ENBRIDGE INC

Enbridge is a leading North American energy infrastructure company. Our core businesses include Liquids Pipelines, which consists of pipelines and terminals in Canada and the US that transport and export various grades of crude oil and other liquid hydrocarbons; Gas Transmission and Midstream, 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 Ontario and Québec; and Renewable Power Generation, which consists primarily of investments in wind and solar assets, as well as geothermal, waste heat recovery and 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 exists to fuel people’s quality of life in a safe, clean, and socially responsible manner. 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 franchises that transport, distribute, and generate 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 by ensuring that people continue to have access to the energy they need today while investing in the lower-carbon platforms that will sustain us going forward.

Our leading investor value proposition is founded on our ability to deliver predictable cash flows and a growing stream of dividends year-over-year through investment in, and efficient operation of, energy infrastructure assets that are strategically positioned between key supply basins and strong demand-pull markets as well as targeted areas of growing renewable and new energy demand. Our assets are underpinned by long-term contracts, regulated cost-of-service tolling frameworks, power purchase agreements (PPAs), and other low-risk commercial arrangements.

Everyday, we strive to be the 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, ESG leadership, stakeholder relations, community investment, and employee engagement.

STRATEGY

Our strategy is underpinned by a deep understanding of energy supply and demand fundamentals. Through disciplined capital allocation, which is aligned with our outlook on energy markets, we have become an industry leader with a diversified portfolio across both conventional and lower-carbon energies. Our assets have reliably generated low-risk, resilient cash flows through many different commodity, economic, and geopolitical environments. We believe that our asset quality and diversity are key differentiators that allow us to be flexible in an uncertain business environment.

In order to continue to be an industry leader and value creator going forward, we maintain a robust strategic planning approach. 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 ensure 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 and portfolio decisions.

Predictable cash flows and ratable growth are hallmarks of our investor value proposition. Our robust portfolio of project development opportunities, the integration of recent strategic acquisitions, and ongoing efficiency improvements are expected to drive our growth in the near term (2024-2025) and the medium term to come. We remain confident in our balanced growth strategy and expect to continue to selectively invest in our diversified footprint of both conventional businesses and complementary lower-carbon platforms, such as renewable power, renewable natural gas (RNG), carbon capture and storage (CCS), blue ammonia, and hydrogen gas (H2). Additionally, ESG continues to be integral to our strategy; we are committed to reducing our emissions, building lasting relationships with our stakeholders, and promoting diversity, equity, and inclusion.

In alignment with our strategy, we progressed several of our priorities in 2023. For example:

•We announced the strategic acquisition of three US gas utilities in Ohio, Utah, and North Carolina. If completed, the Acquisitions will create the largest natural gas utility franchise in North America, lower our already industry-leading business risk profile, and secure visible, low-risk, long-term, rate base growth.

•Our Liquids Pipelines business delivered record volumes on the Mainline and Permian systems, exported record volumes through our Enbridge Ingleside Energy Center (EIEC), reached a tolling agreement for the Mainline system, sanctioned the Enbridge Houston Oil Terminal, assumed operatorship of Gray Oak Pipeline (Gray Oak), and advanced contracting open seasons for the Flanagan South Pipeline (Flanagan South), Gray Oak and Southern Lights pipelines, further strengthening our premier heavy and light oil delivery and export system.

•Our Gas Transmission and Midstream business acquired Aitken Creek Gas Storage facility and Aitken Creek North Gas Storage facility (collectively, Aitken Creek) in British Columbia and Tres Palacios Holdings LLC in Texas, achieved a final investment decision on the Rio Bravo Pipeline, advanced the Woodfibre LNG Project, and have been successfully executing on open seasons for both the Algonquin pipeline and Texas Eastern Transmission line. We continue to capitalize on strong gas fundamentals to deliver safe, reliable, and sustainable energy to North Americans while simultaneously growing LNG exports.

•Within our existing Gas Distribution and Storage business, we have progressed our rate rebasing application in Ontario, added over 46,000 new customers, and advanced Ontario’s largest greenhouse gas (GHG) reduction project to shift Arcelor Mittal’s steel-making operations from coal to natural gas. We continue to fuel Ontarians’ quality of life and economic growth through providing cost-effective, reliable, and sustainable energy to the province.

•Our Renewable Power Generation business continues to execute its growth strategy with significant progress on our European offshore wind portfolio including a 1,000 megawatt (MW) project award for the Normandy (Centre Manche 1) project in France, increased working interest at the Hohe See and Albatros projects in Germany, and ongoing construction of three additional projects in France. Our North American onshore business continued its growth through the ongoing advancement of our large development portfolio (currently greater than 4,500 MW) and through the investment in the Fox Squirrel solar project in Ohio.

•Our New Energy Technologies team, in collaboration with each business unit, advanced our low-carbon strategy through the acquisition of Morrow Renewables’ RNG assets, the creation of a strategic partnership with Yara to progress a blue ammonia export project at our EIEC near Corpus Christi, Texas, the sanctioning of the Longview RNG Project in Washington state with Divert Inc., and the continued development of prioritized lower-carbon technologies.

