 2023.

The factors above were partially offset by:

• higher long-term debt repayments and lower long-term debt issuances in 2024 when compared to the same period in 2023;
• the absence in 2024 of the public offering of common shares, which closed on September 8, 2023 for gross proceeds of $4.6 billion; and
• increased common share dividend payments primarily due to the increase in our common share dividend rate and an increase in the number of common shares outstanding.

2023

The decrease in cash provided by financing activities primarily resulted from the following factors:

• higher long-term debt issuances in 2023 when compared to the same period in 2022;
• our public offering of common shares, which closed on September 8, 2023, resulting in the issuance of 102,913,500 common shares at a price of $44.70 per share for gross proceeds of $4.6 billion, which is intended to finance a portion of the aggregate cash consideration payable for the Acquisitions; and
• the absence in 2023 of the redemption of Preference Shares, Series 17 and Series J in the first and second quarters of 2022, respectively.

The factors above were partially offset by:

• higher net commercial paper and credit facility repayments in 2023 when compared to the same period in 2022;
• net repayments of short-term borrowings in 2023 when compared to net issuances in 2022;
• the absence in 2023 of proceeds received from the sale of a non-operating interest in seven pipelines from our Regional Oil Sands System in October 2022;
• higher long-term debt repayments in 2023 when compared to the same period in 2022; and
• increased common share dividend payments primarily due to the increase in our common share dividend rate and an increase in the number of common shares outstanding.

OFF-BALANCE SHEET ARRANGEMENTS

We enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties and can include financial guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. Please see Part II. Item 8. Financial Statements and Supplementary Data - Note 31 - Guarantees for further discussion of guarantee arrangements.

We do not have material off-balance sheet financing entities or structures, except for guarantee arrangements and financings entered into for our equity investments. For additional information on these commitments, please refer to Part II. Item 8. Financial Statements and Supplementary Data - Note 30 - Commitments and Contingencies and Note 12 - Variable Interest Entities.

We do not have material off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

OUTSTANDING PREFERENCE SHARES

Characteristics of our outstanding preference shares are as follows:

1The holder is entitled to receive a fixed cumulative quarterly preferential dividend, as declared by the Board of Directors. With the exception of Preference Shares, Series A, such fixed dividend rate resets every five years beginning on the initial Redemption and Conversion Option Date. Preference Shares, Series G, Series I and Series 4 contain a feature where the dividend rate resets on a quarterly basis. These Dividend Rates are presented in the table above on an annualized basis using the most recent quarterly dividend rate reset. The Preference Shares, Series 19 contain a feature where the fixed dividend rate, when reset every five years, will not be less than 4.90%. No other series of preference shares has this feature.

2Preference Shares, Series A may be redeemed any time at our option. For all other series of preference shares, we may at our option, redeem all or a portion of the outstanding preference shares for the Per Share Base Redemption Value plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter.

3The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on a one-for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an ascribed issue price equal to the Per Share Base Redemption Value.

4With the exception of Preference Shares, Series A, after the Redemption and Conversion Option Date, holders may elect to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/number of days in year) x three month Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q), 2.5% (Series S), 2.4% (Series 4), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7% (Series 16), or 3.2% (Series 20); or US$25 x (number of days in quarter/number of days in year) x three month US Government treasury bill rate + 3.2% (Series M), 3.1% (Series 2), or 2.8% (Series 6).

5The quarterly dividend per share paid on Preference Shares, Series G was decreased to $0.37911 from $0.43014 on December 1, 2024 due to reset on a quarterly basis.

6The quarterly dividend per share paid on Preference Shares, Series I was decreased to $0.35507 from $0.40589 on December 1, 2024 due to reset on a quarterly basis.

7The quarterly dividend per share paid on Preference Shares, Series P was increased to $0.36988 from $0.27369 on March 1, 2024 due to reset of the annual dividend on March 1, 2024.

8The quarterly dividend per share paid on Preference Shares, Series R was increased to $0.39463 from $0.25456 on June 1, 2024 due to reset of the annual dividend on June 1, 2024.

9The quarterly dividend per share paid on Preference Shares, Series 3 was increased to $0.33050 from $0.23356 on September 1, 2024 due to reset of the annual dividend on September 1, 2024.

10 On September 1, 2024, 1,502,775 of the outstanding Preference Shares, Series 3 were converted into Preference Shares, Series 4. The quarterly dividend per share paid on Preference Shares, Series 4 was decreased to $0.37110 from $0.42206 on December 1, 2024 due to reset on a quarterly basis following the date of issuance.

11The quarterly dividend per share paid on Preference Shares, Series 5 was increased to US$0.41769 from US$0.33596 on March 1, 2024 due to reset of the annual dividend on March 1, 2024.

12 The quarterly dividend per share paid on Preference Shares, Series 7 was increased to $0.37425 from $0.27806 on March 1, 2024 due to reset of the annual dividend on March 1, 2024.

13 The quarterly dividend per share paid on Preference Shares, Series 9 was increased to $0.35450 from $0.25606 on December 1, 2024 due to reset of the annual dividend on December 1, 2024.

