ENB/Filings/10-K Diff

ENB 10-K diff: FY 2023-12-31 → FY 2025-12-31

Paragraph-level diff of Risk Factors (Item 1A) and Management's Discussion & Analysis (Item 7).

Item 1A · Risk Factors

+7 paragraphs −127 paragraphs ~7 changed

FY 2023-12-31 (earlier)

ITEM 1A. RISK FACTORS The following risk factors could materially and adversely affect our business, operations, financial results, market price or value of our securities. This list is not exhaustive, and we place no priority or likelihood based on order of presentation or grouping under sub-captions. RISKS RELATED TO CLIMATE CHANGE Climate change risks could adversely affect our reputation, strategic plan, business, operations and financial results, and these effects could be material. Climate change is a systemic risk that presents both physical and transition risks to our organization. A summary of these risks is outlined below. Given the interconnected nature of climate change-related impacts, we also discuss these risks within the context of other risks impacting Enbridge throughout Item 1A. Risk Factors . Climate change and its associated impacts may also increase our exposure to, and magnitude of, other risks identified in Item 1A. Risk Factors . Our business, financial condition, results of operations, cash flows, reputation, access to and cost of capital or insurance, business plans or strategy may all be materially adversely impacted as a result of climate change and its associated impacts. PHYSICAL RISKS Climate-related physical risks, resulting from changing and more extreme weather, can damage our assets and affect the safety and reliability of our operations. Climate-related physical risks may be acute or chronic. Acute physical risks are those that are event-driven, including increased frequency and severity of extreme weather events, such as heavy snowfall, heavy rainfall, floods, landslides, fires, hurricanes, cyclones, tornados, tropical storms, ice storms, and extreme temperatures. Chronic physical risks are longer-term shifts in climate patterns, such as long-term changes in precipitation patterns, or sustained higher temperatures, which may cause sea level rises or chronic heat waves. 45 Our assets are exposed to potential damage or other negative impacts from these kinds of events, which could result in reduced revenue from business disruption or reduced capacity and may also lead to increased costs due to repairs and required adaptation measures. Such events may also result in personal injury, loss of life or damage to property and the environment. We have experienced operational interruptions and damage to our assets from such weather events in the past, and we expect to continue to experience climate-related physical risks in the future, potentially with increasing frequency or severity. TRANSITION RISKS Transition risks relate to the transition to a lower-emissions economy, which may increase our cost of operations, impact our business plans, and influence stakeholder decisions about our company, each of which could adversely impact our reputation, strategic plan, business, operations or financial results. These transition risks include the following categories: • Policy and legal risks Policy and legal risks may result from evolving government policy, legislation, regulations and regulatory decisions focused on climate change, as well as changing political and public opinion, stakeholder opposition, legal challenges, litigation and regulatory proceedings. Foreign and domestic governments continue to evaluate and implement policy, legislation, and regulations regarding reduction of GHG emissions, adaptation to climate change, and transition to a lower-carbon economy. Such policies, laws and regulations vary at the federal, state, provincial and municipal levels in which Enbridge operates and are continually evolving. The implementation of these measures may be accelerated by international multilateral agreements, increasing physical impacts of climate change, and changing political and public opinion. Enbridge is currently required to adhere to a number of carbon-pricing mechanisms, including explicit carbon prices (i.e., in BC) and implicit carbon prices (i.e., Canadian federal OBPS). In Canada, the federal government has proposed new clean electricity regulations and is considering options to cap and cut oil and gas sector GHG emissions, which may impact our business. Such evolving policy, legislation and regulation could impact commodity demand and the overall energy mix we deliver and may result in significant expenditures and resources, as well as increased costs for our customers. In recent years, there has been an increase in climate-related regulatory action and litigation which has the potential to adversely impact our reputation, business, operations and financial results. • Technology risks Our success in executing our strategic plan, including adapting to the energy transition over time and attaining our GHG emissions reduction goals and targets, depends, in part, on technology (including technology still under development), innovation and continued diversification with renewable power and other lower-carbon energy infrastructure as well as modernization of our infrastructure, all of which could require significant capital expenditures and resources, that could materially differ from our original estimates and expectations. There is also a risk that GHG emissions reduction technology does not materialize as expected, making it more difficult to reduce emissions, or that political or public opinion regarding such technologies continues to evolve. 46 • Market risks Climate change concerns, increased demand for lower-carbon and zero-emissions energy, alternative and new energy sources and technologies, changing customer behavior and reduced energy consumption could impact the demand for our services or securities. In recent years, there has been a push toward certain investors decreasing the carbon intensity of their portfolios and pressure for banks and insurance providers to reduce or cease support for oil and natural gas and related infrastructure businesses and projects. Potential impacts include increased costs to manage these risks, adverse impacts to our access to and cost of capital, and reduced demand for, or value of, our securities. The pace and scale of the transition to a lower-carbon economy may pose a risk if Enbridge diversifies either too quickly or too slowly. Similarly, uncertainty in market signals, such as abrupt and unexpected shifts in energy costs and demands, including due to climate change concerns, can impact revenue through reduced throughput volumes on our pipeline transportation systems. • Reputational risks Companies across all sectors and industries are facing changing expectations or increasing scrutiny from stakeholders related to their approach to climate change and GHG emissions. Companies in the energy industry are experiencing stakeholder opposition to both existing and new infrastructure, as well as organized opposition to oil and natural gas extraction and shipment of oil and natural gas products. If we are not able to achieve our GHG emissions reduction goals and targets, are not able to meet future climate, emissions or other regulatory or reporting requirements, or are not able to meet or manage current and future expectations and issues regarding climate change that are important to our stakeholders, it could negatively impact our reputation and, in turn, our business, operations or financial results. • Disclosure risks Enbridge currently provides certain climate-related disclosures, and from time to time, establishes and publicly announces goals and commitments related to climate change, including reduction of GHG emissions. Standards and processes for climate-related disclosure, setting goals and targets, and measuring and reporting on progress are still developing for our sector and continue to evolve. Our internal controls and processes also continue to evolve, and our climate-related disclosures, goals and targets are based on assumptions that are subject to change. Aligning with evolving requirements has required and may continue to require us to incur significant costs. There can be no assurance that our current or future disclosures and goals, the pathways by which we plan to reach our goals, or the methodologies that we currently use to measure and report on progress, will align with new and evolving standards and processes, legal requirements or expectations of stakeholders. Such misalignment may result in reputational harm, regulatory action or other legal action. RISKS RELATED TO OPERATIONAL DISRUPTION OR CATASTROPHIC EVENTS Operation of complex energy infrastructure involves many hazards and risks that may adversely affect our business, financial results and the environment. These operational risks include adverse weather conditions, natural disasters, accidents, the breakdown or failure of equipment or processes, and lower than expected levels of operating capacity and efficiency. These operational risks could be catastrophic in nature. Operational risk is also intensified by climate change. Climate change presents physical risks that may affect the safety and reliability of our operations. These include acute physical risks, such as heavy snowfall, heavy rainfall, floods, landslides, fires, hurricanes, cyclones, tornados, tropical storms, ice storms, and extreme temperatures, and chronic physical risks, such as long-term changes in precipitation patterns, or sustained higher temperatures. 47 Our assets and operations are exposed to potential damage or other negative impacts from these operational risks, which could result in reduced revenue from business disruption or reduced capacity and may also lead to increased costs due to repairs and required adaptation measures. Such events have led to, and could in the future lead to, rupture or release of product from our pipeline systems and facilities, resulting in damage to property and the environment, personal injury or loss of life, which could result in substantial losses for which insurance may not be sufficient or available and for which we may bear part or all of the cost. An environmental incident is an event that may cause environmental harm and could lead to increased operating and insurance costs, thereby negatively impacting earnings. An environmental incident could have lasting reputational impacts and could impact our ability to work with various stakeholders. For pipeline and storage assets located near populated areas, including residential communities, commercial business centers, industrial sites and other public gathering locations, the level of damage resulting from these events could be greater. We have experienced such events in the past, and expect to continue to incur significant costs in preparing for or responding to operational risks and events. We expect to continue to experience climate-related physical risks, potentially with increasing frequency and severity, and we cannot guarantee that we will not experience catastrophic or other events in the future. In addition, we could be subject to litigation and significant fines and penalties from regulators in connection with any such events. A service interruption could have a significant impact on our operations, and negatively impact financial results, relationships with stakeholders and our reputation. A service interruption due to a major power disruption, curtailment of commodity supply, operational incident, security incident (cyber or physical), availability of gas supply or distribution or other reasons could have a significant impact on our operations and negatively impact financial results, relationships with stakeholders, our reputation or the safety of our end-use customers. Service interruptions that impact our crude oil and natural gas transportation services can negatively impact shippers’ operations and earnings as they are dependent on our services to move their product to market or fulfill their own contractual arrangements, and this has in the past and may again lead to claims against us. We have experienced, and may again experience, service interruptions, restrictions or other operational constraints, including in connection with the kinds of operational incidents referred to in the previous risk factor. Our operations involve safety risks to the public and to our workers and contractors. Several of our pipelines and distribution systems are operated in close proximity to populated areas and a major incident could result in injury or loss of life to members of the public. In addition, given the natural hazards inherent in our operations, our workers and contractors are subject to personal safety risks. A public safety incident or an injury or loss of life to our workers or contractors, which we have experienced in the past and, despite the precautions we take, may experience in the future, could result in reputational damage to us, material repair costs or increased operating and insurance costs. Cyber attacks and other cybersecurity incidents pose threats to our technology systems and could materially adversely affect our business, operations, reputation or financial results. Our business is dependent upon information systems and other digital technologies for controlling our plants, pipelines and other assets, processing transactions and summarizing and reporting results of operations. The secure processing, maintenance and transmission of information is critical to our operations. 48 Cybersecurity risks have increased in recent years as a result of the proliferation of new technologies and the increased sophistication of cyber attacks and financially motivated cybercrime, as well as due to international and domestic political factors including geopolitical tensions, armed hostilities, war, civil unrest, sabotage, terrorism and state-sponsored or other cyber espionage. Human error or malfeasance can also contribute to a cyber incident, and cyber attacks can be internal as well as external and occur at any point in our supply chain. Because of the critical nature of our infrastructure and our use of information systems and other digital technologies to control our assets, we face a heightened risk of cyber attacks, such as ransomware, theft, misplaced or lost data, programming errors, phishing attacks, denial of service attacks, acts of vandalism, computer viruses, malware, hacking, malicious attacks, software vulnerabilities, employee errors and/or malfeasance, or other attacks, security or data breaches or other cybersecurity incidents. Cyber threat actors have attacked and threatened to attack energy infrastructure, and various government agencies have increasingly stressed that these attacks are targeting critical infrastructure, including pipelines, public utilities, and power generation, and are increasing in sophistication, magnitude, and frequency. Additionally, these risks may escalate during periods of heightened geopolitical tensions. New cybersecurity legislation, regulations and orders have been recently implemented or proposed, resulting in additional actual and anticipated regulatory oversight and compliance requirements, which will require significant internal and external resources. We cannot predict the potential impact to our business of potential future legislation, regulations or orders relating to cybersecurity. We have experienced an increase in the number of attempts by external parties to access our systems or our company data without authorization, and we expect this trend to continue. Although we devote significant resources and security measures to prevent unwanted intrusions and to protect our systems and data, whether such data is housed internally or by external third parties, we and our third party vendors have experienced and expect to continue to experience cyber attacks of varying degrees in the conduct of our business. To-date, these prior cyber attacks have not, to our knowledge, had a material adverse effect on our business, operations or financial results. However, there is a risk that any such incidents could have a material adverse effect on us in the future. Our technology systems or those of our vendors or other service providers are expected to become the target of further cyber attacks or security breaches which could compromise our data and systems or our access thereto by us, our customers or others, affect our ability to correctly record, process and report transactions, result in the loss of information, or cause operational disruption or incidents. There can be no assurance that our business continuity plans will be completely effective in avoiding disruption and business impacts. Furthermore, we and some of our third-party service providers (who may in turn also use third-party service providers) collect, process or store sensitive data in the ordinary course of our business, including personal information of our employees, residential gas distribution customers, land owners and investors, as well as intellectual property or other proprietary business information of ours or our customers or suppliers. We and some of our third-party services providers will process increasing amounts of personal information upon the closing of the previously announced acquisitions of gas utilities in the US, due to their large residential customer bases. As a result of the foregoing, we could experience loss of revenues, repair, remediation or restoration costs, regulatory action, fines and penalties, litigation, breach of contract or indemnity claims, cyber extortion, ransomware, implementation costs for additional security measures, loss of customers, customer dissatisfaction, reputational harm, be liable under laws that protect the privacy of personal information, other negative consequences, or other costs or financial loss. These risks may be heightened, and the consequences magnified, upon closing of the Acquisitions. Regardless of the method or form of cyber attack or incident, any or all of the above could materially adversely affect our reputation, business, operations or financial results. 49 In addition, a cyber attack could occur and persist for an extended period without detection. Any investigation of a cyber attack or other security incident may be inherently unpredictable, and it would take time before the completion of any investigation and availability of full and reliable information. During such time, we may not know the extent of the harm or how best to remediate it, and certain errors or actions could be repeated or compounded before they are discovered and remediated, all or any of which could further increase the costs and consequences of a cyber attack or other security incident, and our remediation efforts may not be successful. The inability to implement, maintain and upgrade adequate safeguards could materially and adversely affect our results of operations, cash flows, and financial condition. Moreover, recent rulemakings may require us to disclose information about a cybersecurity incident before it has been completely investigated or remediated in full or even in part. As cyber attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. Furthermore, media reports about a cyber attack or other significant security incident affecting Enbridge, whether accurate or not, or, under certain circumstances, our failure to make adequate or timely disclosures to the public, law enforcement, other regulatory agencies or affected individuals following any such event, whether due to delayed discovery or otherwise, could negatively impact our operating results and result in other negative consequences, including damage to our reputation or competitiveness, harm to our relationships with customers, partners, suppliers, investors, and other third parties, interruption to our management, remediation or increased protection costs, significant litigation or regulatory action, fines or penalties, all of which could materially adversely affect our business, operations, reputation or financial results. Terrorist attacks and threats, escalation of military activity in response to these attacks or acts of war, and other civil unrest or activism could adversely affect our business, operations or financial results. Terrorist attacks and threats (which may take the form of cyber attacks), escalation of military activity, armed hostilities, war, sabotage, or civil unrest or activism may have significant effects on general economic conditions and may cause fluctuations in consumer confidence and spending and market liquidity, each of which could adversely affect our business. Future terrorist attacks, rumors or threats of war, actual conflicts involving the US or Canada, or military or trade disruptions may significantly affect our operations and those of our customers. Strategic critical infrastructure targets, such as energy-related assets, are at greater risk of cyber attack and may be at greater risk of other future attacks than other targets in the US and Canada. Enbridge’s infrastructure and projects under construction could be direct targets or indirect casualties of a cyber or physical attack. In addition, increased environmental activism against pipeline construction and operation could potentially result in work delays, reduced demand for our products and services, new legislation or public policy or increased stringency thereof, or denial or delay of permits and rights-of-way. Pandemics, epidemics or infectious disease outbreaks, such as the COVID-19 pandemic, may adversely affect local and global economies and our business, operations or financial results. Disruptions caused by pandemics, epidemics or infectious disease outbreaks could materially adversely affect our business, operations, financial results and forward-looking expectations. Governments' emergency measures to combat the spread could include restrictions on business activity and travel, as well as requirements to isolate or quarantine. The duration and magnitude of such impacts will depend on many factors that we may not be able to accurately predict. COVID-19 and government responses interrupted business activities and supply chains, disrupted travel, and contributed to significant volatility in the financial and commodity markets. Disruptions related to pandemics, epidemics or infectious disease outbreaks could have the effect of heightening many of the other risks described in this Item 1A. Risk Factors . 