•We have made meaningful progress towards our ESG goals this year. We have continued to strengthen our relationships with Indigenous communities across North America while advancing our reconciliation commitments. We also increased the diversity of our Board and workforce. We are continuing on our path to net zero by lowering our emissions with multiple levers including system modernization, methane reduction technologies, powering our operations with cleaner-energy sources, and continued investment in our lower-carbon businesses.

•We continue to recycle capital at attractive valuations and in 2023 this included the announced 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 to increase our profitability and competitiveness.

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 years past. As always, proactively advancing the safety of our assets, protecting the environment, and maintaining the reliability of our system 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 developing lower-carbon platforms across all our businesses. We will continue to invest where we can advance our strategy, build sustainable competitive advantage, and achieve attractive risk-adjusted returns.

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 $24 billion through 2028) on schedule, at the lowest practical cost, while maintaining the highest 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.

In the near term we will be focused on closing the US gas utilities transactions and successfully integrating each utility. Beyond that, we will continue to seek to identify additional high-quality growth opportunities across all our platforms. We will remain disciplined and deploy capital towards only the best uses, prioritizing balance sheet strength, investment in low capital intensity growth, and regulated utility or utility-like projects. We will carefully assess our remaining investable capacity, deploying capital to the most value-enhancing opportunities available to us, including further organic growth, complementary accretive "tuck-in" acquisitions that improve our competitive positioning, or further strengthening of our balance sheet.

Looking ahead, we see strong utilization of our existing network and opportunities for future 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. Our premier liquids system and export infrastructure will also enable crude, clean fuels, and other export opportunities. Building on our early experience, we expect CCS to provide additional new growth opportunities, over the longer-term.

•Our natural gas transmission business will seek extension and expansion opportunities driven by new load demand from gas-fired power generation, industrial growth, and coastal LNG plants. Looking forward, producing and blending RNG into our system will enhance asset longevity and enable us to offer differentiated lower-carbon solutions to customers. Over the longer-term, we plan to scale similar opportunities with H2 production, blending, and transportation to further decarbonize our gas offerings and extend asset life.

•Our Ontario-based gas distribution and storage business will continue to grow through customer additions, productivity enhancements, modernization investments, and facilities that blend H2 and RNG into the gas supply. Additionally, we will continue to thoughtfully expand our offerings to customers, including additional demand-side management, low-carbon, and distributed energy programs.

•Our renewables business is increasingly well positioned to capitalize on the growth of renewables in Europe and North America. We will continue to leverage our expanded internal capabilities and our strong existing partnerships to successfully execute on our large development portfolio and secure the next wave of projects for the future.

In addition, we aim to drive growth through a continuing 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 utility, 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 to ensure 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 internally generated cash flow, available balance sheet capacity, and selective asset monetizations. 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 opportunities using a disciplined investment framework with the objective of effectively deploying capital to grow while driving 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 remain focused on larger projects where commercial constructs fit our investor value proposition and where we can effectively manage risks during the execution phase. While we will be focused in the near-term on closing our US gas utilities transactions, we are continuing 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 and dividend increases.

Lead 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 GHG emissions. Accordingly, energy systems around the world are being 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 key role in the energy transition by lowering the emission-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 leading the development and construction of future lower-carbon energy infrastructure that the world needs, along with regulators, policy makers, and other key stakeholders.

We believe that diversification and innovation will play a significant role in the transition to a lower-emission future. To date, we have made large investments in natural gas infrastructure, emissions reduction technologies, and renewable energy assets, helping to decrease our emissions and further expand our platforms to enable energy transition across the globe. Our focus areas in renewable energy remain in offshore wind, utility-scale onshore projects, and integrated clean-energy offerings and solutions for customers. We are also taking a leadership role in other lower-carbon platforms like RNG, blue ammonia, CCS, and H2 where we can leverage our infrastructure, capabilities, and stakeholder relationships to accelerate growth and extend the value of our existing assets. Additionally, all our new investments need to have a clear path to achieve net-zero emissions, in alignment with our ESG 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 ESG leadership and world-class execution capabilities to advance our positioning as a differentiated energy provider. We regularly test our assets under various transition scenarios to ensure the resiliency of our business.

STRATEGIC ENABLERS

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

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 a diverse and 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 2023, we published our 22nd annual Sustainability Report outlining our progress against our ESG goals 1. In particular, we:

•made meaningful progress towards our interim emissions intensity and net-zero GHG emissions goals through modernization and innovation of our system, and continued investment in solar self-power, front of the meter renewables, and execution of additional renewable power PPAs;

•enhanced our efforts to ensure that our workforce and the Board better reflect the diversity of our communities, empowering our workforce through employee resource groups and advancing on our diversity, equity, and inclusion 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 ESG performance to incentive compensation and are making meaningful progress towards these goals by executing on our action plans.

We aim to continuously strengthen our ESG approach and are undertaking the following additional actions:

•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

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

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

Talent

Our employees are 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 growing our focus on learning and development. We value diversity and diverse thought, and have embedded inclusive practices in our programs, processes, and approach to people management. Furthermore, we strive to maintain industry-competitive compensation, flexibility, and retention programs that provide both short- and long-term performance incentives.

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, improve efficiencies, 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.