DIVIDENDS

We have paid common share dividends in every year since we became a publicly traded company in 1953. In December 2024, we announced a 3.0% increase in our quarterly dividend to $0.9425 per common share, or $3.77 annualized, effective with the dividend payable on March 1, 2025, thereby declaring a dividend increase for 30 straight years.

For the years ended December 31, 2024 and 2023, total dividends paid in cash were $7.9 billion and $7.3 billion, respectively, and reflected in Cash Flows from Financing Activities in the Consolidated Statements of Cash Flows.

On December 2, 2024, our Board of Directors declared the following quarterly dividends. All dividends are payable on March 1, 2025 to shareholders of record on February 14, 2025.

1The quarterly dividend per common share was increased 3.0% to $0.9425 from $0.9150, effective March 1, 2025.

2The quarterly dividend per share paid on Preference Shares, Series G was decreased to $0.37911 from $0.43014 on December 1, 2024 due to reset on a quarterly basis.

3The quarterly dividend per share paid on Preference Shares, Series I was decreased to $0.35507 from $0.40589 on December 1, 2024 due to reset on a quarterly basis.

4The quarterly dividend per share paid on Preference Shares, Series 4 was decreased to $0.37110 from $0.42206 on December 1, 2024 due to reset on a quarterly basis following the date of issuance.

5The quarterly dividend per share paid on Preference Shares, Series 9 was increased to $0.35450 from $0.25606 on December 1, 2024 due to reset of the annual dividend on December 1, 2024.

SUMMARIZED FINANCIAL INFORMATION

On January 22, 2019, Enbridge entered into supplemental indentures with its wholly-owned subsidiaries, SEP and EEP (the Partnerships), pursuant to which Enbridge fully and unconditionally guaranteed, on a senior unsecured basis, the payment obligations of the Partnerships with respect to the outstanding series of notes issued under the respective indentures of the Partnerships. Concurrently, the Partnerships entered into a subsidiary guarantee agreement pursuant to which they fully and unconditionally guaranteed, on a senior unsecured basis, the outstanding series of senior notes of Enbridge. The Partnerships have also entered into supplemental indentures with Enbridge pursuant to which the Partnerships have issued full and unconditional guarantees, on a senior unsecured basis, of senior notes issued by Enbridge subsequent to January 22, 2019. As a result of the guarantees, holders of any of the outstanding guaranteed notes of the Partnerships (the Guaranteed Partnership Notes) are in the same position with respect to the net assets, income and cash flows of Enbridge as holders of Enbridge's outstanding guaranteed notes (the Guaranteed Enbridge Notes), and vice versa. Other than the Partnerships, Enbridge subsidiaries (including the subsidiaries of the Partnerships, collectively, the Subsidiary Non-Guarantors), are not parties to the subsidiary guarantee agreement and have not otherwise guaranteed any of Enbridge's outstanding series of senior notes.

Consenting SEP notes and EEP notes under Guarantee

1As at December 31, 2024, the aggregate outstanding principal amount of SEP notes was approximately US$2.2 billion.

2As at December 31, 2024, the aggregate outstanding principal amount of EEP notes was approximately US$2.4 billion.

Enbridge Notes under Guarantees

1As at December 31, 2024, the aggregate outstanding principal amount of the Enbridge US dollar denominated notes was approximately US$17.0 billion.

2As at December 31, 2024, the aggregate outstanding principal amount of the Enbridge Canadian dollar denominated notes was approximately $12.3 billion.

Rule 3-10 of the US Securities and Exchange Commission's (SEC) Regulation S-X provides an exemption from the reporting requirements of the Securities Exchange Act of 1934, as amended (the Exchange Act) for fully consolidated subsidiary issuers of guaranteed securities and subsidiary guarantors and allows for summarized financial information in lieu of filing separate financial statements for each of the Partnerships.

The following Summarized Combined Statement of Earnings and the Summarized Combined Statements of Financial Position combines the balances of EEP, SEP and Enbridge.

Summarized Combined Statement of Earnings

91

Summarized Combined Statements of Financial Position

The Guaranteed Enbridge Notes and the Guaranteed Partnership Notes are structurally subordinated to the indebtedness of the Subsidiary Non-Guarantors in respect of the assets of those Subsidiary Non-Guarantors.

Under US bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee can be voided, or claims may be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time the indebtedness evidenced by its guarantee or, in some states, when payments become due under the guarantee:

• received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee and was insolvent or rendered insolvent by reason of such incurrence;
• was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or
• intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they mature.

The guarantees of the Guaranteed Enbridge Notes contain provisions to limit the maximum amount of liability that the Partnerships could incur without causing the incurrence of obligations under the guarantee to be a fraudulent conveyance or fraudulent transfer under US federal or state law.

Each of the Partnerships is entitled to a right of contribution from the other Partnership for 50% of all payments, damages and expenses incurred by that Partnership in discharging its obligations under the guarantees for the Guaranteed Enbridge Notes.