50 RISKS RELATED TO OUR BUSINESS AND INDUSTRY There are utilization risks with respect to our assets. With respect to our Liquids Pipelines assets, we are exposed to throughput risk on the Canadian Mainline, and we are exposed to throughput risk under certain tolling agreements applicable to other Liquids Pipelines assets, such as the Lakehead System. A decrease in volumes transported can directly and adversely affect our revenues and earnings. Factors such as changing market fundamentals, capacity bottlenecks, regulatory restrictions, maintenance and operational incidents on our system and upstream or downstream facilities, and increased competition can all impact the utilization of our assets. Market fundamentals, such as commodity prices and price differentials, weather, gasoline price and consumption, alternative and new energy sources and technologies, and global supply disruptions outside of our control can impact both the supply of and demand for crude oil and other liquid hydrocarbons transported on our pipelines. With respect to our Gas Transmission and Midstream assets, gas supply and demand dynamics continue to change due to shifts in regional and global production and consumption. These shifts can lead to fluctuations in commodity prices and price differentials, which could result in our system not being fully utilized in some areas. Other factors affecting system utilization include operational incidents, regulatory restrictions, system maintenance, and increased competition. With respect to our Gas Distribution and Storage assets, customers are billed on both a fixed charge and volumetric basis and our ability to collect the total revenue requirement (the cost of providing service, including a reasonable return to the utility) depends on achieving the forecast distribution volume established in the rate-making process. The probability of realizing such volume is contingent upon four key forecast variables: weather, economic conditions, pricing of competitive energy sources and growth in the number of customers. Weather is a significant driver of delivery volumes, given that a significant portion of our Gas Distribution customer base uses natural gas for space heating. Distribution volume may also be impacted by the increased adoption of energy efficient technologies, along with more efficient building construction, that continue to place downward pressure on consumption. In addition, conservation efforts by customers may further contribute to a decline in annual average consumption. Sales and transportation service to large volume commercial and industrial customers is more susceptible to prevailing economic conditions. As well, the pricing of competitive energy sources affects volume distributed to these sectors as some customers have the ability to switch to an alternate fuel. Even in those circumstances where we attain our respective total forecast distribution volume, our Gas Distribution business may not earn its expected ROE due to other forecast variables, such as the mix between the higher margin residential and commercial sectors and the lower margin industrial sector. Our Gas Distribution business remains at risk for the actual versus forecast large volume contract commercial and industrial volumes. With respect to our Renewable Power Generation assets, earnings from these assets are highly dependent on weather and atmospheric conditions as well as continued operational availability of these energy producing assets. While the expected energy yields for Renewable Power Generation projects are predicted using long-term historical data, wind and solar resources are subject to natural variation from year-to-year and from season-to-season. Any prolonged reduction in wind or solar resources at any of the Renewable Power Generation facilities could lead to decreased earnings and cash flows. Additionally, inefficiencies or interruptions of Renewable Power Generation facilities due to operational disturbances or outages resulting from weather conditions or other factors, could also impact earnings. 51 Our assets vary in age and were constructed over many decades which causes our inspection, maintenance or repair costs to increase. Our pipelines vary in age and were constructed over many decades. Pipelines are generally long-lived assets, and pipeline construction and coating techniques have changed over time. Depending on the era of construction and construction techniques, some assets require more frequent inspections, which has resulted in and is expected to continue to result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our business, operations or financial results. Competition may result in a reduction in demand for our services, fewer project opportunities or assumption of risk that results in weaker or more volatile financial performance than expected. Our Liquids Pipelines business faces competition from competing carriers available to ship liquid hydrocarbons to markets in Canada, the US and internationally and from proposed pipelines that seek to access basins and markets currently served by our Liquids Pipelines. Competition among existing pipelines is based primarily on the cost of transportation, access to supply, the quality and reliability of service, contract carrier alternatives and proximity to markets. The liquids transported in our pipelines currently, or are expected to increasingly, compete with other emerging alternatives for end-users, including, but not limited to, electricity, electric batteries, biofuels, and hydrogen. Additionally, we face competition from alternative storage facilities. Our natural gas transmission and storage businesses compete with similar facilities that serve our supply and market areas in the transmission and storage of natural gas. The natural gas transported in our business also competes with other forms of energy available to our customers and end-users, including electricity, coal, propane, fuel oils, and renewable energy. Our Renewable Power Generation business faces competition in the procurement of long-term power purchase agreements and from other fuel sources in the markets in which we operate. Competition in all of our businesses, including competition for new project development opportunities, could have a negative impact on our business, financial condition or results of operations. Completion of our secured projects and maintenance programs are subject to various regulatory, operational and market risks, which may affect our ability to drive long-term growth. Our project execution continues to face challenges with intense scrutiny on regulatory and environmental permit applications, politicized permitting, public opposition including protests, action to repeal permits, and resistance to land access. We have experienced permit denials, in particular, in relation to necessary maintenance on the Line 5 Pipeline on the Bad River Reservation in northern Wisconsin based on a stated desire of the Bad River Band to shut down the pipeline. Continued challenges with global supply chains have created unpredictability in materials cost and availability. Labor shortages and inflationary pressures have increased costs of engineering and construction services. Other events that can and have delayed project completion and increased anticipated costs include contractor or supplier non-performance, extreme weather events or geological factors beyond our control. 52 Changing expectations of stakeholders regarding ESG and climate change practices could erode stakeholder trust and confidence, damage our reputation and influence actions or decisions about our company and industry and have negative impacts on our business, operations or financial results. Companies across all sectors and industries are facing changing expectations or increasing scrutiny from stakeholders related to their approach to ESG matters of greatest relevance to their business and to their stakeholders. For energy companies, climate change, GHG emissions, safety and stakeholder and Indigenous relations remain primary focus areas, while other environmental elements such as biodiversity, human rights, and supply chain are ascendant. Companies in the energy industry are experiencing stakeholder opposition to new and existing infrastructure, as well as organized opposition to oil and natural gas extraction and shipment of oil and natural gas products. Changing expectations of our practices and performance across these ESG areas may impose additional costs or create exposure to new or additional risks. We are also exposed to the risk of higher costs, delays, project cancellations, loss of ability to secure new growth opportunities, new restrictions or the cessation of operations of existing pipelines due to increasing pressure on governments and regulators, and legal action, such as the legal challenges to the operation of Line 5 in Michigan and Wisconsin. Our operations, projects and growth opportunities require us to have strong relationships with key stakeholders, including local communities, Indigenous groups and others directly impacted by our activities, as well as governments, regulatory agencies, investors and investor advocacy groups, investment funds, financial institutions, insurers and others, which are increasingly focused on ESG practices and performance. Enhanced public awareness of climate change has driven an increase in demand for lower-carbon and zero-emissions energy. There have been efforts in recent years affecting the investment community, including certain investors increasing investments in lower-carbon assets and businesses while decreasing the carbon intensity of their portfolios through, among other measures, divestments of companies with high exposure to GHG-intensive operations and products. Certain stakeholders have also pressured commercial and investment banks and insurance providers to reduce or stop financing and providing insurance coverage to oil and natural gas and related infrastructure businesses and projects. Managing these risks requires significant effort and resources. Potential impacts could also include changing investor sentiment regarding investment in Enbridge, which could impair our access to and increase our cost of capital, including penalties associated with our sustainability-linked financing and could adversely impact demand for, or value of, our securities. Over the past year, geopolitical uncertainty, slowing Canadian and US economies and continuing inflationary pressures have underscored the critical need for access to secure, affordable energy. The pace and scale of the transition to a lower-emission economy may pose a risk if Enbridge diversifies either too quickly or too slowly. Similarly, unexpected shifts in energy demands, including due to climate change concerns, can impact revenue through reduced throughput volumes on our pipeline transportation systems. 53 We have long been committed to strong ESG practices, performance and reporting, and in 2020 introduced a set of ESG goals to strengthen transparency and accountability. The goals include increasing diversity and inclusion within our organization and reducing GHG emissions from our operations to net-zero by 2050, with corporate and business unit action plans aligned to our strategic priority to adapt to the energy transition over time. The costs associated with meeting our ESG goals, including our GHG emissions reduction goals, could be significant. There is also a risk that some or all of the expected benefits and opportunities of achieving our ESG goals may fail to materialize, may cost more than anticipated to achieve, may not occur within the anticipated time periods or may no longer meet changing stakeholder expectations. Similarly, there is a risk that emissions reduction technologies do not materialize as expected making it more difficult to reduce emissions. If we are not able to achieve our ESG goals, are not able to meet current and future climate, emissions or related reporting requirements of regulators, or are unable to meet or manage current and future expectations regarding issues important to investors or other stakeholders (including those related to climate change), it could erode stakeholder trust and confidence, which could negatively impact our reputation, business, operations or financial results. Our forecasted assumptions may not materialize as expected, including on our expansion projects, acquisitions and divestitures. We evaluate expansion projects, acquisitions and divestitures on an ongoing basis. Planning and investment analysis is highly dependent on accurate forecasting assumptions and to the extent that these assumptions do not materialize, financial performance may be lower or more volatile than expected. Volatility and unpredictability in the economy, both locally and globally, and changes in cost estimates, project scoping and risk assessment could result in a loss of profits. Similarly, uncertainty in market signals, such as abrupt and unexpected shifts in energy costs and demands, as we saw in 2020 resulting from the COVID-19 pandemic, have impacted, and may in the future impact, revenue through reduced throughput volumes on our pipeline transportation systems. One or all of the Acquisitions may not occur on the terms contemplated in the applicable Purchase and Sale Agreement or at all, or may not occur within the expected time frame, which may negatively affect the benefits we expect to obtain from the Acquisitions. We cannot provide any assurance that the Acquisitions will be completed in the manner, on the terms and on the time frame currently anticipated, or at all. Completion of each of the Acquisitions is subject to the satisfaction or waiver of a number of conditions as set forth in the applicable Purchase and Sale Agreement that are beyond our control and may prevent, delay or otherwise materially adversely affect its completion. The success of the Acquisitions will depend on, among other things, our ability to integrate the US gas utilities into our business in a manner that facilitates growth opportunities and achieves anticipated results. There is a significant degree of difficulty and management distraction inherent in the process of integrating an acquisition, including challenges integrating certain operations and functions (including regulatory functions), technologies, organizations, procedures, policies and operations, addressing differences in the business cultures of Enbridge and the US gas utilities and retaining key personnel. The integration may be complex and time consuming and involve delays or additional and unforeseen expenses. The integration process and other disruptions resulting from the Acquisitions may also disrupt our ongoing business. Any failure to realize the anticipated benefits of the Acquisitions, additional unanticipated costs or other factors could negatively impact our earnings or cash flows, decrease or delay any beneficial effects of the Acquisitions and negatively impact our business, financial condition and results of operations. 54 Our insurance coverage may not fully cover our losses in the event of an accident, natural disaster or other hazardous event, and we may encounter increased cost arising from the maintenance of, or lack of availability of, insurance. Our operations are subject to many hazards inherent in our industry as described in this Item 1A. Risk Factors . We maintain an insurance program for us, our subsidiaries and certain of our affiliates to mitigate a certain portion of our risks. However, not all potential risks arising from our operations are insurable, or are insured by us as a result of availability, high premiums and for various other reasons. Enbridge self-insures a significant portion of certain risks through our wholly-owned captive insurance subsidiaries, and Enbridge’s insurance coverage is subject to terms and conditions, exclusions and large deductibles or self-insured retentions which may reduce or eliminate coverage in certain circumstances. Enbridge’s insurance policies are generally renewed on an annual basis and, depending on factors such as market conditions, the premiums, terms, policy limits and/or deductibles can vary substantially. We can give no assurance that we will be able to maintain adequate insurance in the future at rates or on other terms we consider commercially reasonable. In such case, we may decide to self-insure additional risks. A significant self-insured loss, uninsured loss, a loss significantly exceeding the limits of our insurance policies, a significant delay in the payment of a major insurance claim, or the failure to renew insurance policies on similar or favorable terms could materially and adversely affect our business, financial condition and results of operations. Our business is exposed to changes in market prices including interest rates and foreign exchange rates. Our risk management policies cannot eliminate all risks and may result in material financial losses. In addition, any non-compliance with our risk management policies could adversely affect our business, operations or financial results. Our use of debt financing exposes us to changes in interest rates on both future fixed rate debt issuances and floating rate debt. While our financial results are denominated in Canadian dollars, many of our businesses have foreign currency revenues or expenses, particularly the US dollar. Changes in interest rates and foreign exchange rates could materially impact our financial results. We use financial derivatives to manage risks associated with changes in foreign exchange rates, interest rates, commodity prices, power prices and our share price to reduce volatility of our cash flows. Based on our risk management policies, substantially all of our financial derivatives are associated with an underlying asset, liability and/or forecasted transaction and not intended for speculative purposes. These policies cannot, however, eliminate all risk, including unauthorized trading. Although this activity is monitored independently by our Risk Management function, we can provide no assurance that we will detect and prevent all unauthorized trading and other violations, particularly if deception, collusion or other intentional misconduct is involved, and any such violations could adversely affect our business, operations or financial results. To the extent that we hedge our exposure to market prices, we will forego the benefits we would otherwise experience if these were to change in our favor. In addition, hedging activities can result in losses that might be material to our financial condition, results of operations and cash flows. Such losses have occurred in the past and could occur in the future. See Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk and Item 8. Financial Statements and Supplementary Data for a discussion of our derivative instruments and related hedging activities. 55 We rely on access to short-term and long-term capital markets to finance capital requirements and support liquidity needs. Cost effective access to those markets can be affected, particularly if we or our rated subsidiaries are unable to maintain an investment-grade credit rating. A significant portion of our consolidated asset base is financed with debt. The maturity and repayment profile of debt used to finance investments often does not correlate to cash flows from assets. Accordingly, we rely on access to both short-term and long-term capital markets as a source of liquidity for capital requirements not satisfied by cash flows from operations and to refinance investments originally financed with debt. Our senior unsecured long-term debt is currently rated investment-grade by various rating agencies. If the rating agencies were to rate us or our rated subsidiaries below investment-grade, our borrowing costs would increase, perhaps significantly. Consequently, we would likely be required to pay a higher interest rate in future financings and our potential pool of investors and funding sources could decrease. We maintain revolving credit facilities at various entities to backstop commercial paper programs, for borrowings and for providing letters of credit. These facilities typically include financial covenants and failure to maintain these covenants at a particular entity could preclude that entity from accessing the credit facility, which could impact liquidity. Furthermore, if our short-term debt rating were to be downgraded, access to the commercial paper market could be significantly limited. Although this would not affect our ability to draw under our credit facilities, borrowing costs could be significantly higher. If we are not able to access capital at competitive rates or at all, our ability to finance operations and implement our strategy may be affected. An inability to access capital on favorable terms or at all may limit our ability to pursue enhancements or acquisitions that we may otherwise rely on for future growth or to refinance our existing indebtedness. Any downgrade or other event negatively affecting the credit ratings of our subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could increase our need to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing the liquidity and borrowing availability of the consolidated group. Our Liquids Pipelines growth rate and results may be indirectly affected by commodity prices. Wide commodity price basis between Western Canada and global tidewater markets have negatively impacted producer netbacks and margins in the past years that largely resulted from pipeline infrastructure takeaway capacity from producing regions in Western Canada and North Dakota which are operating at capacity. A protracted long-term outlook for low crude oil prices could result in delay or cancellation of future projects. The tight conventional oil plays of Western Canada, the Permian Basin, and the Bakken region of North Dakota have short cycle break-even time horizons, typically less than 24 months, and high decline rates that can be well managed through active hedging programs and are positioned to react quickly to market signals. Accordingly, during periods of comparatively low prices, drilling programs, unsupported by hedging programs, will be reduced and as such, supply growth from tight oil basins may be lower, which may impact volumes on our pipeline systems. Our Energy Services and Gas Transmission and Midstream results may be adversely affected by commodity price volatility. Within our US Midstream assets, we hold investments in DCP and Aux Sable, which are engaged in the businesses of gathering, treating, processing and selling natural gas and natural gas liquids. The financial results of these businesses are directly impacted by changes in commodity prices. To a lesser degree, the financial results of our US Transmission business are subject to fluctuation in power prices which impact electric power costs associated with operating compressor stations. 