1 All percentages or specific goals regarding inclusion, diversity, equity and accessibility are aspirational goals which we intend to achieve in a manner compliant with state, local, provincial and federal law, including, but not limited to, US federal regulations, Equal Employment Opportunity Commission, Department of Labor and Office of Federal Contract Compliance Programs.

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 ensure we 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.

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 to ensure 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 can 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, from customers and lenders to original equipment manufacturers and regulators, to develop and manage. We believe it is critical to have strengths in partnership structuring and relationship management to build and maintain the robust energy infrastructure system that the world needs.

BUSINESS SEGMENTS

During 2023, the activities were carried out through five business segments: Liquids Pipelines; Gas Transmission and Midstream; Gas Distribution and Storage; Renewable Power Generation; and Energy Services, as discussed below.

Liquids Pipelines consists of pipelines and terminals in Canada and the US that transport and export various grades of crude oil and other liquid hydrocarbons.

MAINLINE SYSTEM

The Mainline System is comprised of the Canadian Mainline and the Lakehead System. The Canadian Mainline is a common carrier pipeline system which 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 million barrels per day (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 petroleum from western Canada to the US.

Tolling Framework

The Competitive Toll Settlement (CTS) which governed tolls on the Canadian Mainline, with the exception of Lines 8 and 9 which are tolled on a separate basis, expired on June 30, 2021. The CTS was a 10-year negotiated agreement and provided 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. The IJT tolls were denominated in US dollars.

Enbridge has reached an agreement on a negotiated settlement with shippers for tolls on its Mainline System. The Mainline Tolling Settlement (MTS) covers both the Canadian and US portions of the Mainline and would see the Mainline continuing to operate as a common carrier system available to all shippers on a monthly nomination basis. The MTS is subject to regulatory approval and the term is seven and a half years through the end of 2028, with revised interim tolls effective on July 1, 2023.

The MTS includes:

•an IJT, for heavy crude oil movements from Hardisty to Chicago, comprised of a Canadian Mainline Toll of $1.65 per barrel plus a 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 power indices;

•tolls that continue to be distance and commodity adjusted, and utilize a dual currency IJT; and

•a financial performance collar providing incentives for Enbridge to optimize throughput and cost, but also providing 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, which is similar to the returns earned on average during the previous tolling agreement.

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. The other continuing feature is that the Mainline toll flexes up or down US$0.035 per barrel for 50,000 barrel per day changes in throughput.

The expected financial outcome from this settlement is in line with previously reported financial results after taking into consideration the previously recognized provision, inflationary cost adjustments and increased volumes. Enbridge filed an application with the Canada Energy Regulator (CER) for approval of the MTS on December 15, 2023, with unanimous support from its Representative Stakeholder Group. The CER indicated in its process letter that no dissenting comments were received by January 19, 2024 and that it may decide on the application or it may establish further process steps.

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.

On May 24, 2023, Enbridge filed an Offer of Settlement with the FERC for the Lakehead System (the Lakehead System Settlement). In addition to resolving litigation related to the Index portion of the Lakehead System rate, the Lakehead System Settlement also includes 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. The Lakehead System Settlement was certified by the Settlement Judge on June 23, 2023 and was approved by the FERC Commissioners on November 27, 2023. Lakehead System tolls were revised effective December 1, 2023 to reflect the terms of the Lakehead System Settlement.

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 currently provide access for oil sands production from the three major oil sands deposits, Athabasca, Cold Lake and Peace River.

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 660 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. 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 are 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, 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. It has an expected average annual capacity of 900 kbpd and transports light crude oil. During December 31, 2023, our effective economic interest in Gray Oak increased to 68.5% from 58.5% as a result of our acquisition of Rattler Midstream’s 10% interest in the pipeline. We assumed operatorship of Gray Oak in April 2023.

In October 2021, we acquired Moda Midstream Operating, LLC, which included the EIEC, located near Corpus Christi, Texas. This terminal is comprised of 15.6 million barrels of storage and 1.5 mmbpd of export capacity. We also acquired a 20% interest in the 670-kbpd Cactus II Pipeline, a 100% interest in the 300-kbpd Viola Pipeline, and a 100% interest in the 350-thousand-barrel Taft Terminal. In November 2022, we acquired an additional 10% ownership interest in Cactus II Pipeline, bringing our total non-operating ownership to 30%.

OTHER

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

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 of Southern Lights Pipeline and the US portion of Southern Lights Pipeline receive tariff revenues under long-term contracts with committed shippers. 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 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.

Competition for our liquids pipelines network comes primarily from infrastructure or logistics alternatives (rail, trucking) that transport liquid hydrocarbons from production basins in which we operate to markets in Canada, the US and internationally. Competition from existing and proposed pipelines, such as the 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.

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 China. In North America, demand growth for transportation fuels is expected to moderate over time due to vehicle fuel efficiency improvement and increasing sales of electric vehicles.

Due to the accelerated developments of offshore production in both Brazil and Guyana and continued growth from Canada and the US, it is expected that Organization of Petroleum Exporting Countries (OPEC) will try to manage prices with continued quota constraints, delaying its growth from its supply. However, production in some OPEC countries, like Iran and Venezuela, has the potential to increase from current levels. 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 2023 delivering 3.2 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 is driving 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, the largest crude oil export facility in North America.