Under the terms of the guarantee agreement and applicable supplemental indentures, the guarantees of either of the Partnerships of any Guaranteed Enbridge Notes will be unconditionally released and discharged automatically upon the occurrence of any of the following events:

• any direct or indirect sale, exchange or transfer, whether by way of merger, sale or transfer of equity interests or otherwise, to any person that is not an affiliate of Enbridge, of any of Enbridge’s direct or indirect limited partnership of other equity interests in that Partnership as a result of which the Partnership ceases to be a consolidated subsidiary of Enbridge;
• the merger of that Partnership into Enbridge or the other Partnership or the liquidation and dissolution of that Partnership;
• the repayment in full or discharge or defeasance of those Guaranteed Enbridge Notes, as contemplated by the applicable indenture or guarantee agreement;
• with respect to EEP, the repayment in full or discharge or defeasance of each of the consenting EEP notes listed above;
• with respect to SEP, the repayment in full or discharge or defeasance of each of the consenting SEP notes listed above; or
• with respect to any series of Guaranteed Enbridge Notes, with the consent of holders of at least a majority of the outstanding principal amount of that series of Guaranteed Enbridge Notes.

The guarantee obligations of Enbridge will terminate with respect to any series of Guaranteed Partnership Notes if that series is discharged or defeased.

The Partnerships also guarantee the obligations of Enbridge under its existing credit facilities.

LEGAL AND OTHER UPDATES

LINE 5 EASEMENT (BAD RIVER BAND)

On July 23, 2019, the Bad River Band of the Lake Superior Tribe of Chippewa Indians (the Band) filed a complaint in the US District Court for the Western District of Wisconsin (the Court) over our Line 5 pipeline and right-of-way across the Bad River Reservation (the Reservation). Only a small portion of the total easements across 12 miles of the Reservation are at issue. The Band alleges that our continued use of Line 5 to transport crude oil and related liquids across the Reservation is a public nuisance under federal and state law and that the pipeline is in trespass on certain tracts of land in which the Band possesses ownership interests. The complaint seeks an Order prohibiting us from using Line 5 to transport crude oil and related liquids across the Reservation and requiring removal of the pipeline from the Reservation. Subsequently amended versions of the complaint also seek recovery of profits-based damages based on an unjust enrichment theory. Enbridge has responded to each claim in the initial and amended complaints with an answer, defenses and counterclaims.

On August 29, 2022, the Government of Canada released a statement formally invoking the dispute settlement provisions of the 1977 Transit Pipelines Treaty in respect of this litigation, reiterating its concerns about the uninterrupted transmission of hydrocarbons through Line 5. On September 7, 2022, the Court issued a decision on cross-motions for summary judgment. The Court determined that the Band's nuisance claim raised factual issues that could not be resolved on summary judgment. The Court further determined that Enbridge is in trespass on 12 parcels on the Reservation and that the Band is entitled to some measure of profits-based damages and to an injunction, with the level of damages and scope of the injunction to be determined at trial, which occurred October 24 through November 1, 2022.

On May 9, 2023, the Band filed an Emergency Motion for Injunctive Relief asking the Court to require Enbridge to purge and shutdown Line 5 on the Reservation due to significant erosion at the Meander. Enbridge responded and a hearing was held on May 18, 2023 in front of Judge Conley who indicated that he did not find the Band had proven imminence but that his final ruling on all issues would be provided soon.

On June 26, 2023, the Court issued its Final Order ruling as follows: (1) Enbridge shall adopt and implement its 2022 Monitoring and Shutdown Plan with the Court's modifications by July 5, 2023; (2) Enbridge owes the Band $5,151,668 for past trespass on the 12 allotted parcels; (3) Enbridge must continue to pay money on a quarterly basis using the formula set in its Order as long as Line 5 operates in trespass on the 12 allotted parcels (approximately $400,000 per year); (4) Enbridge must cease operation of Line 5 on any parcel within the Band's tribal territory without a valid right of way by June 16, 2026 and thereafter arrange prompt, reasonable remediation at those sites; and (5) The Court declined to allow for the Relocation to be completed prior to having to cease operations. The Final Judgment was entered on June 29, 2023.

Enbridge filed its Notice of Appeal on June 30, 2023 and the Band filed its Notice of Cross Appeal on July 27, 2023. On December 12, 2023, the 7th Circuit requested the US to file a brief in this appeal as amicus curiae to address the effect of the Agreement Between the US and Canada Concerning Transit Pipelines, 28 U.S.T. 7449 (1977), and any other issues that the US believes to be material. Subsequently, the US filed its brief on April 8, 2024. As invited by the Court of Appeals, Enbridge and the Band filed their respective responses to the US amicus brief on April 29, 2024. We anticipate the Court of Appeals will issue a decision in early 2025.

MICHIGAN LINE 5 DUAL PIPELINES - STRAITS OF MACKINAC EASEMENT

Michigan Attorney General Lawsuit

In 2019, the Michigan Attorney General (AG) filed a complaint in the Michigan Ingham County Circuit Court (the Circuit Court) that requests the Circuit Court to declare the easement granted to Enbridge in 1953 for the operation of Line 5 in the Straits of Mackinac (the Straits) to be invalid and to prohibit continued operation of Line 5 in the Straits. On December 15, 2021, Enbridge removed the case to the US District Court in the Western District of Michigan (US District Court). The removal of the AG's case to federal court followed a November 16, 2021 ruling which held that the similar (and now dismissed) 2020 lawsuit brought by the Governor of Michigan to force Line 5's shutdown raised important federal issues that should be heard in federal court. The AG subsequently filed various motions and appeals (opposed by Enbridge) to remand the case.