56 Energy Services generates margin by capitalizing on quality, time and location differentials when opportunities arise. Changing market conditions that impact the prices at which we buy and sell commodities have in the past limited margin opportunities and impeded Energy Services' ability to cover capacity commitments and could do so again in the future. Other market conditions, such as backwardation, have likewise limited margin opportunities. We are exposed to the credit risk of our customers, counterparties, and vendors. We are exposed to the credit risk of multiple parties in the ordinary course of our business. Generally, our customers are rated investment-grade, are otherwise considered creditworthy or provide us security to satisfy credit concerns. However, we cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including possible declines in the creditworthiness of our customers, vendors, or counterparties. It is possible that payment or performance defaults from these entities, if significant, could adversely affect our earnings and cash flows. Our business requires the retention and recruitment of a skilled and diverse workforce, and difficulties in recruiting and retaining our workforce could result in a failure to implement our business plans. Our operations and management require the retention and recruitment of a skilled and diverse workforce, including engineers, technical personnel, other professionals and executive officers and senior management. We and our affiliates compete with other companies in the energy industry, and for some jobs the broader labor market, for this skilled workforce. If we are unable to retain current employees and/or recruit new employees of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased costs to retain and recruit these professionals. RISKS RELATED TO GOVERNMENT REGULATION AND LEGAL RISKS Many of our operations are regulated and failure to secure timely regulatory approval for our proposed projects, or loss of required approvals for our existing operations, could have a negative impact on our business, operations or financial results. The nature and degree of regulation and legislation affecting permitting and environmental review for energy infrastructure companies in Canada and the US continues to evolve. Within the US and in Canada, pipeline companies continue to face opposition from anti-energy/anti-pipeline activists, Indigenous and tribal groups and communities, citizens, environmental groups, and politicians concerned with the safety of pipelines and their potential environmental effects. In the US, the EPA redefined the Waters of the United States to align with the U.S. Supreme Court’s May 25, 2023 Sackett v. EPA decision that limits the scope of waters regulated by the Clean Water Act, issued new rules under Section 401 of the Clean Water Act broadening the scope of state review for water quality certifications, released rules on methane control and reporting, Cross-state Ozone Pollution (The Good Neighbor Plan), and the Power Plant Rule. The Council for Environmental Quality published immediately applicable guidance for conducting analyses under the National Environmental Policy Act (NEPA), followed by a new rule governing implementation of NEPA in federal actions that may significantly change environmental scope and cost assessments. The FERC has focused on the relationship between natural gas and electric power generation, particularly in connection with reliability issues during severe weather events. The PHMSA issued a draft rule on leak detection and repair. Federal agencies also issued guidance on how environmental justice concerns should be considered and addressed. Many other regulations adopted during the previous US presidential administration are being challenged in multiple courts and some have been overturned by reviewing courts. The current US administration may take further action to modify or reverse regulations that were promulgated by the previous US administration.57In March of 2023, the Supreme Court of Canada heard the Attorney General of Canada’s appeal of the Alberta Court of Appeal’s non-binding decision that the federal Impact Assessment Act (IAA) is unconstitutional. The IAA includes impact assessment requirements that could apply to either federally or provincially regulated pipeline projects that fall within prescribed criteria or that the federal Minister of Environment otherwise designates for review. The potential for any pipeline project to be subject to IAA requirements adds significant uncertainty as to regulatory timelines and outcomes. The Alberta Court of Appeal found that the IAA is an impermissible federal overreach into provincial jurisdiction that would amount to a de facto expropriation of provincial natural resources and proprietary interests by the federal government. The Supreme Court of Canada issued its decision on October 13, 2023, with a majority of the court (5-2) finding that the federal impact assessment regime is outside of the federal Parliament’s authority and that the IAA should focus more narrowly on effects within federal jurisdiction. The decision is a non-binding advisory reference case, so the IAA and associated regulations are not "struck down"; however, the federal government will take the Supreme Court of Canada’s guidance and in collaboration with provinces and Indigenous groups, will seek to amend the IAA so that it is constitutional. The resulting amendments could impact the risks and timing of potential future regulatory approvals and the scope of federal review of intraprovincial pipeline projects. Our operations are subject to numerous environmental laws and regulations, including those relating to climate change, GHG emissions and climate-related disclosure, compliance with which may require significant capital expenditures, increase our cost of operations, and affect or limit our business plans, or expose us to environmental liabilities. We are subject to numerous environmental laws and regulations affecting many aspects of our past, current, and future operations, including air emissions, water and soil quality, wastewater discharges, solid waste and hazardous waste. If we are unable to obtain or maintain all required environmental regulatory approvals and permits for our operating assets and projects or if there is a delay in obtaining any required environmental regulatory approvals or permits, the operation of existing facilities or the development of new facilities could be prevented, delayed, or become subject to additional costs. Failure to comply with environmental laws and regulations may result in the imposition of civil or criminal fines, penalties and injunctive measures affecting our operating assets. We expect that changes in environmental laws and regulations, including those related to climate change, GHG emissions and climate-related disclosure, could result in a material increase in our cost of compliance with such laws and regulations, such as costs to monitor and report our emissions and install new emission controls to reduce emissions. We may not be able to include some or all of such increased costs in the rates charged for utilization of our pipelines or other facilities. Our operations are subject to operational regulation and other requirements, including compliance with easements and other land tenure documents, and failure to comply with applicable regulations and other requirements could have a negative impact on our reputation, business, operations or financial results. Operational risks relate to compliance with applicable operational rules and regulations mandated by governments, applicable regulatory authorities, or other requirements that may be found in easements, permits, or other agreements that provide a legal basis for our operations, breaches of which could result in fines, penalties, awards of damages, operating restrictions (including shutdown of lines) and an overall increase in operating and compliance costs. We do not own all of the land on which our pipelines, facilities and other assets are located and we obtain the rights to construct and operate our pipelines and other assets from third parties or government entities. In addition, some of our pipelines, facilities and other assets cross Indigenous lands pursuant to rights-of-way or other land tenure interests. Our loss of these rights, including through our inability to renew them as they expire, could have an adverse effect on our reputation, operations and financial results. We have experienced litigation in relation to certain Line 5 and other easements; refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates .58Regulatory scrutiny over our assets and operations has the potential to increase operating costs or limit future projects. Regulatory enforcement actions issued by regulators for non-compliant findings can increase operating costs and negatively impact reputation. Potential regulatory changes and legal challenges could have an impact on our future earnings from existing operations and the cost related to the construction of new projects. Regulators' future actions may differ from current expectations, or future legislative changes may impact the regulatory environments in which we operate. While we seek to mitigate operational regulation risk by actively monitoring and consulting on potential regulatory requirement changes with the respective regulators directly, or through industry associations, and by developing response plans to regulatory changes or enforcement actions, such mitigation efforts may be ineffective or insufficient. While we believe the safe and reliable operation of our assets and adherence to existing regulations is the best approach to managing operational regulatory risk, the potential remains for regulators or other government officials to make unilateral decisions that could disrupt our operations or have an adverse financial impact on us. Our operations are subject to economic regulation and failure to secure regulatory approval for our proposed or existing commercial arrangements could have a negative impact on our business, operations or financial results. Our Liquids Pipelines, Gas Transmission and Gas Distribution assets face economic regulation risk. Broadly defined, economic regulation risk is the risk that governments or regulatory agencies change or reject proposed or existing commercial arrangements or policies, including permits and regulatory approvals for both new and existing projects or agreements, upon which future and current operations are dependent. Our Mainline System, other liquids pipelines, gas transmission and distribution assets are subject to the actions of various regulators, including the CER, the FERC, and the OEB with respect to the rates, tariffs, and tolls for these assets. The changing or rejecting of commercial arrangements, including decisions by regulators on the applicable permits and tariff structure or changes in interpretations of existing regulations by courts or regulators such as with respect to the negotiated settlements applicable to our Mainline System, could have an adverse effect on our revenues and earnings. Our Renewable Power Generation assets in Canada and the US are subject to directives, regulations, and policies of federal, provincial and state governments. These measures are variable and can change as a result of, among other things, tax rate changes and a change in the government, which can have a negative impact on our commercial arrangements. Our Renewable Power Generation assets in Europe (France, Germany and the UK) are also subject to the directives, regulations and policies established and enforced by the EU and the UK government. These measures are variable and can include price controls, caps and demand reduction goals, all of which can have a negative impact on our revenues and earnings. 59 We are subject to changes in our tax rates, the adoption of new US, Canadian or international tax legislation or exposure to additional tax liabilities. We are subject to taxes in the US, Canada and numerous foreign jurisdictions. Due to economic and political conditions, tax rates in various jurisdictions may be subject to significant change. Our effective tax rates could be affected by changes in the mix of earnings in countries with differing statutory tax rates, changes in the valuation of deferred tax assets and liabilities, or changes in tax laws or their interpretation. In particular, Canada and other OECD countries have introduced a minimum tax rate to be applied on a global basis. The final legislation and list of the participating countries remains uncertain. In addition, the US enacted the Inflation Reduction Act in 2022 however key regulations still remain outstanding that could impact the interpretation of that act. All of these measures could cause our effective tax rate to increase. We are also subject to the examination of our tax returns and other tax matters by the US Internal Revenue Service, the Canada Revenue Agency and other tax authorities and governmental bodies. We regularly assess the likelihood of an adverse outcome resulting from these examinations to determine the adequacy of our provision for taxes. There can be no assurance as to the outcome of these examinations. If our effective tax rates were to increase, particularly in the US or Canada, or if the ultimate determination of our taxes owed is for an amount in excess of amounts previously accrued, our financial condition and operating results could be materially adversely affected. We are involved in numerous legal proceedings, the outcomes of which are uncertain, and resolutions adverse to us could adversely affect our financial results. We are subject to numerous legal proceedings. In recent years, there has been an increase in climate and disclosure-related litigation against governments as well as companies involved in the energy industry. There is no assurance that we will not be impacted by such litigation, or by other legal proceedings. Litigation is subject to many uncertainties, and we cannot predict the outcome of individual matters with assurance. It is reasonably possible that the final resolution of some of the matters in which we are involved or new matters could require additional expenditures, in excess of established reserves, over an extended period of time and in a range of amounts that could adversely affect our financial results or affect our reputation. Refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates for a discussion of certain legal proceedings with recent developments.

FY 2025-12-31 (later)

Item 1A. Risk Factors 43 Item 1B. Unresolved Staff Comments57Item 1C. Cybersecurity58

Item 7 · Management's Discussion & Analysis

+745 paragraphs −475 paragraphs ~475 changed

FY 2023-12-31 (earlier)

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS INTRODUCTION The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with "Forward-Looking Information" and "Non-GAAP and Other Financial Measures", Part I. Item 1A. Risk Factors and our consolidated financial statements and the accompanying notes included in Part II. Item 8. Financial Statements and Supplementary Data of this Annual Report on Form 10-K.This section of our Annual Report on Form 10-K discusses 2023 and 2022 items and year-over-year comparisons between 2023 and 2022. For discussion of 2021 items and year-over-year comparisons between 2022 and 2021, refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report on Form 10-K for the year ended December 31, 2022.RECENT DEVELOPMENTSMAINLINE TOLLING AGREEMENT Enbridge Inc. (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 International Joint Toll (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 (L3R) 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. 65 On May 24, 2023, Enbridge filed an Offer of Settlement with the Federal Energy Regulatory Commission (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. ACQUISITIONS Acquisition of Renewable Natural Gas (RNG) Facilities 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 for total consideration of $1.4 billion (US$1.1 billion), of which $0.5 billion (US$0.4 billion) was paid at close and $0.9 billion (US$0.7 billion) is payable within two years. The total consideration for all seven facilities is $1.6 billion (US$1.2 billion). Combined RNG production of the facilities is approximately 4.5 bcf per year. The acquired assets align with and advance our low-carbon strategy. Fox Squirrel Solar On November 15, 2023, we acquired a 50% interest in a newly formed partnership with EDF Renewables North America to participate in the initial phase of a solar power facility in Ohio. Cash consideration includes an upfront payment of $157 million (US$115 million) and subsequent capital commitments up to $398 million (US$291 million). Investments past the first phase are contingent on certain conditions being met. An additional payment of $164 million (US$123 million) was made at Phase 1 in-service in December 2023. Hohe See and Albatros Offshore Wind Facilities On November 3, 2023, we acquired an additional 24.45% interest in the Hohe See Offshore Wind Facilities and Albatros Offshore Wind Facilities (the Offshore Wind Facilities), through the acquisition of a 49% interest in Enbridge Renewable Infrastructure Investments S. à r.l (ERII), for $391 million (€267 million) of cash and assumed debt of $524 million (€358 million), bringing our interest in the Offshore Wind Facilities to 49.9%. The Hohe See Offshore Wind Facilities and Albatros Offshore Wind Facilities are located approximately 100 kilometers off the northern coast of Germany and came into service in 2019 and 2020, respectively. Aitken Creek Gas Storage On November 1, 2023, through a wholly-owned Canadian subsidiary, we acquired a 93.8% interest in Aitken Creek Gas Storage Facility and a 100% interest in Aitken Creek North Gas Storage Facility (collectively, Aitken Creek), located in BC, Canada, for $400 million, subject to other customary closing adjustments (the Aitken Creek Acquisition). Aitken Creek is the only underground natural gas storage facility in BC and connects to all major natural gas pipelines in western Canada. The Aitken Creek Acquisition enables us to continue to meet regional energy needs and to support increasing demand for liquefied natural gas (LNG) exports. 66 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), comprised of $12.8 billion (US$9.4 billion) of cash consideration and $6.3 billion (US$4.6 billion) of assumed debt, subject to customary closing adjustments (together, the Acquisitions). If completed, the Acquisitions will create North America's largest natural gas utility platform delivering over 9 billion cubic feet (bcf) per day 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. On September 8, 2023, we closed a public offering of 102,913,500 common shares at a price of $44.70 per share for gross proceeds of $4.6 billion which is intended to finance a portion of the aggregate cash consideration payable for the Acquisitions. Refer to Financing Update for further details on the debt issuances and credit facility obtained to support the Acquisitions. Tres Palacios Holdings LLC On April 3, 2023, we acquired Tres Palacios Holdings LLC (Tres Palacios) for $451 million (US$335 million) of cash. Tres Palacios is a natural gas storage facility located in the US Gulf Coast and its infrastructure serves Texas gas-fired power generation and LNG exports, as well as Mexico pipeline exports. Tres Palacios is comprised of three natural gas storage salt caverns with a total FERC-certificated working gas capacity of approximately 35 billion bcf and also owns an integrated 62-mile natural gas header pipeline system, with eleven inter- and intrastate natural gas pipeline connections. ASSET MONETIZATION Disposition of Alliance Pipeline and Aux Sable 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 sales proceeds will fund a portion of the Acquisitions and be used for debt reduction. GAS TRANSMISSION AND MIDSTREAM PROCEEDINGS Texas Eastern Transmission The Stipulation and Agreement for Texas Eastern Transmission, LP’s (Texas Eastern) consolidated 2021 rate cases was approved by the FERC on November 30, 2022, and became effective on January 1, 2023. Texas Eastern received FERC approval on April 3, 2023 to implement the settled rates and other settlement provisions. Maritimes & Northeast Pipeline The toll settlement agreement for the Canadian portion of the Maritimes & Northeast (M&N) Pipeline (M&N Canada) expired in December 2023. M&N Canada reached a toll settlement with shippers for the effective period from January 1, 2024 to December 31, 2025. On November 28, 2023, M&N Canada filed the 2024 - 2025 toll settlement agreement with the CER for review and approval. A CER decision is expected in the first quarter of 2024. 67GAS DISTRIBUTION AND STORAGE RATE APPLICATIONSIncentive Regulation Rate Application In October 2022, Enbridge Gas Inc. (Enbridge Gas) filed its application with the Ontario Energy Board (OEB) to establish a 2024 through 2028 Incentive Regulation (IR) rate setting framework. The application initially sought approval in two phases to establish 2024 base rates (Phase 1) on a cost-of-service basis and to establish a price cap rate setting mechanism (Phase 2) to be used for the remainder of the IR term. 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. 68 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. Purchase Gas Variance The Purchase Gas Variance Account (PGVA) captures the difference between actual and forecasted natural gas prices reflected in rates. Account balances are typically recovered or refunded over a prospective 12-month period through Quarterly Rate Adjustment Mechanism (QRAM) applications. In March 2023, the April 1, 2023 QRAM application was filed and approved by the OEB, which included an adjustment to the prior rate mitigation approved as part of the July 1, 2022 QRAM. The recovery of the outstanding PGVA balance from the extended recovery period approved as part of the July 1, 2022 QRAM will now be completed by March 31, 2024. In June, September and December 2023, the July 1, 2023, October 1, 2023, and January 1, 2024 QRAM applications, respectively, were filed and approved by the OEB with no adjustments to the prior period rate mitigation plans and did not include any additional rate mitigation measures. As at December 31, 2023, Enbridge Gas' PGVA liability balance was $16 million.FINANCING UPDATEWe completed long-term debt issuances totaling US$8.5 billion and $3.9 billion during the year ended December 31, 2023, including aggregate amounts of US$2.3 billion of 10-year sustainability-linked senior notes in March 2023 and $400 million of 10-year sustainability-linked medium-term notes in May 2023. We increased our credit facilities in March 2023 by approximately $500 million. During our annual renewal process, we renewed and extended approximately $15.4 billion of our credit facilities with maturities ranging from 2024-2028. In September 2023, we obtained commitments for a US$9.4 billion senior unsecured bridge term loan credit facility to support the Acquisitions. The commitment for this facility was subsequently reduced to nil as at December 31, 2023 as a result of the September 2023 $4.6 billion equity offering, the September 2023 subordinated long-term debt issuances, and the November 2023 senior notes long-term debt issuances. In September 2023, we closed a public offering of 102,913,500 common shares at a price of $44.70 per share for gross proceeds of $4.6 billion which is intended to finance a portion of the aggregate cash consideration payable for the Acquisitions. Our 2023 financing activities have provided significant liquidity that we expect will enable us to fund our current portfolio of capital projects and acquisitions without requiring access to the capital markets for the next 12 months should market access be restricted or pricing be unattractive. Refer to Liquidity and Capital Resources . As at December 31, 2023, after adjusting for the impact of floating-to-fixed interest rate swap hedges, less than 5% of our total debt is exposed to floating rates. Refer to Part II. Item 8. Financial Statements and Supplementary Data - Note 23 - Risk Management and Financial Instruments for more information on our interest rate hedging program. 