Opposition to fossil fuel development in conjunction with evolving consumer preferences and new technology 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 pro-actively adapt our business to help meet our customers’ and society’s energy needs.

Gas Transmission and Midstream 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) 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 13,765 kilometers (8,553 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 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 1,820 kilometers (1,131 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 a 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 of Mexico 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.

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, Alliance 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.

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.

Alliance Pipeline is an approximately 3,000 kilometer (1,864 mile) integrated, high-pressure natural gas transmission pipeline with approximately 860 kilometers (534 miles) of lateral pipelines and related infrastructure. It transports liquids-rich natural gas from northeast BC, northwest Alberta and the Bakken area in North Dakota to the Alliance Chicago gas exchange hub downstream of the Aux Sable Liquid Products LP NGL extraction and fractionation plant at Channahon, Illinois. The system has a peak day capacity of 1.8 bcf/d of natural gas. We have a 50% interest in Alliance Pipeline.

On December 13, 2023, we announced that Enbridge has entered into a definitive agreement to sell our 50.0% interest in the Alliance Pipeline and our interest in Aux Sable (including 42.7% interest in Aux Sable Midstream LLC and Aux Sable Liquid Products L.P., and 50% interest in Aux Sable Canada LP) to Pembina Pipeline Corporation for $3.1 billion, including approximately $0.3 billion of non-recourse debt, subject to customary closing adjustments. Closing is expected to occur in the first half of 2024, subject to the receipt of regulatory approvals and satisfaction of customary closing conditions.

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 42.7% interest in each of Aux Sable Liquid Products LP and Aux Sable Midstream LLC, and a 50% interest in Aux Sable Canada LP (collectively, Aux Sable). Aux Sable Liquid Products LP owns and operates a NGL extraction and fractionation plant at Channahon, Illinois, outside Chicago, near the terminus of Alliance Pipeline. Aux Sable also owns facilities connected to Alliance Pipeline that facilitate delivery of liquids-rich natural gas for processing at the Aux Sable plant. These facilities include the Palermo Conditioning Plant and the Prairie Rose Pipeline in the Bakken area of North Dakota, owned and operated by Aux Sable Midstream US, and Aux Sable Canada’s interests in the Montney area of BC, comprising the Septimus Pipeline. Aux Sable Canada also owns a facility which processes refinery/upgrader offgas in Fort Saskatchewan, Alberta.

As of August 17, 2022, US Midstream also 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 36 plants and approximately 86,905 kilometers (54,000 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 of Mexico, 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, through a wholly-owned US subsidiary, we acquired the first six Morrow Renewables operating landfill gas-to-RNG production facilities located in Texas and Arkansas. The acquired assets align with and advance our low-carbon strategy.

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

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

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

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

Natural gas production in the Appalachian and Permian Basins has grown dramatically in the past decade. Today, these regions produce more than 53 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 systems, 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 2023, the US exported over 11.9 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 own systems in the region, which are highly utilized. The continental supply profile has shifted to natural gas shale plays such as the Montney and Duvernay within western Canada. These plays will 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 2023 to 22 bcf/d by 2040. This growth will support an additional 4 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 21% by 2050, according to the recently released International Energy Agency’s Stated Policy Scenario, driven primarily by economic growth in non-OECD countries. According to the Stated Policy Scenario, natural gas will play an important role in meeting this energy demand, and gas consumption is anticipated to grow by approximately 11% 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 2023-2024 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.

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 incentives being put in place such as those in the US Inflation Reduction Act, 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, has been increasing in recent years. This 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 sustainable and more environmentally friendly alternative to traditional natural gas, 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 sustainability, RNG has the potential to play an important role in the transition towards a cleaner and more resilient energy future. We believe that RNG is poised for growth as the global focus on sustainable energy solutions intensifies. Global RNG consumption is expected to increase with a 11% compound annual growth rate until 2050, according to the recently released International Energy Agency’s Stated Policy Scenario.

Gas Distribution and Storage consists of our natural gas utility operations, the core of which is Enbridge Gas Inc. (Enbridge Gas), which serves residential, commercial and industrial customers throughout Ontario. This business segment also includes natural gas distribution activities in Québec.

ENBRIDGE GAS

Enbridge Gas is a rate-regulated natural gas distribution utility with storage and transmission services. Enbridge Gas' distribution system, supported by storage and compression assets, carries natural gas from the point of local supply to customers and serves residential, commercial and industrial customers across Ontario.

There are three principal interrelated aspects of the natural gas distribution business in which Enbridge Gas is directly involved: Distribution, Transportation and Storage.

Distribution

Enbridge Gas’ principal source of revenue arises from 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, Enbridge Gas is 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 Enbridge Gas’ option primarily to meet seasonal or peak demands. The Ontario Energy Board (OEB) approves rates for both contract and general services. The distribution system consists of approximately 151,000 kilometers (93,827 miles) of pipelines that carry natural gas from the point of local supply to customers.

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 Enbridge Gas’ distribution system, or, alternatively, they may choose a system supply option, whereby customers purchase natural gas from Enbridge Gas’ supply portfolio. To acquire the necessary volume of natural gas to serve its customers, Enbridge Gas maintains a diversified natural gas supply portfolio, acquiring supplies on a delivered basis in Ontario, as well as acquiring supply from multiple supply basins across North America.