On June 17, 2024, the 6th Circuit Court of Appeals (6th Circuit) overturned the US District Court’s decision and remanded the AG's lawsuit against Enbridge back to the Circuit Court. On July 15, 2024, Enbridge filed a petition for rehearing, which was denied on August 16, 2024.

Briefing by both parties was concluded on December 23, 2024.

Oral argument took place before the Circuit Court judge on January 27, 2025, on cross motions for summary disposition which have been pending for almost four years. We anticipate a decision on the motions for summary disposition in 2025.

On January 13, 2025, Enbridge filed a petition for certiorari with the US Supreme Court. The petition asks the Supreme Court to review and reverse the June 2024 decision of the 6th Circuit remanding to state court the Michigan Attorney General’s lawsuit against Enbridge seeking to shut down Line 5.

Enbridge Lawsuit

On November 24, 2020, Enbridge filed in the US District Court a Complaint for Declaratory and Injunctive Relief requesting that the US District Court enjoin the State of Michigan Officials from taking any action to prevent or impede the operation of Line 5. The Government of Canada has filed a supplemental brief reiterating that the 1977 Transit Pipelines Treaty between the US and Canada has been invoked and that the matter is of great importance to Canada. This matter remains in federal court.

In January 2022, the State of Michigan Officials filed a motion to dismiss Enbridge's Complaint and Enbridge filed a motion for summary judgment. On July 5, 2024, the US District Court issued an Order denying the Michigan officials' motion to dismiss Enbridge's Complaint, and the State of Michigan Officials filed for an immediate appeal to the 6th Circuit. On August 29, 2024, the US District Court issued an order staying the case, pending the 6th Circuit’s decision.

Briefing on the appeal concluded on December 20, 2024; oral argument is scheduled for March 18, 2025, with an expected decision in 2025.

DAKOTA ACCESS PIPELINE

We own an effective interest of 27.6% in the Bakken Pipeline System, which is inclusive of the Dakota Access Pipeline (DAPL). The Standing Rock Sioux Tribe and the Cheyenne River Sioux Tribe filed lawsuits in 2016 with the US Court for the District of Columbia (the District Court) contesting the lawfulness of the Army Corps easement for DAPL, including the adequacy of the Army Corps' environmental review and tribal consultation process. The Oglala Sioux and Yankton Sioux Tribes also filed lawsuits alleging similar claims in 2018.

On June 14, 2017, the District Court found the Army Corps' environmental review to be deficient and ordered the Army Corps to conduct further study concerning spill risks from DAPL.

On March 25, 2020, in response to amended complaints from the Tribes, the District Court found that the Army Corps' subsequent environmental review completed in August 2018 was also deficient and ordered the Army Corps to prepare an Environmental Impact Statement (EIS) to address unresolved controversy pertaining to potential spill impacts resulting from DAPL. On July 6, 2020, the District Court issued an order vacating the Army Corps' easement for DAPL and ordering that the pipeline be shut down by August 5, 2020. On that day, the US Court of Appeals for the District of Columbia Circuit stayed the District Court's July 6 order to shut down and empty the pipeline.

On January 26, 2021, the US Court of Appeals affirmed the District Court's decision, holding that the Army Corps is required to prepare an EIS and that the Army Corps' easement for DAPL is vacated. The US Supreme Court subsequently denied the request of Dakota Access, LLC to review the decision that an EIS is required. The US Court of Appeals also determined that, absent an injunction proceeding, the District Court could not order DAPL's operations to cease. While not an issue before, the US Court of Appeals also recognized that the Army Corps could consider whether to allow DAPL to continue to operate in the absence of an easement. The Army Corps earlier indicated that it did not intend to exercise its authority to bar DAPL's continued operation, notwithstanding the absence of an easement.

On September 8, 2023, the Army Corps issued its draft EIS, which assesses the impacts of DAPL under five alternative scenarios: denying the easement removing the pipeline; denying the easement and leaving the pipeline in place; granting the easement with the prior conditions (which allow for the ongoing operation, maintenance and ultimate removal of the pipeline and its related facilities); granting the easement with some new safety conditions; and rerouting the pipeline. The Army Corps did not identify a preferred alternative. The public comment period that commenced on the issuance of the draft EIS closed on December 13, 2023. The pipeline will remain operational while the environmental review process continues. The final EIS is expected to be issued in 2025.

On October 15, 2024, the Standing Rock Sioux Tribe filed a complaint in the DC District Court against the Army Corps, among others, seeking a permanent injunction prohibiting the continued operation of DAPL. The main allegations of the complaint are that the Army Corps is unlawfully permitting DAPL to continue to operate without an easement and without a determination under the National Environmental Policy Act, and that the Army Corps has failed to require that a compliant Facility Response Plan be submitted. Several of the claims are similar to those in the litigation described above. Dakota Access, LLC and 13 states have intervened in the case in support of the Army Corps and continued operation of DAPL. Dakota Access, LLC filed an answer to the complaint on December 19, 2024. On January 17, 2025, the Federal Defendants, Dakota Access LLC, and the 13 States filed motions to dismiss the Standing Rock Sioux Tribe’s complaint. Also on January 17, 2025, the Standing Rock Sioux Tribe filed a motion for partial summary judgment on its claims. We expect that these recent motions will require additional briefing in 2025.