69 NORMAL COURSE ISSUER BID On January 4, 2023, the Toronto Stock Exchange (TSX) approved our normal course issuer bid (NCIB), which commenced on January 6, 2023 and expired on January 5, 2024. Our NCIB permitted us to purchase, for cancellation up to 27,938,163 of the outstanding common shares of Enbridge to an aggregate amount of up to $1.5 billion through the facilities of the TSX, the New York Stock Exchange and other designated exchanges and alternative trading systems.RESULTS OF OPERATIONSYear ended December 31, 2023 2022 2021(millions of Canadian dollars, except per share amounts) Segment earnings/(loss) before interest, income taxes and depreciation and amortization 1Liquids Pipelines 9,499 8,364 7,897 Gas Transmission and Midstream 4,264 3,126 3,671 Gas Distribution and Storage 1,592 1,827 2,117 Renewable Power Generation 149 262 508 Energy Services (37) (417) (313) Eliminations and Other 837 (1,124) 356Earnings before interest, income taxes and depreciation and amortization 116,304 12,038 14,236 Depreciation and amortization (4,613) (4,317) (3,852) Interest expense (3,812) (3,179) (2,655) Income tax expense (1,821) (1,604) (1,415) (Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests 133 65 (125) Preference share dividends (352) (414) (373) Earnings attributable to common shareholders 5,839 2,589 5,816 Earnings per common share attributable to common shareholders 2.84 1.28 2.87 Diluted earnings per common share attributable to common shareholders 2.84 1.28 2.87 1 Non-GAAP financial measures.EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERSYear ended December 31, 2023 compared with year ended December 31, 2022 Earnings attributable to common shareholders increased by $3.2 billion due to certain infrequent or other non-operating factors, primarily explained by the following: • the absence in 2023 of a goodwill impairment of $2.5 billion relating to our Gas Transmission reporting unit; • a non-cash, net unrealized derivative fair value gain of $1,127 million ($856 million after-tax) in 2023, compared with a net unrealized loss of $1,246 million ($950 million after-tax) in 2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange, interest rate, and commodity risks; • the absence in 2023 of: an asset impairment loss of $227 million ($173 million after-tax) to our Magic Valley Wind Farm (Magic Valley); an asset impairment loss of $183 million ($137 million after-tax) on the US and Canadian components of the interstate pipeline within the North Dakota System of our Bakken System, an impairment of $44 million ($34 million after-tax) for lease assets due to office relocation plans, and an asset impairment loss of $40 million ($30 million after-tax) relating to MacKay River line within our Alberta Regional Oil Sands System; 70 • a gain of $151 million ($129 million after-tax) and a deferred tax adjustment of $69 million were recognized as a result of Southern Lights Pipeline's (Southern Lights) discontinuation of regulatory accounting; • the absence in 2023 of a transaction cost of $114 million in relation to our investment purchase in the Woodfibre LNG project; • a deferred income tax recovery of $104 million related to a tax adjustment on asset impairments; • a non-cash, net unrealized gain of $73 million ($55 million after-tax) in 2023, compared with a net unrealized loss of $27 million ($21 million after-tax) in 2022, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as to manage the exposure to movements in commodity prices; • the receipt of a litigation claim settlement of $68 million ($52 million after-tax) in 2023; and • a non-cash, net unrealized gain of $35 million ($33 million after-tax) in 2023, compared with a net unrealized loss of $25 million ($22 million after-tax) in 2022, reflecting changes in the mark-to-market value of equity fund investments held by our wholly-owned captive insurance subsidiaries. The factors above were partially offset by: • the absence in 2023 of a gain of $1,076 million ($732 million after-tax) on the closing of the joint venture merger transaction with Phillips 66 (P66) realigning our indirect economic interests in Gray Oak Pipeline LLC (Gray Oak) and DCP Midstream, LP (DCP); • a realized loss of $638 million ($479 million after-tax) due to termination of foreign exchange hedges, as foreign exchange risks inherent within the Competitive Toll Settlement (CTS) framework are not present in the negotiated Mainline tolling agreement; • an impairment loss of $261 million ($20 million after-tax and net of noncontrolling interest) to our Chapman Ranch wind facilities; • an impairment of $281 million ($232 million after-tax) recognized to certain capital projects, capital costs and pension balances in the fourth quarter of 2023 as a result of the OEB's Phase 1 Decision on Enbridge Gas' application; • a deferred tax adjustment of $120 million as a result of deregulation of parts of the Canadian Mainline including Line 9 and L3R; • a provision adjustment and settlement of $124 million ($95 million after-tax) related to a litigation matter; • the absence in 2023 of a gain of $118 million ($89 million after-tax) on Texas Eastern recorded to reflect a settlement with a transportation customer undergoing bankruptcy; • an asset retirement loss of $86 million ($65 million after-tax) related to our Alberta Regional Oil Sands System; • an impairment loss of $82 million ($63 million after-tax) to certain Offshore equity investments in our Gas Transmission and Midstream segment; and • transaction costs of $31 million ($24 million after-tax) incurred as a result of the Acquisitions.The non-cash, unrealized derivative fair value gains and losses discussed above generally arise as a result of our comprehensive economic hedging program to mitigate foreign exchange, interest rate and commodity price risks. This program creates volatility in reported short-term earnings through the recognition of unrealized non-cash gains and losses on derivative instruments used to hedge these risks. Over the long-term, we believe our hedging program supports the reliable cash flows and dividend growth upon which our investor value proposition is based.71 After taking into consideration the factors above, the remaining $51 million increase in earnings attributable to common shareholders is primarily explained by the following significant business factors: • higher contributions from the Mainline System in our Liquids Pipelines segment driven by increased volumes due to increased crude demand, net of a lower L3R surcharge and lower Mainline System tolls as a result of revised interim tolls effective July 1, 2023; • higher contributions from our Liquids Pipelines segment due to increased ownership of the Gray Oak Pipeline and Cactus II Pipeline acquired in the second half of 2022 and the Enbridge Ingleside Energy Center (EIEC) due to higher demand; • the recognition of revenues in our Gas Transmission and Midstream segment attributable to the Texas Eastern rate case settlement; • higher distribution charges at our Gas Distribution and Storage segment resulting from increases in rates and customer base as well as higher demand in the contract market; • higher contributions from our Energy Services segment primarily due to the expiration of transportation commitments and favorable margins due to less pronounced market structure backwardation; and • the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, as compared to 2022; partially offset by • a reduction in earnings from our Gas Transmission and Midstream segment primarily due to our decreased interest in DCP as a result of a joint venture merger transaction with P66 that closed in the third quarter of 2022; • higher operating and administrative costs in our Gas Transmission and Midstream and Gas Distribution and Storage segments; • lower commodity prices impacting the DCP and Aux Sable joint ventures in our Gas Transmission and Midstream segment; • higher interest expense primarily due to higher interest rates and higher average principal; and • higher depreciation and amortization expense as a result of several projects placed into service in the second half of 2022.REVENUES We generate revenues from three primary sources: transportation and other services, gas distribution sales and commodity sales.Transportation and other services revenues of $19.8 billion, $18.5 billion and $16.2 billion for the years ended December 31, 2023, 2022 and 2021, respectively, were earned from our crude oil and natural gas pipeline transportation businesses and also include power generation revenues from our portfolio of renewable and power generation assets. For our transportation assets operating under market-based arrangements, revenues are driven by volumes transported and the corresponding tolls for transportation services. For assets operating under take-or-pay contracts, revenues reflect the terms of the underlying contract for services or capacity. For rate-regulated assets, revenues are charged in accordance with tolls established by the regulator and, in most cost-of-service based arrangements, are reflective of our cost to provide the service plus a regulator-approved rate of return. Gas distribution sales revenues of $4.8 billion, $5.7 billion and $4.0 billion for the years ended December 31, 2023, 2022 and 2021, respectively, were recognized in a manner consistent with the underlying rate-setting mechanism mandated by the regulator. Revenues generated by the gas distribution businesses are primarily driven by volumes delivered, which vary with weather and customer composition and utilization, as well as regulator-approved rates. The cost of natural gas is passed through to customers through rates and does not ultimately impact earnings due to its flow-through nature. 72 Commodity sales revenues of $19.0 billion, $29.2 billion and $26.9 billion for the years ended December 31, 2023, 2022 and 2021, respectively, were generated primarily through our Energy Services operations. Energy Services includes the purchase and sale of crude oil, natural gas, power and NGL to generate a margin, which is typically a small fraction of gross revenue. Sales revenue generated from these operations reflect activity levels which are driven by differences in commodity prices between locations, grades and points in time, rather than on absolute prices. Any residual commodity margin risk is closely monitored and managed. Revenues from these operations depend on activity levels, which vary from year-to-year depending on market conditions and commodity prices.Our revenues also include changes in unrealized derivative fair value gains and losses related to foreign exchange and commodity price contracts used to manage exposures from movements in foreign exchange rates and commodity prices. The mark-to-market accounting creates volatility and impacts the comparability of revenues in the short-term, but we believe over the long-term, the economic hedging program supports reliable cash flows. BUSINESS SEGMENTS LIQUIDS PIPELINESYear ended December 31, 2023 2022 2021(millions of Canadian dollars)Earnings before interest, income taxes and depreciation and amortization 9,499 8,364 7,897 Year ended December 31, 2023 compared with year ended December 31, 2022 EBITDA was positively impacted by $500 million due to certain infrequent or other non-operating factors, primarily explained by the following: • a non-cash, net unrealized gain of $607 million in 2023, compared with a net unrealized loss of $183 million in 2022, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks; • a gain of $151 million recognized as a result of Southern Lights' discontinuation of regulatory accounting; • the absence in 2023 of: a total asset impairment loss of $183 million on the US and Canadian components of the interstate pipeline within the North Dakota System of our Bakken System, and an asset impairment loss of $40 million relating to MacKay River line within our Alberta Regional Oil Sands System, partially offset by an asset retirement loss in 2023 of $86 million related to our Alberta Regional Oil Sands System; and • the receipt of a litigation claim settlement of $68 million in 2023; partially offset by • a realized loss of $638 million due to termination of foreign exchange hedges, as foreign exchange risks inherent within the CTS framework are not present in the negotiated Mainline tolling agreement. 73 After taking into consideration the factors above, the remaining $635 million increase is primarily explained by the following significant business factors: • higher Mainline System ex-Gretna average throughput of 3.1 million barrels per day (mmbpd) in 2023 as compared to 3.0 mmbpd in 2022, and higher Line 9 deliveries to eastern Canada driven by higher crude demand, net of a lower L3R surcharge and lower Mainline System tolls as a result of revised interim Mainline tolls effective July 1, 2023; • higher contributions from the Gulf Coast and Mid-Continent System due primarily to increased ownership of Gray Oak Pipeline and Cactus II Pipeline acquired in the second half of 2022 and the EIEC due to higher demand; and • the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, as compared to 2022; partially offset by • higher power costs as a result of increased volumes and power prices. GAS TRANSMISSION AND MIDSTREAM Year ended December 31, 2023 2022 2021(millions of Canadian dollars)Earnings before interest, income taxes and depreciation and amortization 4,264 3,126 3,671 Year ended December 31, 2023 compared with year ended December 31, 2022 EBITDA was positively impacted by $1.2 billion due to certain infrequent or other non-operating factors primarily explained by the following: • the absence in 2023 of a goodwill impairment of $2.5 billion; partially offset by • the absence in 2023 of: a gain of $1,076 million on the closing of the joint venture merger transaction with P66 realigning our effective economic interests in Gray Oak and DCP, and a gain of $118 million on Texas Eastern recorded for a customer bankruptcy settlement; • a provision adjustment and settlement of $124 million related to a litigation matter; and • an impairment loss of $82 million to certain Offshore equity investments. After taking into consideration the factors above, we saw a $19 million decrease, primarily explained by the following significant business factors: • a reduction in earnings from our investment in DCP as a result of our decreased interest due to the joint venture merger transaction with P66 that closed during the third quarter of 2022; • higher operating and administrative costs; • lower commodity prices impacting our DCP and Aux Sable joint ventures; • lower AECO-Chicago basis differential impacting our investment in Alliance Pipeline, partially offset by • the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, as compared to 2022; • favorable contracting on our US Gas Transmission and Storage assets; • the recognition of revenues attributable to the Texas Eastern rate case settlement effective for 2023; and • contributions from the Tres Palacios acquisition in the second quarter of 2023 and Aitken Creek in the fourth quarter of 2023. 74GAS DISTRIBUTION AND STORAGEYear ended December 31, 2023 2022 2021(millions of Canadian dollars)Earnings before interest, income taxes and depreciation and amortization 1,592 1,827 2,117 Year ended December 31, 2023 compared with year ended December 31, 2022 EBITDA was negatively impacted by $252 million due to an impairment of $281 million recognized to certain capital projects, capital costs and pension balances in the fourth quarter of 2023 as a result of the OEB's Phase 1 Decision. After taking into consideration the factors above, the remaining $17 million increase is primarily explained by the following significant business factors: • higher distribution charges resulting from increases in rates and customer base, as well as higher demand in the contract market; partially offset by • when compared with the normal weather forecast embedded in rates, warmer than normal weather in 2023 negatively impacted 2023 EBITDA by approximately $86 million year over year; and • higher operating and administrative costs primarily due to higher pension related costs.RENEWABLE POWER GENERATIONYear ended December 31, 2023 2022 2021(millions of Canadian dollars)Earnings before interest, income taxes and depreciation and amortization 149 262 508 Year ended December 31, 2023 compared with year ended December 31, 2022 EBITDA was negatively impacted by $122 million due to certain infrequent or non-operating factors, primarily explained by: • an impairment loss of $261 million to Chapman Ranch wind facilities, partially offset by the absence in 2023 of an impairment loss of $227 million to Magic Valley; and • a non-cash, net unrealized loss of $72 million in 2023, compared with a net unrealized gain of $8 million in 2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage commodity price risks. After taking into consideration the negative factors above, the remaining $9 million increase is primarily explained by the following significant business factors: • fees earned on certain wind and solar development contracts; • higher contribution from the Hohe See and Albatros Offshore Wind Facilities as a result of the November 2023 acquisition of an additional 24.45% interest in these facilities; and • contributions from the Saint-Nazaire Offshore Wind Project, which reached full operating capacity in December 2022; partially offset by • lower energy pricing at European offshore wind facilities; and • weaker wind resources at Canadian and US onshore wind facilities. 75 ENERGY SERVICES Year ended December 31, 2023 2022 2021 (millions of Canadian dollars) Loss before interest, income taxes and depreciation and amortization (37) (417) (313) EBITDA from Energy Services is dependent on market conditions and results achieved in one period may not be indicative of results to be achieved in future periods. Year ended December 31, 2023 compared with year ended December 31, 2022 EBITDA was positively impacted by $117 million due to certain non-operating factors, primarily explained by a non-cash, net unrealized gain of $73 million in 2023, compared with a net unrealized loss of $27 million in 2022, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as to manage the exposure to movements in commodity prices. After taking into consideration the factor above, the remaining $263 million increase is primarily explained by the following significant business factors: • expiration of certain less attractive transportation commitments; • more favorable margins realized on facilities where we hold capacity obligations and storage opportunities as compared to 2022; and • less pronounced market structure backwardation as compared to 2022.ELIMINATIONS AND OTHERYear ended December 31, 2023 2022 2021(millions of Canadian dollars)Earnings/(loss) before interest, income taxes and depreciation and amortization 837 (1,124) 356 Eliminations and Other includes operating and administrative costs that are not allocated to business segments, the impact of foreign exchange hedge settlements and the activities of our wholly-owned captive insurance subsidiaries. Eliminations and Other also includes the impact of new business development activities and corporate investments. Year ended December 31, 2023 compared with year ended December 31, 2022 EBITDA was positively impacted by $1.9 billion due to certain infrequent or non-operating factors, primarily explained by: • a non-cash, net unrealized gain of $623 million in 2023, compared with a net unrealized loss of $1,090 million in 2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk; • the absence in 2023 of: $114 million of transaction costs in relation to our investment purchase in the Woodfibre LNG Project, and an impairment of $44 million for lease assets due to office relocation plans; and • a non-cash, net unrealized gain of $35 million in 2023, compared with a net unrealized loss of $25 million in 2022, reflecting changes in the mark-to-market value of equity fund investments held by our wholly-owned captive insurance subsidiaries; partially offset by • transaction costs of $31 million incurred as a result of the Acquisitions. After taking into consideration the non-operating factors above, we saw a $18 million increase in EBITDA that is primarily explained by higher investment income from the pre-funding of the Acquisitions. 76GROWTH PROJECTS - COMMERCIALLY SECURED PROJECTSThe following table summarizes the status of our significant commercially secured projects, organized by business segment: Enbridge's Ownership Interest Estimated Capital Cost 1Expenditures to Date 2 Status 2 Expected In-Service Date (Canadian dollars, unless stated otherwise)GAS TRANSMISSION AND MIDSTREAM 1. Texas Eastern Venice Extension Project 3 100 % US$477 million US$170 million Under construction 2023 - 2024 2. Texas Eastern Modernization 100 % US$394 million US$37 million Pre-construction 2025 - 2026 3. T-North Expansion 100 % $1.2 billion $70 million Pre-construction 2026 4. Rio Bravo Pipeline 5 100 % US$1.2 billion US$66 million Pre-construction 2026 5. Woodfibre LNG 6 30 % US$1.5 billion US$310 million Under construction 2027 6. T-South Expansion 4 100 % $4.0 billion $67 million Pre-construction 2028RENEWABLE POWER GENERATION7. Fécamp Offshore Wind 7 17.9 % $692 million $528 million Under construction 1Q-2024 (€471 million) (€362 million) 8. Calvados Offshore Wind 8 21.7 % $954 million $307 million Under construction 2025 (€645 million) (€214 million) 9. Fox Squirrel Solar 50 % US$406 million US$152 million Under construction 2023-20241 These amounts are estimates and are subject to upward or downward adjustment based on various factors. Where appropriate, the amounts reflect our share of joint venture projects.2 Expenditures to date and status of the project are determined as at December 31, 2023. 