Transportation

Enbridge Gas contracts for firm transportation service, primarily with TransCanada Pipelines Limited (TransCanada), 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 allows Enbridge Gas flexibility in obtaining its own natural gas supply and accommodating the requests of its direct purchase customers for assignment of TransCanada capacity. Enbridge Gas forecasts the natural gas supply needs of its customers, including the associated transportation and storage requirements.

In addition to contracting for transportation service, Enbridge Gas offers firm and interruptible transportation services on its own Dawn-Parkway pipeline system. Enbridge Gas’ transmission system consists of approximately 3,800 kilometers (2,361 miles) of high pressure pipeline and five mainline compressor stations and has an effective peak daily demand capacity of 7.6 bcf/d. Enbridge Gas’ 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. Enbridge Gas delivered 2,218 bcf of gas through its distribution and transmission system in 2023. A substantial amount of Enbridge Gas’ transportation revenue is generated by fixed annual demand charges, with the average length of a long-term contract being approximately 17 years and the longest remaining contract term being 17 years.

Storage

Enbridge Gas’ 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 Enbridge Gas to take delivery of natural gas on favorable terms during off-peak summer periods for subsequent use during the winter heating season. This practice permits Enbridge Gas to minimize the annual cost of transportation of natural gas from its supply basins, assists in reducing its 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 Enbridge Gas’ franchise areas.

Enbridge Gas’ 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 for utility operations. Enbridge Gas also has storage contracts with third parties for 21 bcf of storage capacity.

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. During 2023, Dawn provided services such as storage, balancing, gas loans, transport, exchange and peaking services to approximately 200 counterparties.

A substantial amount of Enbridge Gas’ storage revenue is generated by fixed annual demand charges, with the average length of a long-term contract being approximately three years and the longest remaining contract term being 13 years.

GAZIFÈRE

We wholly own Gazifère Inc. (Gazifère), a natural gas distribution company that serves approximately 45,000 customers in western Québec. Gazifère is regulated by the Québec Régie de l’énergie.

US GAS UTILITIES

On September 5, 2023, we announced that Enbridge had entered into three separate definitive agreements with Dominion Energy, Inc. to acquire The East Ohio Gas Company, Questar Gas Company and its related Wexpro companies, and Public Service Company of North Carolina for an aggregate purchase price of $19.1 billion (US$14.0 billion). If completed, the Acquisitions will create North America's largest natural gas utility platform delivering over 9 bcf/d to approximately 7 million customers across multiple regulatory jurisdictions. The Acquisitions are expected to close in 2024, subject to the satisfaction of customary closing conditions including the receipt of certain regulatory approvals, which are not cross-conditional.

Enbridge Gas’ distribution system is regulated by the OEB and is subject to regulation in a number of areas, including rates. Enbridge Gas is not generally subject to third-party distribution competition within its franchise areas.

Enbridge Gas competes with other forms of energy available to its 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 law, governmental regulations, the ability to convert to alternative fuels and other factors.

We anticipate that demand for natural gas in North America will stabilize over the long term with potential growth in peak day demands; however, there are risks to the natural gas market that may challenge its growth prospects. The recent decision by the OEB on Enbridge Gas' application to establish 2024 base rates, net-zero carbon policies, evolving customer preferences for lower-carbon fuels and more efficient technologies, combined with increasing opposition to natural gas development in North America, may reduce the markets’ ability to efficiently deploy capital to connect supply and demand. We monitor these factors closely to be able to develop our business strategy to align with shifts in customer preferences and public policy requirements.

The recent decision by the OEB on Enbridge Gas' application to establish 2024 base rates includes changes to the revenue horizon over which costs can be recovered for small volume customer connections. The implications of the recent OEB decision are being assessed. Refer to Regulation - Government Regulations - Gas Distribution and Storage for further discussion.

Enbridge Gas 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 responsibly sourced natural gas, and H2.

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. However, over the past two years, geopolitical unrest has increased and led to elevated concerns with energy security in regions such as Europe and Asia. In response, one of the key supply sources supporting global energy security has been US LNG, which has introduced additional competition for North American supply. These market dynamics have resulted in higher and more volatile natural gas prices across many US and Canadian natural gas trading points. Unregulated storage values are primarily determined by the difference in value between winter and summer natural gas prices. As a result of the recent volatility exhibited in natural gas prices, storage values have risen.

Renewable Power Generation consists primarily of investments in wind and solar assets, as well as geothermal, waste heat recovery, and 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 2,371 MW of net generation capacity, which primarily consists of approximately:

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

•526 MW generated by European offshore wind facilities;

•186 MW expected to be generated by the Fécamp and Calvados Offshore Wind Projects in France, both of which are currently under construction;

•6 MW expected to be generated by the Provence Grand Large Floating Offshore Wind Project in France, which is under construction; and

•198 MW generated by North American solar facilities in operation, with an additional 30 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.

Renewable Power Generation also includes our 24.1% interest in the East-West Tie, a 450-MW transmission line in northwestern Ontario, which entered operations in March 2022.