OTHER LITIGATION

We and our subsidiaries are subject to various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our consolidated financial position or results of operations.

TAX MATTERS

We and our subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in our view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our consolidated financial statements are prepared in accordance with US GAAP, which requires management to make estimates, judgments and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. In making judgments and estimates, management relies on external information and observable conditions, where possible, supplemented by internal analysis as required. We believe our most critical accounting policies and estimates discussed below have an impact across the various segments of our business.

BUSINESS COMBINATIONS

We apply the provisions of Accounting Standards Codification 805 Business Combinations in accounting for our business acquisitions. The acquired assets and assumed liabilities are recorded at their estimated fair values as at the date of acquisition. Goodwill represents the excess of the purchase price over the fair value of net identifiable assets. While we use our best estimates and assumptions to accurately value assets acquired and liabilities assumed at the date of acquisition, as well as any contingent consideration, our estimates are inherently uncertain and subject to refinement. During the measurement period, which may be up to one year from the acquisition date, we record adjustments to the assets acquired and liabilities assumed with a corresponding offset to goodwill. Upon conclusion of the measurement period, or the final determination of values for assets acquired or liabilities assumed, whichever comes first, any subsequent adjustments are recorded in the Consolidated Statements of Earnings.

Accounting for business combinations requires significant judgment, estimates and assumptions at the acquisition date. In developing estimates of fair values at the acquisition date, we utilize a variety of factors including market data, historical and future expected cash flows, growth rates and discount rates. The subjective nature of our assumptions increases the risk associated with estimates surrounding the projected performance of the acquired entity.

GOODWILL IMPAIRMENT

Goodwill represents the excess of the purchase price over the fair value of net identifiable assets upon acquisition of a business. The carrying value of goodwill, which is not amortized, is assessed for impairment annually or more frequently if events or changes in circumstances arise that suggest the carrying value of goodwill may be impaired. We perform our annual review of the goodwill balance on April 1.

We perform our annual review for impairment at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete information is available, whether segment management regularly reviews the operating results of those components, and whether the economic and regulatory characteristics are similar. Our reporting units are Liquids Pipelines, Gas Transmission, Gas Distribution and Storage, and Renewable Power Generation.

We have the option to first assess qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment assessment. When performing a qualitative assessment, we determine the drivers of fair value for each reporting unit and evaluate whether those drivers have been positively or negatively affected by relevant events and circumstances since the last fair value assessment. Our evaluation includes, but is not limited to, the assessment of macroeconomic trends (including the impact of changes in discount rates and rate base multiple), changes to regulatory environments, capital accessibility, operating income trends (including changes to projected cash flows from operations, expected future capital expenditures and forecasted rate base), and changes to industry conditions. Based on our assessment of qualitative factors, if we determine it is more likely than not that the fair value of the reporting unit is less than its carrying amount, a quantitative goodwill impairment assessment is performed.

The quantitative goodwill impairment assessment involves determining the fair value of our reporting units and comparing those values to the carrying value of each reporting unit. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit's carrying value exceeds its fair value. This amount should not exceed the carrying amount of goodwill. The fair value of our reporting units is estimated using a discounted cash flow technique. The determination of fair value using the discounted cash flow technique requires the use of estimates and assumptions related to discount rates, projected operating income, expected future capital expenditures and working capital levels, as well as terminal value growth rates for the Liquids Pipelines, Gas Transmission, and Renewable Power Generation reporting units, and projected regulatory rate base and rate base multiple for the Gas Distribution and Storage reporting unit.

The allocation of goodwill to held-for-sale and disposed businesses is based on the relative fair value of businesses included in the relevant reporting unit.

On April 1, 2024, we performed our annual goodwill impairment assessment which consisted of a qualitative assessment for the Liquids Pipelines, Gas Transmission, Gas Distribution and Storage, and Renewable Power Generation reporting units and did not identify impairment indicators. No indicators of goodwill impairment were identified during the remainder of 2024.

ASSET IMPAIRMENT

We evaluate the recoverability of our property, plant and equipment when events or circumstances, such as economic obsolescence, business climate, legal or regulatory changes, or other factors, indicate that we may not recover the carrying amount of our assets. We regularly monitor our businesses, the market and business environments to identify indicators that could suggest an asset may not be recoverable. If it is determined that the carrying value of an asset exceeds its expected undiscounted cash flows, we will assess the fair value of the asset. An impairment loss is recognized when the carrying amount of the asset exceeds its fair value.

With respect to equity method investments, we assess at each balance sheet date whether there is objective evidence that the investment is impaired by completing a qualitative or quantitative analysis of factors impacting the investment. If there is objective evidence of impairment, we determine whether the decline below carrying value is other-than-temporary. If the decline is determined to be other-than-temporary, an impairment charge is recorded in earnings with an offsetting reduction to the carrying value of the investment.