3 Includes the $37 million Gator Express Project placed into service in August 2023. Total estimated capital cost consists of the reversal and expansion of Texas Eastern's Line 40 expected to be completed in 2024. 4 Capital cost estimates will be updated prior to filing the regulatory applications. 5 Rio Grande LNG has reached a final investment decision for three liquefaction trains. Current estimated capital cost is based on two liquefaction trains and an update to the estimated capital cost is expected to be provided in 2024. 6 Our equity contribution is approximately US$893 million, with the remainder financed through non-recourse project level debt. Capital cost estimates will be updated prior to the 60% engineering milestone, at which point Enbridge's preferred return will be set. 7 Our equity contribution is $103 million, with the remainder financed through non-recourse project level debt. 8 Our equity contribution is $181 million, with the remainder financed through non-recourse project level debt. Risks related to the development and completion of growth projects are described under Part I. Item 1A. Risk Factors. GAS TRANSMISSION AND MIDSTREAM The following commercially secured growth projects are currently in various stages of construction: • Texas Eastern Venice Extension Project – A reversal and expansion of Texas Eastern’s Line 40 from its existing New Roads compressor station to a new delivery point with the proposed Gator Express pipeline just south of Texas Eastern’s Larose compressor station. The project is expected to deliver 1.5 billion cubic feet per day (bcf/d) of natural gas to Venture Global Plaquemines LNG, LLC’s LNG export facility located in Plaquemines Parish, Louisiana and is underpinned by long-term take or pay contracts. 77 • Texas Eastern Modernization – This program is the modernization of compression facilities in Pennsylvania and New Jersey to increase safety and reliability and reduce associated greenhouse gas emissions at multiple sites on our Texas Eastern system. The program will be completed in stages over a period of years beginning in 2024. • T-North Expansion – An expansion of Westcoast Energy Inc.'s (Westcoast) BC Pipeline in northern BC that includes pipeline looping, additional compressor units and other ancillary station modifications to support 535 million cubic feet per day (mmcf/d) of additional capacity. The project will be underpinned by a cost-of-service commercial model with a target in-service date of 2026. On January 8, 2024, we filed the regulatory application with the CER. • Rio Bravo Pipeline – In July 2023, the Rio Grande LNG export facility, owned by NextDecade Corporation (NextDecade), reached a final investment decision. As a result, the construction on our previously announced Rio Bravo Pipeline project is anticipated to proceed after obtaining necessary regulatory approvals. The first phase of the Rio Bravo Pipeline is designed to transport 2.6 bcf/d of natural gas feedstock to NextDecade's Rio Grande LNG export facility in the Port of Brownsville, Texas. The project is expected to achieve commercial operations in 2026. • Woodfibre LNG Project – Construction of liquefaction and floating storage facilities in Squamish, BC, as well as an expansion of the BC Pipeline System. The project is expected to be placed into service in 2027. • T-South Expansion – An expansion of Westcoast's BC Pipeline's T-South section that includes pipeline looping, additional compressor units and other ancillary station modifications to support 300 mmcf/d of additional capacity. The project is expected to be placed in service in 2028 and will be underpinned by a cost-of-service commercial model.RENEWABLE POWER GENERATIONThe following commercially secured growth projects are expected to be placed into service from 2023 to 2025: • Fécamp Offshore Wind Project – An offshore wind project that will be comprised of 71 wind turbines located off the northwest coast of France and is expected to generate approximately 500 megawatts (MW). Project revenues are underpinned by a 20-year fixed price power purchase agreement (PPA). • Calvados Offshore Wind Project – An offshore wind project located off the northwest coast of France that is expected to generate approximately 448 MW. Project revenues are underpinned by a 20-year fixed price PPA. • Fox Squirrel Solar – A fully contracted, ground-mounted solar facility in Ohio with expected installed capacity of approximately 577 MW. The initial phase successfully commenced operations in December 2023. We plan to invest in the following phases in 2024, assuming certain conditions are met. Project revenues are underpinned by a 20-year fixed price PPA. 78LIQUIDITY AND CAPITAL RESOURCESThe maintenance of financial strength and flexibility is fundamental to our growth strategy, particularly in light of the significant number and size of capital projects and acquisitions currently secured or under development. Access to timely funding from capital markets could be limited by factors outside our control including, but not limited to, financial market volatility resulting from economic and political events both inside and outside North America. To mitigate such risks, we actively manage financial plans and strategies to ensure we maintain sufficient liquidity to meet routine operating and future capital requirements. In the near term, we generally expect to utilize cash from operations together with commercial paper issuance and/or credit facility draws and the proceeds of capital market offerings to fund liabilities as they become due, finance capital expenditures, fund debt retirements and pay common and preference share dividends. We target maintaining sufficient liquidity through the use of committed credit facilities with a diversified group of banks and financial institutions to enable us to fund all anticipated requirements for approximately one year without accessing the capital markets. Material contractual obligations arising in the normal course of business primarily consist of long-term contracts, annual debt maturities and related interest obligations, rights-of-way and leases. See Part II. Item 8. Financial Statements and Supplementary Data - Note 17 - Debt and Note 26 - Leases for amounts outstanding at December 31, 2023, related to debt and leases. Long-term contracts are contracts that we have signed for the purchase of services, pipe and other materials totaling $8.9 billion which are expected to be paid over the next five years. Remaining long-term contracts primarily consist of the following purchase obligations: firm capacity payments for natural gas and crude oil transportation and storage contracts, natural gas purchase commitments, service and product purchase obligations and power commitments. Our financing plan is regularly updated to reflect evolving capital requirements and financial market conditions and identifies a variety of potential sources of debt and equity funding alternatives, including reinstatement of our dividend reinvestment and share purchase plan or at-the-market equity issuances.CAPITAL MARKET ACCESSWe ensure ready access to capital markets, subject to market conditions, through maintenance of shelf prospectuses that allow for issuance of long-term debt, equity and other forms of long-term capital when market conditions are attractive. In accordance with our funding plan, we completed the following long-term debt issuances totaling US$8.5 billion and $3.9 billion in 2023: Entity Issuance date Type of issuance Amount (in millions of Canadian dollars, unless stated otherwise) Enbridge Inc. March 2023 Sustainability-linked senior notes US$2,300 Enbridge Inc. March 2023 Senior notes US$700 Enbridge Inc. May 2023 Medium-term notes $1,100 Enbridge Inc. May 2023 Sustainability-linked medium-term notes $400 Enbridge Inc. September 2023 Fixed-to-fixed subordinated notes US$2,000 Enbridge Inc. September 2023 Fixed-to-fixed subordinated notes $1,000 Enbridge Inc. November 2023 Senior notes US$3,500 Enbridge Gas Inc. October 2023 Medium-term notes $1,000 Enbridge Pipelines Inc. August 2023 Medium-term notes $350 79 Credit Facilities, Ratings and Liquidity To ensure ongoing liquidity and to mitigate the risk of capital market disruption, we maintain ready access to funds through committed bank credit facilities and actively manage our bank funding sources to optimize pricing and other terms. The following table provides details of our committed credit facilities, inclusive of term loans, at December 31, 2023:Maturity 1Total Facilities Draws 2Available (millions of Canadian dollars)Enbridge Inc. 2024-2028 8,876 3,177 5,699 Enbridge (U.S.) Inc. 2025-2028 8,373 670 7,703 Enbridge Pipelines Inc. 2025 2,000 449 1,551 Enbridge Gas Inc. 2025 2,500 400 2,100 Total committed credit facilities 21,749 4,696 17,0531 Maturity date is inclusive of the one-year term out option for certain credit facilities. 2 Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.In March 2023, Enbridge Gas increased its 364-day extendible credit facility from $2.0 billion to $2.5 billion and in July 21, 2023, the facility's maturity date was extended to July 2025, which includes a one-year term out provision from July 2024. In July 2023, Enbridge Pipelines Inc. extended the maturity date of its 364-day extendible credit facility to July 2025, which includes a one-year term out provision from July 2024. In July 2023, we renewed approximately $6.8 billion of our 364-day extendible credit facilities, extending the maturity dates to July 2025, which includes a one-year term out provision from July 2024. We also renewed approximately $7.6 billion of our five-year credit facilities, extending the maturity dates to July 2028. Further, we extended our three-year credit facilities, extending the maturity dates to July 2026. In September 2023, we obtained commitments for a US$9.4 billion senior unsecured bridge term loan credit facility to support the Acquisitions. The commitment for this facility was subsequently reduced to nil as at December 31, 2023 as a result of the September 2023 $4.6 billion equity offering, the September 2023 subordinated long-term debt issuances, and the November 2023 senior notes long-term debt issuances. In addition to the committed credit facilities noted above, we maintain $1.1 billion of uncommitted demand letter of credit facilities, of which $572 million was unutilized as at December 31, 2023. As at December 31, 2022, we had $1.3 billion of uncommitted demand letter of credit facilities, of which $689 million was unutilized. As at December 31, 2023, our net available liquidity totaled $23.0 billion (2022 - $10.0 billion), consisting of available credit facilities of $17.1 billion (2022 - $9.1 billion) and unrestricted Cash and cash equivalents of $5.9 billion (2022 - $861 million) as reported in the Consolidated Statements of Financial Position. Our credit facility agreements and term debt indentures include standard events of default and covenant provisions, whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at December 31, 2023, we were in compliance with all debt covenants and expect to continue to comply with such covenants. 80 Cash flow growth, ready access to liquidity from diversified sources and a stable business model have enabled us to manage our credit profile. We actively monitor and manage key financial metrics with the objective of sustaining investment grade credit ratings from the major credit rating agencies and ongoing access to bank funding and term debt capital on attractive terms. In 2023, our credit ratings with DBRS Morningstar, Fitch Ratings, Moody's Investor Services, Inc. and Standard & Poor's were all affirmed. Key measures of financial strength that are closely managed include the ability to service debt obligations from operating cash flow and the ratio of debt to EBITDA. There are no material restrictions on our cash. Total Restricted cash of $84 million, as reported in the Consolidated Statements of Financial Position, primarily includes cash collateral and future pipeline abandonment costs collected and held in trust. Cash and cash equivalents held by certain subsidiaries may not be readily accessible for alternative use by us. Excluding current maturities of long-term debt, as at December 31, 2023 and 2022, we had a positive and negative working capital positions of $3.0 billion and $2.1 billion, respectively. In 2023, the major contributing factor to the positive working capital position was the increase in cash associated with pre-funding of the Acquisitions. In 2022, the major contributing factor to the negative working capital position was the current liabilities associated with our growth capital program.SOURCES AND USES OF CASHYear ended December 31, 2023 2022 2021(millions of Canadian dollars)Operating activities 14,201 11,230 9,256 Investing activities (6,043) (5,270) (10,657) Financing activities (2,864) (5,428) 1,236 Effect of translation of foreign denominated cash and cash equivalents and restricted cash (216) 55 (5) Net change in cash and cash equivalents and restricted cash 5,078 587 (170) Significant sources and uses of cash for the years ended December 31, 2023 and 2022 are summarized below:Operating ActivitiesTypically, the primary factors impacting cash provided by operating activities year-over-year include changes in our operating assets and liabilities in the normal course due to various factors, including the impact of fluctuations in commodity prices and activity levels on working capital within our business segments, the timing of tax payments, as well as timing of cash receipts and payments generally. Refer to Part II. Item 8. Financial Statements and Supplementary Data - Note 28. Changes in Operating Assets and Liabilities. Cash provided by operating activities is also impacted by changes in earnings and certain infrequent or other non-operating factors, as discussed under Results of Operations, as well as Distributions from equity investments.Investing ActivitiesCash used in investing activities primarily relates to capital expenditures to execute our capital program, which is further described in Growth Projects - Commercially Secured Projects . The timing of project approval, construction and in-service dates impacts the timing of cash requirements. Cash used in investing activities is also impacted by acquisitions and dispositions as discussed under Recent Developments, and changes in contributions to, and distributions from, our equity investments. 81 A summary of additions to property, plant and equipment for the years ended December 31, 2023, 2022 and 2021 is set out below: Year ended December 31, 2023 2022 2021 (millions of Canadian dollars) Liquids Pipelines 1,158 1,418 4,051 Gas Transmission and Midstream 1,890 1,647 2,353 Gas Distribution and Storage 1,451 1,499 1,343 Renewable Power Generation 100 50 16 Energy Services — — 1 Eliminations and Other 55 33 54 Total capital expenditures 4,654 4,647 7,8182023The increase in cash used in investing activities primarily resulted from the following factors: • the absence in 2023 of the proceeds received from the completion of a joint venture merger transaction for DCP Midstream, LLC in August 2022; and • higher cash outflows related to acquisitions in 2023 when compared to 2022. The factors above were partially offset by higher distributions in 2023 mainly related to our investment in NEXUS Gas Transmission, LLC. 2022The decrease in cash used in investing activities primarily resulted from the following factors:• lower capital expenditures due to the US L3R program that was placed into service in the fourth quarter of 2021; • lower cash outflows related to acquisitions in 2022 when compared to 2021; and • proceeds received from the completion of a joint venture merger transaction for DCP Midstream LLC in August 2022. The factors above were partially offset by: • the absence in 2022 of proceeds received from dispositions in 2021 related to sale of our interest in Noverco Inc. in December 2021; and • increased investments held by our wholly-owned captive insurance subsidiaries.Financing ActivitiesCash used in financing activities primarily relates to issuances and repayments of external debt, as well as transactions with our common and preference shareholders relating to dividends, share issuances, share redemptions and common share repurchases under our NCIB. Cash used in financing activities is also impacted by changes in distributions to, and contributions from, noncontrolling interests. 2023 The decrease in cash used in financing activities primarily resulted from the following factors: • higher long-term debt issuances in 2023 when compared to the same period in 2022; • our public offering of common shares, which closed on September 8, 2023, resulting in the issuance of 102,913,500 common shares at a price of $44.70 per share for gross proceeds of $4.6 billion, which is intended to finance a portion of the aggregate cash consideration payable for the Acquisitions; and • the absence in 2023 of the redemption of Preference Shares, Series 17 and Series J in the first and second quarters of 2022, respectively. 82 The factors above were partially offset by: • higher net commercial paper and credit facility repayments in 2023 when compared to the same period in 2022; • net repayments of short-term borrowings in 2023 when compared to net issuances in 2022; • the absence in 2023 of proceeds received from the sale of a non-operating interest in seven pipelines from our Regional Oil Sands System in October 2022; • higher long-term debt repayments in 2023 when compared to the same period in 2022; and • increased common share dividend payments primarily due to the increase in our common share dividend rate and an increase in the number of common shares outstanding. 2022The increase in cash used in financing activities primarily resulted from the following factors:• net commercial paper and credit facility repayments in 2022 when compared to draws in 2021; • higher long-term debt repayments along with lower long-term debt issuances in 2022 when compared to 2021; • the redemption of Preference Shares, Series 17 and Series J in the first and second quarters of 2022, respectively; • the repurchase and cancellation of 2,737,965 common shares under our NCIB for approximately $151 million in 2022; and • increased common share dividend payments primarily due to the increase in our common share dividend rate. The factors above were partially offset by: • proceeds received from the sale of a non-operating interest in seven pipelines from our Regional Oil Sands System in October 2022; and • the absence in 2022 of the redemption of Westcoast's preferred shares in the first quarter of 2021. OFF-BALANCE SHEET ARRANGEMENTSWe enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties and can include financial guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. Please see Part II. Item 8. Financial Statements and Supplementary Data - Note 31 - Guarantees for further discussion of guarantee arrangements.We do not have material off-balance sheet financing entities or structures, except for guarantee arrangements and financings entered into for our equity investments. For additional information on these commitments, please refer to Part II. Item 8. Financial Statements and Supplementary Data - Note 30 - Commitments and Contingencies and Note 12 - Variable Interest Entities.We do not have material off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.83OUTSTANDING PREFERENCE SHARES Characteristics of our outstanding preference shares are as follows:Dividend Rate Dividend 1 Per Share Base Redemption Value 2 Redemption and Conversion Option Date 2,3 Right to Convert Into 3,4(Canadian dollars unless otherwise stated)Preference Shares, Series A 5.50 % $1.37500 $25 — — Preference Shares, Series B 5.20 % $1.30052 $25 June 1, 2027 Series C Preference Shares, Series D 5 5.41 % $1.35300 $25 March 1, 2028 Series E Preference Shares, Series F 6 5.54 % $1.38452 $25 June 1, 2028 Series G Preference Shares, Series G 7 6.96 % $1.90704 $25 June 1, 2028 Series F Preference Shares, Series H 8 6.11 % $1.52800 $25 September 1, 2028 Series I Preference Shares, Series I 9 7.19 % $1.81004 $25 September 1, 2028 Series H Preference Shares, Series L 5.86 % US$1.46448 US$25 September 1, 2027 Series M Preference Shares, Series N 6.70 % $1.67400 $25 December 1, 2028 Series O Preference Shares, Series P 4.38 % $1.09476 $25 March 1, 2024 Series Q Preference Shares, Series R 4.07 % $1.01825 $25 June 1, 2024 Series S Preference Shares, Series 1 10 6.70 % US$1.67592 US$25 June 1, 2028 Series 2 Preference Shares, Series 3 3.74 % $0.93425 $25 September 1, 2024 Series 4 Preference Shares, Series 5 5.38 % US$1.34383 US$25 March 1, 2024 Series 6 Preference Shares, Series 7 4.45 % $1.11224 $25 March 1, 2024 Series 8 Preference Shares, Series 9 4.10 % $1.02424 $25 December 1, 2024 Series 10 Preference Shares, Series 11 3.94 % $0.98452 $25 March 1, 2025 Series 12 Preference Shares, Series 13 3.04 % $0.76076 $25 June 1, 2025 Series 14 Preference Shares, Series 15 2.98 % $0.74576 $25 September 1, 2025 Series 16 Preference Shares, Series 19 11 6.21 % $1.55300 $25 March 1, 2028 Series 20 1 The holder is entitled to receive a fixed cumulative quarterly preferential dividend, as declared by the Board of Directors. With the exception of Preference Shares, Series A, such fixed dividend rate resets every five years beginning on the initial Redemption and Conversion Option Date. Preference Shares, Series G and I contain a feature where the dividend rate resets on a quarterly basis. The Preference Shares, Series 19 contain a feature where the fixed dividend rate, when reset every five years, will not be less than 4.90%. No other series of preference shares has this feature.2 Preference Shares, Series A may be redeemed any time at our option. For all other series of preference shares, we may at our option, redeem all or a portion of the outstanding preference shares for the Per Share Base Redemption Value plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter. 3 The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on a one-for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an ascribed issue price equal to the Per Share Base Redemption Value.4 With the exception of Preference Shares, Series A, after the Redemption and Conversion Option Date, holders may elect to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/number of days in year) x three month Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q), 2.5% (Series S), 2.4% (Series 4), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7% (Series 16), or 3.2% (Series 20); or US$25 x (number of days in quarter/number of days in year) x three month US Government treasury bill rate + 3.2% (Series M), 3.1% (Series 2), or 2.8% (Series 6). 5 The quarterly dividend per share paid on Preference Shares, Series D was increased to $0.33825 from $0.27875 on March 1, 2023 due to reset of the annual dividend on March 1, 2023. 