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 maintain a 51% interest and which we manage and operate. One of our US solar projects is held within a separate joint venture in which we hold a 50% stake.

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 Grande Large Floating Offshore Wind Project, under construction in France;

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

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

Renewable Power Generation operates in the North American and European power markets, which are subject to competition and supply and demand fundamentals for power in the jurisdictions in which it operates. The majority of revenue is generated pursuant to 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 seek opportunities to collaborate with well-established renewable power developers and financial partners and to target regions with commercial constructs consistent with our low risk business model. In addition, we have expertise in completing and delivering large scale infrastructure projects.

Renewable power generation in North America and Europe is expected to grow significantly over the next 20 years due to the replacement of older fossil fuel-based sources of electricity generation in support of announced governmental carbon emissions reduction targets. Any additional governmental actions toward reducing emissions and/or increasing electrification will further accelerate renewable electricity demand growth and electrification across all sectors.

On the demand side, North American economic growth over the longer term and the continued electrification and transition to lower-carbon strategies within the residential, transportation and industrial sectors are expected to drive growing electricity demand. Furthermore, voluntary GHG emissions reduction targets are becoming increasingly expected by stakeholders, which is driving significant demand from corporate electricity end-users for clean electricity and environmental attributes. However, continued efficiency gains are expected to make the economy less energy-intensive and temper overall demand growth.

On the supply side in North America, legislation is accelerating the retirement of aging coal-fired generation, while generation from conventional nuclear power is also forecast to decline. As a result, 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 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 renewable sources is expected to double 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.

On the supply side, the International Energy Agency expects coal to fall by more than 90% from 2020 levels, while nuclear is expected to fall by one-third, by 2040. Over the same period, it anticipates power generation from renewable sources will more than double, including installed (onshore and offshore) wind more than doubling and photovoltaics solar power nearly tripling. 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.

The Energy Services businesses in Canada and the US provide physical commodity marketing and logistical services to North American refiners, producers, and other customers.

Energy Services 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, Energy Services transports and stores on both Enbridge-owned and third-party assets using a combination of contracted pipeline, storage, railcar, and truck capacity agreements.

Effective January 1, 2024, to better align how the chief operating decision-maker reviews operating performance and resource allocation across operating segments, we transferred our Canadian and US crude oil businesses from the Energy Services segment to the Liquids Pipelines segment. The Energy Services segment will cease to exist and the remainder of the business will be reported in the Eliminations and Other segment.

Energy Services’ earnings 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.

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.

REGULATION

GOVERNMENT REGULATION

Pipeline Regulation

Our Liquids Pipelines and Gas Transmission and Midstream 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 United States 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 pressures.

PHMSA continues to review existing regulations and establish new regulations to support safety standards that are designed to improve operations integrity management processes. 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. The 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 ensuring reliability targets are met. Furthermore, the integrity management program has an independent step to check the results of integrity assessments to validate the effectiveness of the program and to ensure 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 continual improvement in every aspect of integrity management.

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.

Gas Distribution and Storage

Our gas distribution and storage utility operations are regulated by the OEB and the Québec Régie de l’énergie, among others. 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.

Enbridge Gas' distribution rates, were set under a five-year incentive regulation (IR) framework using a price cap mechanism, which ended on December 31, 2023. The price cap mechanism established new rates each year through an annual base rate escalation at inflation less a 0.3% productivity factor, in addition to annual updates for certain costs to be passed through to customers, and where applicable, provided for the recovery of material discrete incremental capital investments beyond those that could be funded through base rates. The IR framework included the continuation and establishment of certain deferral and variance accounts, as well as an earnings sharing mechanism that required Enbridge Gas to share equally with customers any earnings in excess of 150 basis points over the annual OEB approved return on equity (ROE).

In October 2022, Enbridge Gas filed its application with the OEB to establish a 2024 through 2028 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. A third phase (Phase 3) has been established with the OEB as part of the Phase 1 Partial Settlement Proposal (Settlement Proposal).

On August 17, 2023, the OEB approved the Settlement Proposal to support the determination of just and reasonable rates effective January 1, 2024. Items resolved in whole or in part include:

•additions to rate base up to and including 2022;

•interest rates on debt and return on equity;

•deferral and variance accounts;

•Indigenous engagement; and

•rate implementation approach for 2024.

On December 21, 2023, the OEB issued its Decision and Order on Phase 1 (Phase 1 Decision). The decision addressed three main areas: energy transition, Enbridge Gas Distribution Inc. and Union Gas Limited amalgamation and harmonization issues, and other issues. The Phase 1 Decision included the following key findings or orders:

•energy transition risk requires Enbridge Gas 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;

•our 2024 capital plan must be reduced by $250 million with a focus on monitoring, repair and life extension of our assets and a further $50 million of capitalized indirect overhead costs must be expensed, escalating to $250 million per year during the IR term with an offsetting adjustment to revenues in each year;

•all new small volume customers wishing to connect to natural gas pay their full connection costs as an upfront charge rather than through rates over time effective January 1, 2025;

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

•an increase in equity thickness from 36% to 38% effective for 2024; and

•January 1, 2024 will be the effective date for 2024 rates.