Asset fair value is determined using present value techniques. The determination of fair value using present value techniques requires the use of projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes to these projections and assumptions could result in revisions to the evaluation of the recoverability of the asset and the recognition of an impairment loss in the Consolidated Statements of Earnings.

ASSETS HELD FOR SALE

We classify assets as held for sale when management commits to a formal plan to actively market an asset or a group of assets and when management believes it is probable the sale of the assets will occur within one year. We measure assets classified as held for sale at the lower of their carrying value and their estimated fair value less costs to sell.

REGULATORY ACCOUNTING

Certain parts of our businesses are subject to regulation by various authorities including, but not limited to, the CER, the FERC, the Alberta Energy Regulator, the BC Energy Regulator, the OEB, the Québec Régie de l’énergie, the Ohio Commission, the North Carolina Commission, the Utah Commission, the Wyoming Commission, and the Idaho Commission. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking, and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under US GAAP for non-rate-regulated entities.

Key determinants in the ratemaking process are:

• costs of providing service, including operating costs, capital invested, depreciation expense and taxes;
• allowed rate of return, including the equity component of the capital structure and related income taxes;
• interest costs on the debt component of the capital structure; and
• contract and volume throughput assumptions.

The allowed rate of return is determined in accordance with the applicable regulatory model and may impact our profitability. The rates for a number of our projects are based on a cost-of-service recovery model that follows the regulators' authoritative guidance. Under the cost-of-service tolling methodology, we calculate tolls based on forecast volumes and cost. A difference between forecast and actual results causes an over- or under-recovery in any given year.

Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates, amounts collected from customers in advance of costs being incurred, or to be paid to cover future abandonment costs and for future removal and site restoration costs as approved by the regulator. If there are changes in our assessment of the probability of recovery for a regulatory asset, we reduce its carrying amount to the balance that we expect to recover from customers in future periods through rates. If a regulator later excludes from allowable costs all or a part of costs that were capitalized as a regulatory asset, we reduce the carrying amount of the asset by the excluded amounts.

The recognition of regulatory assets and liabilities is based on the actions, or expected future actions, of the regulator. To the extent that the regulator's actions differ from our expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate regulation, we would generally not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned. A regulatory asset or liability is recognized in respect of deferred income taxes when it is expected the amounts will be recovered or settled through future regulator-approved rates.

During the fourth quarter of 2023, Southern Lights Pipeline completed an open season to negotiate new transportation service agreements. We did not renew the agreements under a cost-of-service toll methodology, therefore Southern Lights Pipeline was no longer subject to rate-regulated accounting. As a result, the related regulatory liabilities, regulatory tax assets and associated regulatory deferred tax liabilities were derecognized in 2023.

As at December 31, 2024 and 2023, our regulatory assets totaled $7.6 billion and $5.7 billion, respectively, and regulatory liabilities totaled $6.7 billion and $3.8 billion, respectively.

DEPRECIATION

Depreciation of property, plant and equipment, our largest asset with a net book value at December 31, 2024 and 2023, of $131.1 billion and $104.6 billion, respectively, is charged in accordance with two primary methods. For distinct assets, depreciation is generally provided on a straight-line basis over the estimated useful life of the asset commencing when it is placed in service. For largely homogeneous groups of assets with comparable useful lives, the pool method of accounting is followed whereby similar assets are grouped and depreciated as a pool. When group assets are retired or otherwise disposed of, gains and losses are generally not reflected in earnings but are booked as an adjustment to accumulated depreciation.

When it is determined that the estimated service life of an asset no longer reflects the expected remaining period of benefit, prospective changes are made to the estimated service life. Estimates of useful lives are based on third-party engineering studies, experience and/or industry practice. There are a number of assumptions inherent in estimating the service lives of our assets including the level of development, exploration, drilling, reserves and production of crude oil and natural gas in the supply areas served by our pipelines, as well as the demand for crude oil and natural gas and the integrity of our systems. Changes in these assumptions could result in adjustments to the estimated service lives, which could result in material changes to depreciation expense in future periods in any of our business segments. For certain rate-regulated operations, depreciation rates are approved by the regulator and the regulator may require periodic studies or technical updates on useful lives which may change depreciation rates.

The successful efforts method of accounting is used for cost-of-service reserves developed and produced by Wexpro for gas utility affiliate, Questar. Cost-of-service reserves are properties for which the operations and return on investment are subject to the Wexpro Agreements. Under the successful efforts method, Wexpro capitalizes the costs of acquiring leaseholds, drilling development wells, drilling successful exploratory wells, and purchasing related support equipment and facilities. Geological and geophysical studies are expensed as incurred. Capitalized costs of development wells and leaseholds are amortized on a field-by-field basis using the unit-of-production method and the estimated proved developed or total proved natural gas and crude oil reserves.