6 The quarterly dividend per share paid on Preference Shares, Series F was increased to $0.34613 from $0.29306 on June 1, 2023 due to reset of the annual dividend on June 1, 2023. 7 On June 1, 2023, 1,827,695 of the outstanding Preference Shares, Series F were converted into Preference Shares, Series G. 8 The quarterly dividend per share paid on Preference Shares, Series H was increased to $0.38200 from $0.27350 on September 1, 2023 due to reset of the annual dividend on September 1, 2023. 9 On September 1, 2023, 2,350,602 of the outstanding Preference Shares, Series H were converted into Preference Shares, Series I. 10 The quarterly dividend per share paid on Preference Shares, Series 1 was increased to US$0.41898 from US$0.37182 on June 1, 2023 due to reset of the annual dividend on June 1, 2023. 11 The quarterly dividend per share paid on Preference Shares, Series 19 was increased to $0.38825 from $0.30625 on March 1, 2023 due to reset of the annual dividend on March 1, 2023. 84DIVIDENDSWe have paid common share dividends in every year since we became a publicly traded company in 1953. In November 2023, we announced a 3.1% increase in our quarterly dividend to $0.9150 per common share, or $3.66 annualized, effective with the dividend payable on March 1, 2024, thereby declaring a dividend increase for 29 straight years. For the years ended December 31, 2023 and 2022, total dividends paid were $7.3 billion and $7.0 billion, respectively, all of which were paid in cash and reflected in Cash Flows from Financing Activities in the Consolidated Statements of Cash Flows . On November 28, 2023, our Board of Directors declared the following quarterly dividends. All dividends are payable on March 1, 2024 to shareholders of record on February 15, 2024.Dividend per share Common Shares 1$0.91500 Preference Shares, Series A $0.34375 Preference Shares, Series B $0.32513 Preference Shares, Series D $0.33825 Preference Shares, Series F $0.34613Preference Shares, Series G 2$0.47676 Preference Shares, Series H $0.38200Preference Shares, Series I 3$0.45251 Preference Shares, Series L US$0.36612 Preference Shares, Series N 4$0.41850Preference Shares, Series P $0.27369 Preference Shares, Series R $0.25456 Preference Shares, Series 1 US$0.41898 Preference Shares, Series 3 $0.23356 Preference Shares, Series 5 US$0.33596 Preference Shares, Series 7 $0.27806 Preference Shares, Series 9 $0.25606 Preference Shares, Series 11 $0.24613 Preference Shares, Series 13 $0.19019 Preference Shares, Series 15 $0.18644 Preference Shares, Series 19 $0.38825 1 The quarterly dividend per common share was increased 3.1% to $0.9150 from $0.8875, effective March 1, 2024 . 2 The quarterly dividend per share paid on Preference Shares, Series G was increased to $0.47676 from $0.47245 on December 1, 2023 due to reset on a quarterly basis. 3 The quarterly dividend per share paid on Preference Shares, Series I was increased to $0.45251 from $0.44814 on December 1, 2023 due to reset on a quarterly basis following the date of issuance. 4 The quarterly dividend per share paid on Preference Shares, Series N was increased to $0.41850 from $0.31788 on December 1, 2023 due to reset of the annual dividend on December 1, 2023. 85SUMMARIZED FINANCIAL INFORMATIONOn January 22, 2019, Enbridge entered into supplemental indentures with its wholly-owned subsidiaries, Spectra Energy Partners, LP (SEP) and Enbridge Energy Partners, L.P. (EEP) (the Partnerships), pursuant to which Enbridge fully and unconditionally guaranteed, on a senior unsecured basis, the payment obligations of the Partnerships with respect to the outstanding series of notes issued under the respective indentures of the Partnerships. Concurrently, the Partnerships entered into a subsidiary guarantee agreement pursuant to which they fully and unconditionally guaranteed, on a senior unsecured basis, the outstanding series of senior notes of Enbridge. The Partnerships have also entered into supplemental indentures with Enbridge pursuant to which the Partnerships have issued full and unconditional guarantees, on a senior unsecured basis, of senior notes issued by Enbridge subsequent to January 22, 2019. As a result of the guarantees, holders of any of the outstanding guaranteed notes of the Partnerships (the Guaranteed Partnership Notes) are in the same position with respect to the net assets, income and cash flows of Enbridge as holders of Enbridge's outstanding guaranteed notes (the Guaranteed Enbridge Notes), and vice versa. Other than the Partnerships, Enbridge subsidiaries (including the subsidiaries of the Partnerships, collectively, the Subsidiary Non-Guarantors), are not parties to the subsidiary guarantee agreement and have not otherwise guaranteed any of Enbridge's outstanding series of senior notes. Consenting SEP notes and EEP notes under GuaranteeSEP Notes 1 EEP Notes 24.750% Senior Notes due 2024 5.875% Notes due 2025 3.500% Senior Notes due 2025 5.950% Notes due 2033 3.375% Senior Notes due 2026 6.300% Notes due 2034 5.950% Senior Notes due 2043 7.500% Notes due 2038 4.500% Senior Notes due 2045 5.500% Notes due 2040 7.375% Notes due 2045 1 As at December 31, 2023, the aggregate outstanding principal amount of SEP notes was approximately US$3.2 billion. 2 As at December 31, 2023, the aggregate outstanding principal amount of EEP notes was approximately US$2.4 billion. 86Enbridge Notes under Guarantees USD Denominated 1 CAD Denominated 2Floating Rate Senior Notes due 2024 3.950% Medium-term Notes due 2024 3.500% Senior Notes due 2024 2.440% Medium-term Notes due 2025 2.150% Senior Notes due 2024 3.200% Medium-term Notes due 2027 2.500% Senior Notes due 2025 5.700% Medium-term Notes due 2027 2.500% Senior Notes due 2025 6.100% Medium-term Notes due 2028 4.250% Senior Notes due 2026 4.900% Medium-term Notes due 2028 1.600% Senior Notes due 2026 2.990% Medium-term Notes due 2029 5.969% Senior Notes due 2026 7.220% Medium-term Notes due 2030 5.900% Senior Notes due 2026 7.200% Medium-term Notes due 2032 3.700% Senior Notes due 2027 6.100% Sustainability-Linked Medium-term Notes due 2032 6.000% Senior Notes due 2028 3.100% Sustainability-Linked Medium-term Notes due 2033 3.125% Senior Notes due 2029 5.360% Sustainability-Linked Medium-term Notes due 2033 6.200% Senior Notes due 2030 5.570% Medium-term Notes due 2035 2.500% Sustainability-Linked Senior Notes due 2033 5.750% Medium-term Notes due 2039 5.700% Sustainability-Linked Senior Notes due 2033 5.120% Medium-term Notes due 2040 4.500% Senior Notes due 2044 4.240% Medium-term Notes due 2042 5.500% Senior Notes due 2046 4.570% Medium-term Notes due 2044 4.000% Senior Notes due 2049 4.870% Medium-term Notes due 2044 3.400% Senior Notes due 2051 4.100% Medium-term Notes due 2051 6.700% Senior Notes due 2053 6.510% Medium-term Notes due 2052 5.760% Medium-term Notes due 2053 4.560% Medium-term Notes due 2064 1 As at December 31, 2023, the aggregate outstanding principal amount of the Enbridge US dollar denominated notes was approximately US$15.7 billion. 2 As at December 31, 2023, the aggregate outstanding principal amount of the Enbridge Canadian dollar denominated notes was approximately $11.0 billion. Rule 3-10 of the US Securities and Exchange Commission's (SEC) Regulation S-X provides an exemption from the reporting requirements of the Securities Exchange Act of 1934, as amended (the Exchange Act) for fully consolidated subsidiary issuers of guaranteed securities and subsidiary guarantors and allows for summarized financial information in lieu of filing separate financial statements for each of the Partnerships. The following Summarized Combined Statement of Earnings and the Summarized Combined Statements of Financial Position combines the balances of EEP, SEP and Enbridge.Summarized Combined Statement of EarningsYear ended December 31, 2023(millions of Canadian dollars)Operating loss (149) Earnings 4,273 Earnings attributable to common shareholders 3,921 87Summarized Combined Statements of Financial PositionDecember 31, 2023 2022(millions of Canadian dollars)Cash and cash equivalents 6,525 425 Accounts receivable from affiliates 3,440 2,486 Short-term loans receivable from affiliates 3,291 5,232 Other current assets 491 969 Long-term loans receivable from affiliates 45,702 43,873 Other long-term assets 3,303 4,111 Accounts payable to affiliates 2,264 1,375 Short-term loans payable to affiliates 807 1,745 Trade payable and accrued liabilities 743 716 Other current liabilities 7,256 8,036 Long-term loans payable to affiliates 35,556 37,626 Other long-term liabilities 52,096 47,447The Guaranteed Enbridge Notes and the Guaranteed Partnership Notes are structurally subordinated to the indebtedness of the Subsidiary Non-Guarantors in respect of the assets of those Subsidiary Non-Guarantors. Under US bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee can be voided, or claims may be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time the indebtedness evidenced by its guarantee or, in some states, when payments become due under the guarantee: • received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee and was insolvent or rendered insolvent by reason of such incurrence; • was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or • intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they mature. The guarantees of the Guaranteed Enbridge Notes contain provisions to limit the maximum amount of liability that the Partnerships could incur without causing the incurrence of obligations under the guarantee to be a fraudulent conveyance or fraudulent transfer under US federal or state law. Each of the Partnerships is entitled to a right of contribution from the other Partnership for 50% of all payments, damages and expenses incurred by that Partnership in discharging its obligations under the guarantees for the Guaranteed Enbridge Notes.88Under the terms of the guarantee agreement and applicable supplemental indentures, the guarantees of either of the Partnerships of any Guaranteed Enbridge Notes will be unconditionally released and discharged automatically upon the occurrence of any of the following events:• any direct or indirect sale, exchange or transfer, whether by way of merger, sale or transfer of equity interests or otherwise, to any person that is not an affiliate of Enbridge, of any of Enbridge’s direct or indirect limited partnership of other equity interests in that Partnership as a result of which the Partnership ceases to be a consolidated subsidiary of Enbridge; • the merger of that Partnership into Enbridge or the other Partnership or the liquidation and dissolution of that Partnership; • the repayment in full or discharge or defeasance of those Guaranteed Enbridge Notes, as contemplated by the applicable indenture or guarantee agreement; • with respect to EEP, the repayment in full or discharge or defeasance of each of the consenting EEP notes listed above; • with respect to SEP, the repayment in full or discharge or defeasance of each of the consenting SEP notes listed above; or • with respect to any series of Guaranteed Enbridge Notes, with the consent of holders of at least a majority of the outstanding principal amount of that series of Guaranteed Enbridge Notes. The guarantee obligations of Enbridge will terminate with respect to any series of Guaranteed Partnership Notes if that series is discharged or defeased.The Partnerships also guarantee the obligations of Enbridge under its existing credit facilities .LEGAL AND OTHER UPDATESLIQUIDS PIPELINES Line 5 Easement (Bad River Band) On July 23, 2019, the Bad River Band of the Lake Superior Tribe of Chippewa Indians (the Band) filed a complaint in the US District Court for the Western District of Wisconsin (the Court) over our Line 5 pipeline and right-of-way across the Bad River Reservation (the Reservation). Only a small portion of the total easements across 12 miles of the Reservation are at issue. The Band alleges that our continued use of Line 5 to transport crude oil and related liquids across the Reservation is a public nuisance under federal and state law and that the pipeline is in trespass on certain tracts of land in which the Band possesses ownership interests. The complaint seeks an Order prohibiting us from using Line 5 to transport crude oil and related liquids across the Reservation and requiring removal of the pipeline from the Reservation. Subsequently amended versions of the complaint also seek recovery of profits-based damages based on an unjust enrichment theory. Enbridge has responded to each claim in the initial and amended complaints with an answer, defenses and counterclaims. On August 29, 2022, the Government of Canada released a statement formally invoking the dispute settlement provisions of the 1977 Transit Pipelines Treaty in respect of this litigation; reiterating its concerns about the uninterrupted transmission of hydrocarbons through Line 5. On September 7, 2022, the Court issued a decision on cross-motions for summary judgment. The Court determined that the Band's nuisance claim raised factual issues that could not be resolved on summary judgment. The Court further determined that Enbridge is in trespass on 12 parcels on the Reservation and that the Band is entitled to some measure of profits-based damages and to an injunction, with the level of damages and scope of the injunction to be determined at trial, which occurred October 24 through November 1, 2022. On May 9, 2023, the Band filed an Emergency Motion for Injunctive Relief asking the Court to require Enbridge to purge and shutdown Line 5 on the Reservation due to significant erosion at the Meander. Enbridge responded and a hearing was held on May 18, 2023 in front of Judge Conley who indicated that he did not find the Band had proven imminence but his final ruling on all issues would be provided soon. 89 On June 26, 2023, the Court issued its Final Order ruling that (1) Enbridge shall adopt and implement its 2022 Monitoring and Shutdown Plan with the Court's modifications by July 5, 2023; (2) Enbridge owes the Band $5,151,668 for past trespass on the 12 allotted parcels; (3) Enbridge must continue to pay money on a quarterly basis using the formula set in its Order as long as Line 5 operates in trespass on the 12 allotted parcels (approximately $400,000 per year); (4) Enbridge must cease operation of Line 5 on any parcel within the Band's tribal territory without a valid right of way by June 16, 2026 and thereafter arrange prompt, reasonable remediation at those sites; and (5) The Court declined to allow for the Relocation to be completed prior to having to cease operations. The Final Judgment was entered on June 29, 2023. Enbridge filed its Notice of Appeal on June 30, 2023 and the Band filed its Notice of Cross Appeal on July 27, 2023. On December 12, 2023, the 7th Circuit requested the US to file a brief in this appeal as amicus curiae to address the effect of the Agreement Between the US and Canada Concerning Transit Pipelines, 28 U.S.T. 7449 (1977), and any other issues that the US believes to be material. Briefing by the parties was complete on December 15, 2023. Oral argument is scheduled in February 2024, and we anticipate a decision in 2024. Michigan Line 5 Dual Pipelines - Straits of Mackinac Easement In 2019, the Michigan Attorney General (AG) filed a complaint in the Michigan Ingham County Circuit Court (the Circuit Court) that requests the Circuit Court to declare the easement granted in 1953 that we have for the operation of Line 5 in the Straits of Mackinac (the Straits) to be invalid and to prohibit continued operation of Line 5 in the Straits. On December 15, 2021, Enbridge removed the case to the US District Court in the Western District of Michigan (US District Court), where it was assigned to Judge Janet T. Neff. The removal of the AG's case to federal court followed a November 16, 2021 ruling which held that the similar (and now dismissed) 2020 lawsuit brought by the Governor of Michigan to force Line 5's shutdown raised important federal issues that should be heard in federal court. On December 21, 2021, the AG made a request to file a motion to remand the 2019 case, which the US District Court allowed on January 5, 2022. However, after full briefing, on August 18, 2022, Judge Neff denied the AG's motion to remand. On August 30, 2022, the AG filed a motion to certify the August 18 Order to pursue an appeal on the jurisdictional issue, which Enbridge opposed. On February 21, 2023, that motion was granted and shortly after, on March 2, 2023, the AG filed her Petition for Permission to Appeal in the 6 th Circuit Court of Appeals (6 th Circuit). On July 21, 2023, the 6 th Circuit granted the AG's Petition for Permission to appeal the US District Court's August 18 Order denying remand to state court. The 6 th Circuit's briefing was completed by the end of 2023 and oral argument has been scheduled for March 2024. We anticipate a decision in 2024. Dakota Access Pipeline We own an effective interest of 27.6% in the Bakken Pipeline System, which is inclusive of the Dakota Access Pipeline (DAPL). The Standing Rock Sioux Tribe and the Cheyenne River Sioux Tribe filed lawsuits in 2016 with the US Court for the District of Columbia (the District Court) contesting the lawfulness of the Army Corps easement for DAPL, including the adequacy of the Army Corps' environmental review and tribal consultation process. The Oglala Sioux and Yankton Sioux Tribes also filed lawsuits alleging similar claims in 2018. On June 14, 2017, the District Court found the Army Corps' environmental review to be deficient and ordered the Army Corps to conduct further study concerning spill risks from DAPL. On March 25, 2020, in response to amended complaints from the Tribes, the District Court found that the Army Corps' subsequent environmental review completed in August 2018 was also deficient and ordered the Army Corps to prepare an Environmental Impact Statement (EIS) to address unresolved controversy pertaining to potential spill impacts resulting from DAPL. On July 6, 2020, the District Court issued an order vacating the Army Corps' easement for DAPL and ordering that the pipeline be shut down by August 5, 2020. On that day, the US Court of Appeals for the District of Columbia Circuit stayed the District Court's July 6 order to shut down and empty the pipeline. 90 On January 26, 2021, the US Court of Appeals affirmed the District Court's decision, holding that the Army Corps is required to prepare an EIS and that the Army Corps' easement for DAPL is vacated. The US Supreme Court subsequently denied the request of Dakota Access, LLC to review the decision that an EIS is required. The US Court of Appeals also determined that, absent an injunction proceeding, the District Court could not order DAPL's operations to cease. While not an issue before, the US Court of Appeals also recognized that the Army Corps could consider whether to allow DAPL to continue to operate in the absence of an easement. The Army Corps earlier indicated that it did not intend to exercise its authority to bar DAPL's continued operation, notwithstanding the absence of an easement. On September 8, 2023, the Army Corps issued its draft EIS, which assesses the impacts of DAPL under five alternative scenarios: denying the easement removing the pipeline; denying the easement and leaving the pipeline in place; granting the easement with the prior conditions (which allow for the ongoing operation, maintenance and ultimate removal of the pipeline and its related facilities); granting the easement with some new safety conditions; and rerouting the pipeline. The Army Corps did not identify a preferred alternative. The public comment period that commenced on the issuance of the draft EIS closed on December 13, 2023. The pipeline will remain operational while the environmental review process continues. GAS TRANSMISSION AND MIDSTREAM Aux Sable The previously reported claim filed against Aux Sable by a counterparty to an NGL supply agreement was settled and discontinued during the fourth quarter of 2023. A provision was recognized for this claim in the third quarter of 2023.OTHER LITIGATION We and our subsidiaries are subject to various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our consolidated financial position or results of operations.TAX MATTERS We and our subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in our view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.CRITICAL ACCOUNTING POLICIES AND ESTIMATES Our consolidated financial statements are prepared in accordance with US GAAP, which requires management to make estimates, judgments and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. In making judgments and estimates, management relies on external information and observable conditions, where possible, supplemented by internal analysis as required. We believe our most critical accounting policies and estimates discussed below have an impact across the various segments of our business.91 BUSINESS COMBINATIONS We apply the provisions of Accounting Standards Codification 805 Business Combinations in accounting for our acquisitions. The acquired assets and assumed liabilities are recorded at their estimated fair values at the date of acquisition. Goodwill represents the excess of the purchase price over the fair value of net identifiable assets. While we use our best estimates and assumptions to accurately value assets acquired and liabilities assumed at the date of acquisition, as well as any contingent consideration, our estimates are inherently uncertain and subject to refinement. During the measurement period, which may be up to one year from the acquisition date, we record adjustments to the assets acquired and liabilities assumed with a corresponding offset to goodwill. Upon conclusion of the measurement period, or the final determination of values for assets acquired or liabilities assumed, whichever comes first, any subsequent adjustments are recorded to our Consolidated Statements of Earnings. Accounting for business combinations requires significant judgment, estimates and assumptions at the acquisition date. In developing estimates of fair values at the acquisition date, we utilize a variety of factors including market data, historical and future expected cash flows, growth rates and discount rates. The subjective nature of our assumptions increases the risk associated with estimates surrounding the projected performance of the acquired entity.GOODWILL IMPAIRMENT Goodwill represents the excess of the purchase price over the fair value of net identifiable assets upon acquisition of a business. The carrying value of goodwill, which is not amortized, is assessed for impairment annually or more frequently if events or changes in circumstances arise that suggest the carrying value of goodwill may be impaired. We perform our annual review of the goodwill balance on April 1.We perform our annual review for impairment at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete information is available, whether segment management regularly reviews the operating results of those components, and whether the economic and regulatory characteristics are similar. Our reporting units are Liquids Pipelines, Gas Transmission, Gas Distribution and Storage, and Renewable Power Generation. The Renewable Power Generation reporting unit had goodwill beginning in the third quarter of 2022. We have the option to first assess qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment assessment. When performing a qualitative assessment, we determine the drivers of fair value for each reporting unit and evaluate whether those drivers have been positively or negatively affected by relevant events and circumstances since the last fair value assessment. Our evaluation includes, but is not limited to, the assessment of macroeconomic trends, changes to regulatory environments, capital accessibility, operating income trends, and changes to industry conditions. Based on our assessment of qualitative factors, if we determine it is more likely than not that the fair value of the reporting unit is less than its carrying amount, a quantitative goodwill impairment assessment is performed. The quantitative goodwill impairment assessment involves determining the fair value of our reporting units and comparing those values to the carrying value of each reporting unit. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit's carrying value exceeds its fair value. This amount should not exceed the carrying amount of goodwill. The fair value of our reporting units is estimated using a discounted cash flow technique. The determination of fair value using the discounted cash flow technique requires the use of estimates and assumptions related to discount rates, projected operating income, expected future capital expenditures and working capital levels, as well as terminal value growth rates for the Liquids Pipelines, Gas Transmission, and Renewable Power Generation reporting units, and projected regulatory rate base and rate base multiple for the Gas Distribution and Storage reporting unit. 92The allocation of goodwill to held-for-sale and disposed businesses is based on the relative fair value of businesses included in the relevant reporting unit.On April 1, 2023, we performed our annual goodwill impairment assessment which consisted of a qualitative assessment for the Liquids Pipelines, Gas Transmission, Gas Distribution and Storage, and Renewable Power Generation reporting units and did not identify impairment indicators. Due to an impairment recorded in 2022 for the Gas Transmission reporting unit and the OEB decision on Phase 1 for Enbridge Gas, we performed a quantitative assessment for the Gas Transmission and Gas Distribution and Storage reporting units as at December 1, 2023, which did not result in the recognition of an impairment charge for either reporting unit. Also, we did not identify any indicators of goodwill impairment during the remainder of 2023. The Gas Transmission reporting unit remains at risk as the quantitative test performed resulted in the fair value exceeding carrying value by less than 10% and once the Alliance Pipeline and Aux Sable disposition closes in 2024, the fair value of the reporting unit will decrease.ASSET IMPAIRMENT We evaluate the recoverability of our property, plant and equipment when events or circumstances, such as economic obsolescence, business climate, legal or regulatory changes, or other factors, indicate that we may not recover the carrying amount of our assets. We regularly monitor our businesses, the market and business environments to identify indicators that could suggest an asset may not be recoverable. If it is determined that the carrying value of an asset exceeds its expected undiscounted cash flows, we will assess the fair value of the asset. An impairment loss is recognized when the carrying amount of the asset exceeds its fair value. With respect to equity method investments, we assess at each balance sheet date whether there is objective evidence that the investment is impaired by completing a qualitative or quantitative analysis of factors impacting the investment. If there is objective evidence of impairment, we determine whether the decline below carrying value is other-than-temporary. If the decline is determined to be other-than-temporary, an impairment charge is recorded in earnings with an offsetting reduction to the carrying value of the investment. Asset fair value is determined using present value techniques. The determination of fair value using present value techniques requires the use of projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes to these projections and assumptions could result in revisions to the evaluation of the recoverability of the asset and the recognition of an impairment loss in the Consolidated Statements of Earnings.ASSETS HELD FOR SALE We classify assets as held for sale when management commits to a formal plan to actively market an asset or a group of assets and when management believes it is probable the sale of the assets will occur within one year. We measure assets classified as held for sale at the lower of their carrying value and their estimated fair value less costs to sell. 93REGULATORY ACCOUNTINGCertain parts of our businesses are subject to regulation by various authorities including, but not limited to, the CER, the FERC, the Alberta Energy Regulator, the BC Energy Regulator, the OEB and the Québec Régie de l'énergie. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking, and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under US GAAP for non-rate-regulated entities.Key determinants in the ratemaking process are: • costs of providing service, including operating costs, capital invested, depreciation expense and taxes; • allowed rate of return, including the equity component of the capital structure and related income taxes; • interest costs on the debt component of the capital structure; and • contract and volume throughput assumptions.The allowed rate of return is determined in accordance with the applicable regulatory model and may impact our profitability. The rates for a number of our projects are based on a cost-of-service recovery model that follows the regulators' authoritative guidance. Under the cost-of-service tolling methodology, we calculate tolls based on forecast volumes and cost. A difference between forecast and actual results causes an over- or under-recovery in any given year. Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates, amounts collected from customers in advance of costs being incurred, or to be paid to cover future abandonment costs in relation to the CER's Land Matters Consultation Initiative (LMCI) and for future removal and site restoration costs as approved by the regulator. If there are changes in our assessment of the probability of recovery for a regulatory asset, we reduce its carrying amount to the balance that we expect to recover from customers in future periods through rates. If a regulator later excludes from allowable costs all or a part of costs that were capitalized as a regulatory asset, we reduce the carrying amount of the asset by the excluded amounts. The recognition of regulatory assets and liabilities is based on the actions, or expected future actions, of the regulator. To the extent that the regulator's actions differ from our expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate regulation, we would generally not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned. A regulatory asset or liability is recognized in respect of deferred income taxes when it is expected the amounts will be recovered or settled through future regulator-approved rates. During the fourth quarter of 2023, Southern Lights Pipeline completed an open season to negotiate new transportation service agreements effective 2025. We do not expect to renew the agreements under a cost-of-service toll methodology, therefore Southern Lights Pipeline is no longer subject to rate-regulated accounting. As a result, the related regulatory liabilities, regulatory tax assets and associated regulatory deferred tax liabilities were derecognized. As at December 31, 2023 and 2022, our regulatory assets totaled $5.7 billion and $6.5 billion, respectively, and regulatory liabilities totaled $3.8 billion. 94DEPRECIATIONDepreciation of property, plant and equipment, our largest asset with a net book value at December 31, 2023 and 2022, of $104.6 billion and $104.5 billion, respectively, is charged in accordance with two primary methods. For distinct assets, depreciation is generally provided on a straight-line basis over the estimated useful lives of the assets commencing when the asset is placed in service. For largely homogeneous groups of assets with comparable useful lives, the pool method of accounting is followed whereby similar assets are grouped and depreciated as a pool. When group assets are retired or otherwise disposed of, gains and losses are not reflected in earnings but are booked as an adjustment to accumulated depreciation.When it is determined that the estimated service life of an asset no longer reflects the expected remaining period of benefit, prospective changes are made to the estimated service life. Estimates of useful lives are based on third-party engineering studies, experience and/or industry practice. There are a number of assumptions inherent in estimating the service lives of our assets including the level of development, exploration, drilling, reserves and production of crude oil and natural gas in the supply areas served by our pipelines, as well as the demand for crude oil and natural gas and the integrity of our systems. Changes in these assumptions could result in adjustments to the estimated service lives, which could result in material changes to depreciation expense in future periods in any of our business segments. For certain rate-regulated operations, depreciation rates are approved by the regulator and the regulator may require periodic studies or technical updates on useful lives which may change depreciation rates.PENSION AND OTHER POSTRETIREMENT BENEFITS We use certain assumptions relating to the calculation of defined benefit pension and other postretirement liabilities and net periodic benefit costs. These assumptions comprise management's best estimates of expected return on plan assets, future salary levels, other cost escalations, retirement ages of employees, and other actuarial factors including discount rates and mortality. We determine discount rates by reference to rates of high-quality long-term corporate bonds with maturities that approximate the timing of future payments anticipated to be made under each of the respective plans. The expected return on plan assets is determined using market-related values and assumptions on the asset mix consistent with the investment policy relating to the assets and their projected returns. The assumptions are reviewed annually by our independent actuaries. Actual results that differ from results based on assumptions are amortized over future periods and, therefore, could materially affect the expense recognized and the recorded obligation in future periods.The following sensitivity analysis identifies the impact on the consolidated financial statements for the year ended December 31, 2023 of a 0.5% change in key pension and other postretirement benefits (OPEB) obligation assumptions: Canada United States Obligation Expense Obligation Expense(millions of Canadian dollars) PensionDecrease in discount rate 297 12 52 3 Decrease in expected return on assets — 21 — 5 Decrease in rate of salary increase (60) (5) (5) (1)OPEBDecrease in discount rate 15 1 5 — Decrease in expected return on assets N/A N/A — 1 95CONTINGENT LIABILITIESProvisions for claims filed against us are determined on a case-by-case basis. Case estimates are reviewed on a regular basis and are updated as new information is received. The process of evaluating claims involves the use of estimates and a high degree of management judgment. Claims outstanding, the final determination of which could have a material impact on our financial results and certain subsidiaries and investments, are detailed in Legal and Other Updates and Part II. Item 8. Financial Statements and Supplementary Data - Note 30. Commitments and Contingencies . In addition, any unasserted claims that later may become evident could have a material impact on our financial results and certain subsidiaries and investments.ASSET RETIREMENT OBLIGATIONSAsset retirement obligations (ARO) associated with the retirement of long-lived assets are measured at fair value and recognized as Other current liabilities or Other long-term liabilities in the period in which they can be reasonably determined. Fair value approximates the cost a third party would charge to perform the tasks necessary to retire such assets and is recognized at the present value of expected future cash flows. The discount rates used to estimate the present value of expected future cash flows for the years ended December 31, 2023 and 2022 ranged from 1.5% to 9.0%. ARO is added to the carrying value of the associated asset and depreciated over the asset's useful life. The corresponding liability is accreted over time through charges to earnings and is reduced by actual costs of decommissioning and reclamation. Our estimates of retirement costs could change as a result of changes in cost estimates and regulatory requirements. Currently, for the majority of our assets, there is insufficient data or information to reasonably determine the timing of settlement for estimating the fair value of the ARO. In these cases, the fair value of ARO is considered indeterminate for accounting purposes, as there is no data or information that can be derived from past practice, industry practice or the estimated economic life of the asset. In 2009, the CER issued a decision related to the LMCI, which required holders of an authorization to operate a pipeline under the CER Act to file a proposed process and mechanism to set aside funds to pay for future abandonment costs in respect of the sites in Canada used for the operation of a pipeline. The CER's decision stated that, while pipeline companies are ultimately responsible for the full costs of abandoning pipelines, abandonment costs are a legitimate cost of providing service and are recoverable from the users of the pipeline upon approval by the CER. Following the CER's final approval of the collection mechanism and the set-aside mechanism for LMCI, we began collecting and setting aside funds to cover future abandonment costs effective January 1, 2015. The funds collected are held in trusts in accordance with the CER decision. The funds collected from shippers are reported within Transportation and other services revenues and Restricted long-term investments. Concurrently, we reflect the future abandonment cost as an increase to Operating and administrative expense and Other long-term liabilities.CHANGES IN ACCOUNTING POLICIESRefer to Part II. Item 8. Financial Statements and Supplementary Data - Note 3. Changes in Accounting Policies .

FY 2025-12-31 (later)

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS INTRODUCTION The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with "Forward-Looking Information" and "Non-GAAP and Other Financial Measures", Part I. Item 1A. Risk Factors and our consolidated financial statements and the accompanying notes included in Part II. Item 8. Financial Statements and Supplementary Data of this Annual Report on Form 10-K.This section of our Annual Report on Form 10-K discusses 2025 and 2024 items and year-over-year comparisons between 2025 and 2024. For discussion of 2023 items and year-over-year comparisons between 2024 and 2023, refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report on Form 10-K for the year ended December 31, 2024.RECENT DEVELOPMENTSLIQUIDS PIPELINES INVESTMENT Mainline System Capital Investment In 2025, we announced plans to invest up to US$1.3 billion in our Mainline System through 2028. These investments are expected to earn a return through the Mainline Tolling Settlement and will be focused on extending the service life of the underlying assets, as well as further enhancing reliability and efficiency given continuing demands on the system. NONCONTROLLING INTEREST INVESTMENT BC Pipeline System On July 2, 2025, Stonlasec8 Indigenous Investments Limited Partnership (the First Nations Partnership), an entity representing 38 First Nations in British Columbia (BC), invested approximately $736 million in our Westcoast Energy Inc. BC natural gas pipeline system. As at December 31, 2025, we own 87.53% of the BC Pipeline system, which is included in our Gas Transmission segment, and continue to manage and operate the pipeline system. The First Nations Partnership owns the remaining 12.47% interest. GAS TRANSMISSION RATE PROCEEDINGS Algonquin Algonquin Gas Transmission, LLC (Algonquin) filed a rate case on May 30, 2024 and a settlement in principle was reached with customers in December 2024. A Stipulation and Agreement was approved by the Federal Energy Regulatory Commission (FERC) on April 25, 2025 with rates effective December 1, 2024. Maritimes & Northeast Maritimes & Northeast (M&N) United States (US) filed a rate case on May 30, 2024 and a settlement in principle was reached with customers in December 2024. A Stipulation and Agreement was approved by the FERC on April 25, 2025 with rates effective January 1, 2025. The toll settlement agreement for M&N Canada expired in December 2025. M&N Canada reached a toll settlement with shippers for the effective period from January 1, 2026 to December 31, 2027. On December 15, 2025, M&N Canada filed the 2026–2027 toll settlement agreement with the Canada Energy Regulator (CER) for review and approval. A CER decision is expected in the first quarter of 2026. 63 East Tennessee East Tennessee Natural Gas, LLC (East Tennessee) filed a rate case on April 29, 2025. On May 29, 2025, the FERC issued an order accepting and suspending tariff records, subject to refund, conditions, and establishing hearing procedures. In compliance with the order, East Tennessee made a filing to implement the rates to be effective November 1, 2025, subject to refund. Settlement discussions with shippers commenced in the third quarter of 2025. Vector Vector Pipeline L.P. (Vector) filed a rate case on May 30, 2025. On June 30, 2025, the FERC issued an order accepting and suspending tariff records filed in this rate case, and establishing hearing procedures. In compliance with the order, Vector placed the proposed rates into effect on July 1, 2025. Additionally, on July 1, 2025, the chief administrative law judge issued an order consolidating Vector’s outstanding review of rates initiated by the FERC in 2024 with Vector’s May 30, 2025 rate case filing. In February 2026, Vector reached a settlement in principle with all active participants that resolves all issues in the consolidated rate case, which will be filed for FERC approval in the first half of 2026. If approved, settlement rates will be effective April 1, 2026.GAS DISTRIBUTION AND STORAGE RATE APPLICATIONSEnbridge Gas Ontario In October 2022, Enbridge Gas Inc. (Enbridge Gas Ontario) filed its application with the Ontario Energy Board (OEB) to establish a 2024–2028 Incentive Regulation (IR) rate setting framework: • Phase 1 of the application established 2024 base rates on a cost-of-service basis. • Phase 2 established a price cap incentive rate-setting (Price Cap IR) mechanism for 2025–2028. • Phase 3 addresses cost allocation and the harmonization of rates, rate classes and services. Completion of Phase 3 is expected in 2026. Phase 1 In December 2023, the OEB issued its decision on Phase 1. Enbridge Gas Ontario continues to appeal through Ontario courts the OEB's Phase 1 findings on depreciation, equity thickness and undepreciated capital, with hearing dates scheduled in 2026. Phase 2 Through a November 2024 decision on the Phase 2 partial settlement proposal, and a May 2025 decision on outstanding issues, the OEB approved a Price Cap IR mechanism for 2025–2028 rates. The mechanism includes an earnings sharing mechanism which requires earnings in excess of 100 basis points over the allowed return on equity (ROE) to be shared equally with customers, and 90% of any earnings in excess of 300 basis points over the allowed ROE. Rates effective January 1, 2025 and January 1, 2026, were set using the approved Price Cap IR mechanism. Generic Cost of Capital Proceeding In March 2025, the OEB released its decision in the generic cost of capital proceeding. The OEB determined that Enbridge Gas Ontario's equity thickness would remain at 38% as approved in the Phase 1 decision. The OEB also revised the formula for calculating ROE by reducing flotation costs by 25 basis points. The new formula will be applicable to Enbridge Gas Ontario at its next rebasing expected in 2029. Until then, rates will continue to reflect the 2024 ROE of 9.21%. Enbridge Gas Ohio In October 2023, Enbridge Gas Ohio filed its first base rates application with the Ohio Commission since 2007, proposing a base rate annual revenue increase to be effective January 2025. The base rate increase was proposed to recover the significant investment in distribution infrastructure for the benefit of Ohio customers, including an ROE of 10.40%. 