The issues addressed in the Settlement Proposal and the Phase 1 Decision resulted in the following items not approved for future recovery, and the subsequent impairments recognized for the year ended December 31, 2023:

•a portion of undepreciated capital projects removed from 2024 rate base of $41 million;

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

•pre-2017 Union Gas Limited related pension balances of $156 million.

Enbridge Gas filed a Notice of Appeal in the Ontario Divisional Court on January 22, 2024 regarding four aspects of the Phase 1 Decision: small volume customer revenue horizon, the 2024 capital plan reduction, the extension of service life for certain asset classes and equity thickness. On January 29, 2024 Enbridge Gas also filed a Notice of Motion with the OEB requesting the OEB to review and vary five aspects of the Phase 1 Decision: small volume customer revenue horizon, the 2024 capital plan reduction, integration capital, depreciation and equity thickness. The outcome of these proceedings is uncertain.

The Phase 1 Decision results in interim rates, pending phases 2 and 3 of the proceeding, resolution of the Notice of Appeal, Notice of Motion and any possible legislative steps that could be undertaken by the Government of Ontario further to the Ontario Minister of Energy's December 22, 2023 news release. Phase 2 will establish and determine the incentive rate mechanism for the remainder of the rebasing term, and gas cost and unregulated storage cost allocation. Phase 3 will address cost allocation and the harmonization of rates and rate classes between legacy rate zones.

Enbridge Gas continues to develop opportunities to support a lower-carbon future in Ontario. In 2021, we received OEB approval of an Integrated Resource Planning (IRP) framework and integrated the framework into our planning practices. The framework requires Enbridge Gas to consider facility and non-pipe demand and/or supply side alternatives (IRP alternatives) to address the systems needs of its regulated operations, where certain parameters have been met. The framework also allows Enbridge Gas to pursue an IRP alternative (or combination of IRP alternatives and facility alternative) where it is found to be in the best interests of Enbridge Gas and its customers, taking into account reliability and safety, cost-effectiveness, public policy, optimized scoping, and risk management.

On July 19, 2023, Enbridge Gas filed an application seeking approval for the cost consequences associated with two IRP pilot projects. The projects are designed to implement demand-side IRP alternatives, including enhanced targeted energy efficiency and residential demand response programs, in combination with supply-side IRP alternatives, in select communities in order to mitigate identified system constraints and associated facility projects. The pilot projects are intended to provide learnings on the performance of the selected IRP alternatives, including the potential for scalability, that can be leveraged in future IRP alternative plan design. An OEB decision is expected during 2024.

Renewable Power Generation

Renewable Power Generation is 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.

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 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 (OBPS) and has proposed a Clean Electricity Regulation (CE Regulation) that would require Canada’s electricity grid to reach net-zero by 2035. The CE Regulation is expected to come into effect in 2024.

Policy changes may also provide new opportunities for existing assets and new developments. The US passed the Inflation Reduction Act in late 2022, which established long-term production and investment tax credits for renewable power generation, battery storage projects and for related manufacturing supply chains. Similarly, Canada has prepared legislation that would establish competitive tax credits for renewable power generation and battery storage projects, which it anticipates passing in early 2024. Changes to these tax programs 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, Texas introduced firming requirements that would require new wind and solar projects to be paired with batteries or other firm power supply and/or introduced caps on the percentage of the grid’s power that can be provided by variable generation. Other state and provincial governments are considering similar legislation.

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, effective January 1, 2023, to address the significant increase in energy prices. The impact of merchant exposure on our Renewable Power Generation asset in the UK is limited by fixed revenue payments backed by the UK government.

Energy Services

Energy Services 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. Energy Services retains dedicated professional staff and has a robust regulatory compliance program (including targeted training) to mitigate these potential risks associated with the business.

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. The provincial and territorial securities regulators similarly regulate commodity marketing within Canada and are members of the Canadian Securities Administrators. These various regulators enforce, among other things, the prohibition of market manipulation, fraud and disruptive trading.

The regulation of wholesale sales of electric energy is also regulated by the FERC, which authorizes Energy Services to sell electricity at market-based rates.

The export of natural gas out of Alberta is regulated by the Alberta Energy Regulator. The import and export of commodities between Canada and the US is subject to regulation by the CER and the US Department of Energy, as well as customs authorities. In particular, import and export permits are required, with associated regular reporting requirements. Breaches of import and export rules and permits could result in an inability to perform day to day operations, and can negatively impact the earnings of the business.

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. In the event of a release, remediation of the affected area would be required. Energy Services 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.

ENVIRONMENTAL REGULATION

Pipeline Regulation

Our Liquids Pipelines and Gas Transmission and Midstream 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 major Clean Air Act 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. In addition, there are evolving regulations on environmental justice that could impact Enbridge facilities. 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. Pursuant to federal regulations, we are currently subject to an obligation to report our GHG emissions at our largest emitting facilities. On December 2, 2023 the Environmental Protection Agency (EPA) released a final rule to minimize methane emissions for new and existing crude oil and natural gas facilities, coupled later with a fee for excess emissions. The current US presidential administration has been implementing policies designed to combat climate change and reduce GHG emissions. In addition, a number of 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 January 1, 2023, the federal carbon price was increased from $50 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.