PENSION AND OTHER POSTRETIREMENT BENEFITS

We use certain assumptions relating to the calculation of defined benefit pension and other postretirement liabilities and net periodic benefit costs. These assumptions comprise management's best estimates of expected return on plan assets, future salary levels, other cost escalations, retirement ages of employees, and other actuarial factors including discount rates and mortality. We determine discount rates by reference to rates of high-quality long-term corporate bonds with maturities that approximate the timing of future payments anticipated to be made under each of the respective plans. The expected return on plan assets is determined using market-related values and assumptions on the asset mix consistent with the investment policy relating to the assets and their projected returns. The assumptions are reviewed annually by our independent actuaries. Actual results that differ from results based on assumptions are amortized over future periods and, therefore, could materially affect the expense recognized and the recorded obligation in future periods.

The following sensitivity analysis identifies the impact on the consolidated financial statements for the year ended December 31, 2024 of a 0.5% change in key pension and other postretirement benefits (OPEB) obligation assumptions:

CONTINGENT LIABILITIES

Provisions for claims filed against us are determined on a case-by-case basis. Case estimates are reviewed on a regular basis and are updated as new information is received. The process of evaluating claims involves the use of estimates and a high degree of management judgment. Claims outstanding, the final determination of which could have a material impact on our financial results and certain subsidiaries and investments, are detailed in Legal and Other Updates and Part II. Item 8. Financial Statements and Supplementary Data - Note 30. Commitments and Contingencies. In addition, any unasserted claims that later may become evident could have a material impact on our financial results and certain subsidiaries and investments.

ASSET RETIREMENT OBLIGATIONS

Asset retirement obligations (ARO) associated with the retirement of long-lived assets are measured at fair value and recognized as Other current liabilities or Other long-term liabilities in the period in which they can be reasonably determined. Fair value approximates the cost a third party would charge to perform the tasks necessary to retire such assets and is recognized at the present value of expected future cash flows. The discount rates used to estimate the present value of expected future cash flows for the year ended December 31, 2024 and 2023 ranged from 1.5% to 9.0%. ARO is added to the carrying value of the associated asset and depreciated over the asset's useful life. The corresponding liability is accreted over time through charges to earnings and is reduced by actual costs of decommissioning and reclamation. Our estimates of retirement costs could change as a result of changes in cost estimates and regulatory requirements. Currently, for the majority of our assets, there is insufficient data or information to reasonably determine the timing of settlement for estimating the fair value of the ARO. In these cases, the fair value of ARO is considered indeterminate for accounting purposes, as there is no data or information that can be derived from past practice, industry practice or the estimated economic life of the asset.

In 2009, the CER issued a decision related to the Land Matters Consultation Initiative (LMCI), which required holders of an authorization to operate a pipeline under the CER Act to file a proposed process and mechanism to set aside funds to pay for future abandonment costs in respect of the sites in Canada used for the operation of a pipeline. The CER's decision stated that, while pipeline companies are ultimately responsible for the full costs of abandoning pipelines, abandonment costs are a legitimate cost of providing service and are recoverable from the users of the pipeline upon approval by the CER. Following the CER's final approval of the collection mechanism and the set-aside mechanism for LMCI, we began collecting and setting aside funds to cover future abandonment costs effective January 1, 2015. The funds collected are held in trusts in accordance with the CER decision. The funds collected from shippers are reported within Transportation and other services revenues and Restricted long-term investments and cash. Concurrently, we reflect the future abandonment cost as an increase to Operating and administrative expense and Other long-term liabilities.

CHANGES IN ACCOUNTING POLICIES

Refer to Part II. Item 8. Financial Statements and Supplementary Data - Note 3. Changes in Accounting Policies.

Our earnings, cash flows and other comprehensive income (OCI) are subject to movements in foreign exchange rates, interest rates, commodity prices and our share price.

The following summarizes the types of market risks to which we are exposed and the risk management instruments used to mitigate them. We use a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below.

Foreign Exchange Risk

We generate certain revenues, incur expenses and hold a number of investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, our earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability.

We employ financial derivative instruments to hedge foreign currency-denominated earnings exposure. A combination of qualifying and non-qualifying derivative instruments is used to hedge anticipated foreign currency-denominated revenues and expenses and to manage variability in cash flows. We hedge certain net investments in US dollar-denominated investments and subsidiaries using US dollar-denominated debt.

Interest Rate Risk

Our earnings, cash flows and OCI are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. We have a policy of limiting the maximum floating rate debt to 30% of total debt outstanding. To ensure compliance with our policy, we monitor and adjust our debt portfolio mix of fixed and variable rate debt instruments in conjunction with the use of hedging instruments. We have implemented a hedging program to partially mitigate the impact of short-term interest rate volatility on interest expense via the execution of floating-to-fixed interest rate swaps and costless collars. These swaps have an average fixed rate of 3.6%.

Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. A combination of qualifying and non-qualifying forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have established a program including some of our subsidiaries to partially mitigate our exposure to long-term interest rate variability on forecasted term debt issuances via execution of floating-to-fixed interest rate swaps with an average swap rate of 3.4%.

Commodity Price Risk

Our earnings, cash flows and OCI are exposed to changes in commodity prices as a result of our ownership interests in certain assets and investments, as well as through the activities of our energy marketing subsidiaries. These commodities include natural gas, crude oil, power and NGL. We employ financial and physical derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. We use primarily non-qualifying derivative instruments to manage commodity price risk.

Equity Price Risk

Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure to our own common share price through the issuance of various forms of stock-based compensation, which affect earnings through the revaluation of outstanding units every period.

Market Risk Management

We have a Risk Policy to minimize the likelihood that adverse cash flow impacts arising from movements in market prices will exceed a defined risk tolerance. We identify and measure all material market risks including commodity price risks, interest rate risks, foreign exchange risk and equity price risk using a standardized measurement methodology. Our market risk metric consolidates the exposure after accounting for the impact of offsetting risks and limits the consolidated cash flow volatility arising from market related risks to an acceptable approved risk tolerance threshold. Our market risk metric is Cash Flow at Risk (CFaR).

CFaR is a statistically derived measurement used to measure the maximum cash flow loss that could potentially result from adverse market price movements over a one month holding period for price sensitive non-derivative exposures and for derivative instruments we hold or issue as recorded in the Consolidated Statements of Financial Position as at December 31, 2024. CFaR assumes that no further mitigating actions are taken to hedge or otherwise minimize exposures and the selection of a one month holding period reflects the mix of price risk sensitive assets at Enbridge. As a practical matter, a large portion of Enbridge’s exposure could be hedged or unwound in a much shorter period if required to mitigate the risks.

The consolidated CFaR policy limit for Enbridge is 3.5% of its forward 12 month normalized cash flow. At December 31, 2024 and 2023 CFaR was $113 million and $100 million or 0.9% and 0.9%, respectively, of estimated 12 month forward normalized cash flow.

LIQUIDITY RISK

Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a 12 month rolling time period to determine whether sufficient funds will be available. Our primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt, which includes debentures and medium-term notes. Our shelf prospectuses with securities regulators enable ready access to either the Canadian or US public capital markets, subject to market conditions. In addition, we maintain sufficient liquidity through committed credit facilities with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated requirements for approximately one year without accessing the capital markets. We were in compliance with all the terms and conditions of our committed credit facility agreements and term debt indentures as at December 31, 2024. As a result, all credit facilities are available to us and the banks are obligated to fund us under the terms of the facilities. We also identify other potential sources of debt and equity funding alternatives, including reinstatement of our dividend reinvestment and share purchase plan or at-the-market equity issuances.

CREDIT RISK

Entering into derivative instruments may result in exposure to credit risk from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, we enter into risk management transactions primarily with institutions that possess strong investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated through the maintenance and monitoring of credit exposure limits, contractual requirements and netting arrangements. We also review counterparty credit exposure using external credit rating services and other analytical tools to manage credit risk.

We have a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements, or other similar derivative agreements, with the majority of our derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit events and reduce our credit risk exposure on financial derivative asset positions in those circumstances.

FAIR VALUE MEASUREMENTS

Our financial assets and liabilities measured at fair value on a recurring basis include derivatives and other financial instruments. We also disclose the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects our best estimates of market value based on generally accepted valuation techniques or models and is supported by observable market prices and rates. When such values are not available, we use discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value.

DISCLOSURE CONTROLS AND PROCEDURES

Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in reports filed with, or submitted to, securities regulatory authorities is recorded, processed, summarized and reported within the time periods specified under Canadian and US securities law. As at December 31, 2024, an evaluation was carried out under the supervision of and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operations of our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective in ensuring that information required to be disclosed by us in reports that we file with or submit to the SEC and the Canadian Securities Administrators is recorded, processed, summarized and reported within the time periods required.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in the rules of the SEC and the Canadian Securities Administrators. Our internal control over financial reporting is a process designed under the supervision and with the participation of executive and financial officers to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external reporting purposes in accordance with US GAAP.

Our internal control over financial reporting includes policies and procedures that:

• pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of our assets;
• provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with US GAAP; and
• provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Our internal control over financial reporting may not prevent or detect all misstatements because of inherent limitations. Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with our policies and procedures.

Our management assessed the effectiveness of our internal control over financial reporting as at December 31, 2024, based on the framework established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, our management concluded that we maintained effective internal control over financial reporting as at December 31, 2024.

During the year ended December 31, 2024, we acquired The East Ohio Gas Company, Questar Gas Company and its related Wexpro entities, and the Public Service Company of North Carolina, Incorporated. As permitted by the SEC, we excluded these acquisitions from our evaluation of the effectiveness of our internal controls over financial reporting as at December 31, 2024 because we acquired them in separate business combinations during 2024. Total assets and total revenues of The East Ohio Gas Company, Questar Gas Company and its related Wexpro entities, and Public Service Company of North Carolina, Incorporated combined represented approximately 11% and 4%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2024.

The effectiveness of our internal control over financial reporting as at December 31, 2024 has been audited by PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm appointed by our shareholders. As stated in their Report of Independent Registered Public Accounting Firm which appears in Item 8. Financial Statements and Supplementary Data, they expressed an unqualified opinion on the effectiveness of our internal control over financial reporting as at December 31, 2024.

Changes in Internal Control Over Financial Reporting

During the three months ended December 31, 2024, there has been no material change in our internal control over financial reporting.