Gas Distribution and Storage

Our Gas Distribution and Storage operations, facilities and workers are subject to municipal, provincial 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 and a small volume of oil and brine production in southwestern Ontario. Environmental risk associated with these facilities has the potential for unplanned releases. In the event of a release, remediation of the affected area would be required. 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 we are in good standing with our 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 2023 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.

Enbridge Gas utilizes emissions data management processes and systems to help with the data capture and mandatory and voluntary reporting needs. Quantification methodologies and emission factors are updated in our systems as required. Enbridge Gas continues to work with industry associations to refine quantification methodologies and emissions factors, as well as best management practices to minimize emissions.

In October 2018, the federal government confirmed that Ontario is subject to the federal government’s carbon pricing program, otherwise known as the Federal Carbon Pricing Backstop Program. This program consists of two components: a carbon charge levied on fossil fuels, including natural gas, and an OBPS. This program applies in whole or in part to any province or territory that requested it or that did not have an equivalent carbon pricing system in place by January 1, 2019.

The federal 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 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, rising to 12.39 cents/m3 in 2023. As confirmed by the federal government in July 2021, the federal carbon price will increase by $15 per tonne each year beginning in 2023, rising to $170 per tCO2e in 2030. This will equate to a federal carbon charge of 32.40 cents/m3 in 2030.

In September 2020, Ontario and the federal government announced that the federal government has accepted that Ontario’s Emission Performance Standards (EPS) will replace the federal OBPS for industrial facilities. In March 2021, the federal government announced that the federal OBPS would stand down in Ontario at the end of 2021 and Ontario would transition to the EPS effective January 1, 2022. In September 2021, the Greenhouse Gas Pollution Pricing Act was amended to remove Ontario as a covered province, enabling the EPS to take effect on January 1, 2022. Effective January 1, 2022, Enbridge Gas transitioned out of the federal OBPS to the provincial EPS. Enbridge Gas is registered with the Ontario Ministry of the Environment, Conservation and Parks 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 must remit payment annually on the portion of emissions that exceed its total annual emissions limit. Payment is due the year following a compliance period and as such, Enbridge Gas remitted payment for its 2022 EPS compliance obligation in November 2023. Enbridge Gas will remit payment for its 2023 EPS compliance obligation in 2024.

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

Renewable Power Generation

In summer 2023, the Federal Government of Canada introduced its draft CE Regulation that would cap emissions on electricity generation resources on Canada’s grid. The CE Regulation would cap emissions from electricity generation sources at, or near zero tCO2e per megawatt hour. Details of the CE Regulation and related compliance are under negotiation with the provinces at this time, at least one of which has taken steps to formally resist the adoption of the CE Regulation. The Federal Government anticipates adopting the CE Regulation in 2024, which would begin to apply to projects in 2035, as drafted.

Similarly, the US EPA introduced emissions caps for utilities that would apply to certain coal and natural gas generation facilities by 2035. The caps would require applicable facilities to either capture a portion of carbon emissions and/or to co-fire using hydrogen.

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

HUMAN CAPITAL RESOURCES

WORKFORCE SIZE AND COMPOSITION

As at December 31, 2023, we had approximately 11,500 regular employees, including approximately 1,500 unionized employees across our North American operations. This total rises to just over 13,400 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.

DIVERSITY, EQUITY AND INCLUSION

In 2020, we announced Enbridge’s ESG goals – including goals to increase representation of women, underrepresented ethnic and racial groups (including Indigenous peoples), people with disabilities and veterans – to ensure our workforce is reflective of the communities where we operate. In executing on our ESG strategy, we continue to track progress towards these representation goals in 2023. Consistent with our culture, we remain committed to open, two-way dialogue related to our goals, enhancing transparency and accountability for all stakeholders.

Diversity Representation Goals

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 9, 2024:

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 for all 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 25 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 and Midstream 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 & Storage on March 5, 2023. She is responsible for the overall leadership and operations of Ontario-based Enbridge Gas, as well as Gazifère, which serves the Gatineau region of Québec. Prior to assuming her current role, Ms. Harradence was Senior Vice President & President, Gas Distribution and Storage from March 2022 to March 2023. Prior thereto, she was Senior Vice President and Chief Operations Officer of Enbridge’s Gas Transmission and Midstream business unit from June 2019 to March 2022 and Senior Vice President Operations, Gas Transmission and Midstream from February 2017 to June 2019.

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

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

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

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

ADDITIONAL INFORMATION

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

ENBRIDGE GAS INC.

Additional information about Enbridge Gas can be found in its annual information form, financial statements and MD&A for the year ended December 31, 2023, 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 and are publicly available on SEDAR+ at www.sedarplus.ca. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.

ENBRIDGE PIPELINES INC.

Additional information about Enbridge Pipelines Inc. (EPI) can be found in its annual information form, financial statements and MD&A for the year ended December 31, 2023, which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to EPI and are publicly available on SEDAR+ at www.sedarplus.ca. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.

WESTCOAST ENERGY INC.

Additional information about Westcoast can be found in its financial statements and MD&A for the year ended December 31, 2023, which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to Westcoast and are publicly available on SEDAR+ at www.sedarplus.com. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.