64 In June 2025, the Ohio Commission ordered a decrease to annual revenue of US$26.3 million, utilizing an ROE of 9.79%, and an increase to the equity thickness to 51.9%. The order also resulted in disallowances of $330 million (US$240 million), including regulatory pension assets of $280 million (US$204 million) and other disallowances of $50 million (US$36 million) which were recognized for the year ended December 31, 2025. The order authorized the continuation of the Pipeline Infrastructure Replacement (PIR) and Capital Expenditure Programs (CEP) through 2028, with 3% increases of capital expenditures under the PIR per year. Assets placed in service accrue a carrying cost at the cost of long-term debt approved in the most recent rate case until incorporated into rates via annual filings. In July 2025, Enbridge Gas Ohio filed a rehearing application for certain aspects of the order. The Ohio Commission corrected errors in its order addressing the rehearing application, resulting in a reduction of the original annual revenue decrease to US$14.3 million. Updated rates were effective on November 1, 2025. On December 12, 2025, Enbridge Gas Ohio filed a notice of appeal with the Ohio Supreme Court, focusing on the Ohio Commission's treatment of the pension fund and capitalized incentive-compensation costs. In December 2025, Enbridge Gas Ohio filed a base rate case application proposing an annual revenue increase of US$163 million, subject to update and adjustments, to be effective in early 2027. The base rate increase was proposed to recover Enbridge Gas Ohio's investment in distribution infrastructure and other costs to serve, including operating expenses and debt servicing costs. Enbridge Gas North Carolina In April 2025, Enbridge Gas North Carolina filed its first rates application since 2021 with the North Carolina Utilities Commission, proposing the recovery of costs to deliver natural gas to customers and investments in infrastructure to support service reliability and customer growth. In September 2025, a settlement agreement was filed reflecting an annual revenue increase of US$33 million. The settlement was approved by the North Carolina Utilities Commission on December 9, 2025, with updated rates effective November 1, 2025. The settlement includes a Major Projects Rider for the Moriah Energy Center LNG facility and the T-15 Reliability Project, as a standalone cost recovery mechanism between general base rate cases. Enbridge Gas Utah In May 2025, Enbridge Gas Utah filed its first rates application since 2022 with the Utah Public Service Commission, proposing the recovery of costs to deliver natural gas to customers and investments in infrastructure to support service reliability and customer growth. In September 2025, Enbridge Gas Utah filed a settlement and final order approving an annual revenue increase of US$61 million was issued on December 24, 2025 with updated rates effective January 1, 2026.FINANCING UPDATEWe completed long-term debt issuances totaling $4.6 billion and US$4.7 billion during the year ended December 31, 2025. On February 25, 2025, Enbridge Pipelines Inc. redeemed below par all of the outstanding $100 million 4.10% medium-term notes that carried an original maturity date in July 2112. On July 28, 2025, Enbridge Energy Partners, L.P. (EEP) redeemed at par all of the outstanding US$500 million 5.88% senior notes that carried an original maturity date in October 2025. During our annual renewal process, we renewed and extended approximately $22.1 billion of our credit facilities with maturities ranging from 2027 – 2030. 65 Our 2025 financing activities have provided significant liquidity that we expect will enable us to fund our current portfolio of capital projects and acquisitions without requiring access to the capital markets for the next 12 months, should market access be restricted or pricing be unattractive. Refer to Liquidity and Capital Resources . As at December 31, 2025, after adjusting for the impact of floating-to-fixed interest rate swap hedges, approximately 9% of our total debt is exposed to floating rates. Refer to Part II. Item 8. Financial Statements and Supplementary Data - Note 23 - Risk Management and Financial Instruments for more information on our interest rate hedging program.RESULTS OF OPERATIONSYear ended December 31, 2025 2024 2023(millions of Canadian dollars, except per share amounts) Segment earnings/(loss) before interest, income taxes and depreciation and amortization 1Liquids Pipelines 9,396 9,531 9,383 Gas Transmission 5,491 5,656 4,264 Gas Distribution and Storage 3,809 2,869 1,592 Renewable Power Generation 620 733 149 Eliminations and Other 1,161 (1,904 ) 916Earnings before interest, income taxes and depreciation and amortization 120,477 16,885 16,304 Depreciation and amortization (5,661 ) (5,167 ) (4,613 ) Interest expense (5,023 ) (4,419 ) (3,812 ) Income tax expense (2,004 ) (1,668 ) (1,821 ) (Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interest (298 ) (190 ) 133 Preference share dividends (419 ) (388 ) (352 ) Earnings attributable to common shareholders 7,072 5,053 5,839 Earnings per common share attributable to common shareholders 3.23 2.34 2.84 Diluted earnings per common share attributable to common shareholders 3.22 2.34 2.84 1 Non-GAAP financial measure. Refer to Non-GAAP and Other Financial Measures . 66EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERSYear ended December 31, 2025, compared with year ended December 31, 2024 Earnings attributable to common shareholders was positively impacted by $1.5 billion due to certain infrequent or other non-operating factors, primarily explained by the following: • a non-cash, net unrealized derivative fair value gain of $1.3 billion ($999 million after-tax) in 2025, compared with a net unrealized loss of $2.1 billion ($1.6 billion after-tax) in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange, interest rate and commodity price risks; and • equity earnings of $87 million ($65 million after-tax) from our investment in DCP Midstream, LP (DCP), as a result of DCP's gain on disposition from certain pipeline assets; partially offset by • the absence in 2025 of a gain on sale of $1.1 billion ($765 million after-tax) on the disposition of our interests in the Alliance Pipeline and Aux Sable Liquid Products LP, Aux Sable Midstream LLC, and Aux Sable Canada LP (Aux Sable); • an impairment of $330 million ($261 million after-tax) of certain rate-regulated assets related to pension and other disallowances as a result of the Ohio Commission's June 2025 order related to Enbridge Gas Ohio's rate case; and • an impairment loss of $240 million ($176 million after-tax) of certain non-core Liquids Pipelines assets.The non-cash, unrealized derivative fair value gains and losses discussed above generally arise as a result of our comprehensive economic hedging program to mitigate foreign exchange, interest rate and commodity price risks. This program creates volatility in reported short-term earnings through the recognition of unrealized non-cash gains and losses on derivative instruments used to hedge these risks. Over the long-term, we believe our hedging program supports the reliable cash flows and dividend growth upon which our investor value proposition is based.After taking into consideration the factors above, the remaining $541 million increase in earnings attributable to common shareholders is primarily explained by the following significant business factors: • full year of contributions from the US Gas Utilities in our Gas Distribution and Storage segment; • positive earnings impact in Enbridge Gas Ontario due to colder weather in 2025 compared to a negative impact in 2024, higher storage optimization and pricing, and higher distribution margin and customer growth in our Gas Distribution and Storage segment; • higher contributions from our Gas Transmission segment primarily due to the recognition of increased revenue attributable to Algonquin and Texas Eastern rate case settlements, favorable contracting on our US Gas Transmission assets, and contributions from the Texas Eastern Venice Extension project; • higher contributions from Mainline System (net of sharing) due to higher demand, higher tolls, and lower power costs; and • lower income tax expense, excluding tax on infrequent or non-operating factors discussed above, mainly driven by lower effective US tax rate primarily from the impact of higher investment tax credits. 67 The factors above were partially offset by: • higher interest expense primarily due to higher average debt principal outstanding; • higher depreciation and amortization expense mainly driven by full year ownership of the US Gas Utilities; • lower contributions from the Gulf Coast and Mid-Continent System in our Liquids Pipelines segment primarily due to lower spot volumes on the Flanagan South Pipeline; • lower contributions from our Gas Transmission segment due to the sale of our interests in Alliance Pipeline and Aux Sable in April 2024 and lower earnings from our Tomorrow RNG renewable natural gas facilities due to lower Renewable Identification Number (RIN) pricing and production volumes; • the decrease in 2025 of equity earnings from Fox Squirrel Solar investment tax credits in our Renewable Power Generation segment; and • the absence in 2025 of interest income from cash pre-funding related to Enbridge's acquisitions of the East Ohio Gas Company (EOG), Questar Gas Company (Questar) and its related Wexpro companies (Wexpro), and Public Service Company of North Carolina, Incorporated (PSNC) (together, the Acquisitions) in Eliminations and Other.REVENUES We generate revenues from three primary sources: transportation and other services, gas distribution sales and commodity sales.Transportation and other services revenues of $20.2 billion, $19.7 billion and $19.2 billion, for the years ended December 31, 2025, 2024 and 2023, respectively, were earned from our crude oil and natural gas pipeline transportation businesses and also include power generation revenues from our portfolio of renewable and power generation assets. For our transportation assets operating under market-based arrangements, revenues are driven by volumes transported and the corresponding tolls for transportation services. For assets operating under take-or-pay contracts, revenues reflect the terms of the underlying contract for services or capacity. For rate-regulated assets, revenues are charged in accordance with tolls established by the regulator and, in most cost-of-service based arrangements, are reflective of our cost to provide the service plus a regulator-approved rate of return. 68 Gas distribution sales revenues of $9.8 billion, $6.8 billion and $5.4 billion for the years ended December 31, 2025, 2024 and 2023, respectively, were recognized in a manner consistent with the underlying rate-setting mechanism mandated by the regulator. Revenues generated by the gas distribution businesses are primarily driven by volumes delivered, which vary with weather and customer composition and utilization, as well as regulator-approved rates. The cost of natural gas is passed through rates to customers and does not ultimately impact earnings due to its flow-through nature. Commodity sales revenues of $35.2 billion, $27.0 billion and $19.0 billion for the years ended December 31, 2025, 2024 and 2023, respectively, were generated primarily through our crude oil marketing, natural gas and power marketing businesses. This includes the purchase and sale of crude oil, natural gas, power and NGL to generate a margin, which is typically a small fraction of gross revenue. Sales revenue generated from these operations reflect activity levels which are driven by differences in commodity prices between locations, grades and points in time, rather than on absolute prices. Commodity sales revenues also include revenue generated from our Tomorrow RNG business. Any residual commodity margin risk is closely monitored and managed. Revenues from these operations depend on activity levels, which vary from year-to-year depending on market conditions and commodity prices.Our revenues also include changes in unrealized derivative fair value gains and losses related to foreign exchange and commodity price contracts used to manage exposures from movements in foreign exchange rates and commodity prices. The mark-to-market accounting creates volatility and impacts the comparability of revenues in the short-term, but we believe over the long-term, the economic hedging program supports reliable cash flows. BUSINESS SEGMENTS LIQUIDS PIPELINESYear ended December 31, 2025 2024 2023(millions of Canadian dollars)Earnings before interest, income taxes and depreciation and amortization 9,396 9,531 9,383 Year ended December 31, 2025 compared with year ended December 31, 2024 EBITDA was negatively impacted by $191 million primarily due to impairment losses of $240 million related to certain non-core assets. After taking into consideration the above, the remaining $56 million increase is primarily explained by the following significant business factors: • higher Mainline System contributions (net of sharing) as a result of higher demand, annual escalators and surcharge effective July 1, 2024, and lower power costs from operational efficiencies and lower mill rates; • higher contributions from Line 9 due to higher volumes; and • the favorable effect of translating US dollar earnings at a higher average exchange rate in 2025, compared to 2024; partially offset by • lower contributions from the Gulf Coast and Mid-Continent System primarily due to lower spot volumes on the Flanagan South Pipeline. 69 GAS TRANSMISSION Year ended December 31, 2025 2024 2023(millions of Canadian dollars)Earnings before interest, income taxes and depreciation and amortization 5,491 5,656 4,264 Year ended December 31, 2025 compared with year ended December 31, 2024 EBITDA was negatively impacted by $780 million due to certain infrequent or other non-operating factors primarily explained by the following: • the absence in 2025 of a gain on sale of $1.1 billion on the disposition of interests in the Alliance Pipeline and Aux Sable; partially offset by • the absence in 2025 of an asset impairment loss of $137 million related to the Big Sandy Pipeline; • equity earnings of $87 million from our investment in DCP, as a result of DCP's gain on disposition from certain pipeline assets; and • a net positive adjustment of $32 million to the gas inventory at Aitken Creek in 2025, compared to a net negative adjustment of $33 million in 2024. After taking into consideration the factors above, the remaining $615 million increase is primarily explained by the following significant business factors: • the recognition of increased revenue attributable to the Algonquin and Texas Eastern rate case settlements; • contributions from the Texas Eastern Venice Extension project since service commencement in late 2024; • higher revenues at Aitken Creek due to favorable storage spreads; • favorable contracting on our US Gas Transmission assets; • higher earnings from our investment in DCP; • contributions from the acquisition of equity interests in the Whistler Parent JV, Delaware Basin Residue, LLC (DBR), and Matterhorn Express, LLC in the second and fourth quarters of 2024, and the second quarter of 2025, respectively; and • the favorable effect of translating US dollar earnings at a higher average exchange rate in 2025, compared to 2024; partially offset by • the absence of contributions from Alliance Pipeline and Aux Sable due to the sale of our interests in these investments in April 2024; and • lower earnings at Tomorrow RNG primarily due to lower RIN pricing and production volumes. 70GAS DISTRIBUTION AND STORAGEYear ended December 31, 2025 2024 2023(millions of Canadian dollars)Earnings before interest, income taxes and depreciation and amortization 3,809 2,869 1,592 Year ended December 31, 2025 compared with year ended December 31, 2024 EBITDA was negatively impacted by $330 million due to an impairment of certain rate-regulated assets related to pension and other disallowances as a result of the Ohio Commission's June 2025 order related to Enbridge Gas Ohio's rate case. After taking into consideration the above, the remaining $1.3 billion increase is primarily explained by the following significant business factors: • full year of contributions from the US Gas Utilities; • when compared with the normal forecast embedded in rates, the positive impact of weather on EBITDA for Enbridge Gas Ontario was approximately $30 million (net of sharing) in 2025 compared to a negative impact of approximately $129 million in 2024; • higher distribution margin resulting from increases in rates and customer base at Enbridge Gas Ontario; • higher storage optimization and pricing at Enbridge Gas Ontario; and • higher distribution margin resulting from increased revenue requirement from recovery of capital investments at Enbridge Gas Ohio and higher base rates at Enbridge Gas North Carolina.RENEWABLE POWER GENERATIONYear ended December 31, 2025 2024 2023(millions of Canadian dollars)Earnings before interest, income taxes and depreciation and amortization 620 733 149 Year ended December 31, 2025 compared with year ended December 31, 2024 EBITDA was positively impacted by $35 million due to certain infrequent or non-operating factors, primarily explained by: • the absence in 2025 of an impairment loss of $55 million related to certain assets; partially offset by • a realized loss of $139 million, partially offset by a non-cash, net unrealized gain of $112 million in 2025, compared with a net unrealized loss of $13 million in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks. After taking into consideration the factors above, the remaining $148 million decrease is primarily explained by the decrease in 2025 of equity earnings related to Fox Squirrel Solar investment tax credits. 71ELIMINATIONS AND OTHERYear ended December 31, 2025 2024 2023(millions of Canadian dollars)Earnings/(loss) before interest, income taxes and depreciation and amortization 1,161 (1,904 ) 916 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 subsidiary. Eliminations and Other also includes our natural gas and power marketing businesses and the impact of new business development activities and corporate investments. Year ended December 31, 2025 compared with year ended December 31, 2024 EBITDA was positively impacted by $3.5 billion due to certain infrequent or non-operating factors, primarily explained by: • a non-cash, net unrealized gain of $1.2 billion in 2025, compared with a net unrealized loss of $2.2 billion in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks; and • the absence in 2025 of $105 million severance costs as a result of a workforce reduction in February 2024. After taking into consideration the non-operating factors above, we saw a $461 million decrease in EBITDA that is primarily explained by: • higher realized foreign exchange losses on hedge settlements in 2025; and • the absence in 2025 of interest income from cash pre-funding related to the Acquisitions. 72GROWTH PROJECTS - COMMERCIALLY SECURED PROJECTSThe following table summarizes the status of our material commercially secured projects, organized by business segment: Enbridge's Ownership Interest Estimated Capital Cost 1Expenditures to Date 2 Status 2 Expected In-Service Date (Canadian dollars, unless stated otherwise)LIQUIDS PIPELINES Mainline Optimization Pre- 1. Phase 1 100% US$1.4 billion US$39 million construction 2027 No significant Southern Illinois expenditures to Pre- 2. Connector 100% 3 US$0.5 billion date construction 2028 No significant expenditures to Pre- 3. Pelican CO 2 Hub 50% US$0.3 billion date construction 2029 GAS TRANSMISSION Texas Eastern 4. Modernization 100% US$0.4 billion US$273 million Various stages 2025 - 2026 T-North Expansion Under 5. (Aspen Point) 100% 4 $1.2 billion $788 million construction 2026 6. Tennessee Ridgeline Expansion 100% US$1.4 billion US$506 million Under construction 2026 7. Woodfibre LNG 5 30% US$2.9 billion US$1.5 billion Under construction 2027 8. T-South Expansion (Sunrise) 100% 4 $4.0 billion $540 million Pre-construction 2028 T-North Expansion Pre- 9. (Birch Grove) 100% 4 $0.4 billion $23 million construction 2028 10. Canyon System Pipelines 100% US$1.0 billion US$154 million Pre-construction 2029 Algonquin Gas No significant Transmission expenditures to Pre- 11. Enhancement 100% US$0.3 billion date construction 2029 No significant USGC Storage Growth expenditures to Pre- 12. Program 100% US$0.5 billion date construction 2028 - 2033 GAS DISTRIBUTION AND STORAGE 13. Moriah Energy Center 6 100% US$0.6 billion US$368 million Under construction 2027 14. T-15 Reliability Project 6,7 100% US$0.7 billion US$98 million Pre-construction 2027 - 2028RENEWABLE POWER GENERATION15. Sequoia Solar 100% US$1.1 billion US$796 million Various stages 2025 - 2026 16. Clear Fork Solar 100% US$0.9 billion US$198 million Under construction 2027 17. Easter 100% US$0.4 billion US$104 million Pre-construction 2026 - 2027 No significant expenditures to Pre- 18. Cowboy Phase 1 100% US$1.2 billion date construction 2027 Courseulles (Calvados) $1.0 billion $444 million Under 19. Offshore Wind 8 21.7% (€0.6 billion) (€303 million) construction 20271 These amounts are estimates and are subject to upward or downward adjustment based on various factors. Where appropriate, the amounts reflect our share of joint venture projects.2 Expenditures to date and status of the project are determined as at December 31, 2025. 73 3 Includes amounts for the construction of the Southern Illinois Connector Pipeline, which is expected to be 50% jointly-owned with Energy Transfer, costs to upgrade the Energy Transfer Crude Oil Pipeline, in which we have a 27.6% ownership interest, as well as amounts fully attributable to Enbridge. 4 Our redeemable noncontrolling interest holder, the First Nations Partnership, will have the opportunity to participate in designated capital programs once they have been completed or substantially completed. As a result, our ownership interest in the program(s) may change in future periods. 5 Our expected investment is approximately US$2.3 billion, with the remainder financed through non-recourse project level debt. 6 Previously approved projects that were acquired by Enbridge through the acquisition of PSNC. 7 Includes approved capital costs for the second phase of the project which involves installation of additional compression to add capacity and is expected to go into service in 2028. 8 Our investment is approximately $0.3 billion, with the remainder financed through non-recourse project level debt. Risks related to the development and completion of growth projects are described in Part I. Item 1A. Risk Factors. LIQUIDS PIPELINES • Mainline Optimization Phase 1 - The Mainline Optimization Phase 1 project is intended to support growing customer demand and long-term production growth in Western Canada, increasing deliveries of Canadian heavy oil to key refining markets in the US Midwest and US Gulf Coast (USGC). The project is expected to add 150 and 100 thousand barrels per day of capacity to our Mainline System and Flanagan South Pipeline (FSP), respectively, through increased horsepower, upstream optimizations and terminal enhancements. The FSP expansion is underpinned by long-term take-or-pay contracts providing full-path service from Edmonton, Alberta to Houston, Texas. In addition, the majority of existing customers also elected to extend their existing FSP full-path contracts beyond 2040. The project is expected to enter service in 2027. • Southern Illinois Connector - The construction of a new 24-inch pipeline from Wood River to Patoka, Illinois, connecting the Platte Pipeline to our jointly-owned Energy Transfer Crude Oil Pipeline. In addition, the project includes new pump stations to provide incremental capacity to the Platte system. Incremental volumes are secured under long-term take-or-pay agreements with investment grade customers. The project has an expected in-service date in 2028. • Pelican CO 2 Hub - A 50/50 joint venture with a subsidiary of Occidental Petroleum Corporation (Oxy) to design, construct and operate a carbon dioxide transportation and sequestration hub in the Louisiana Mississippi River corridor. Oxy will manage the sequestration portions of the project, while Enbridge will manage the pipeline. Development is supported by a long-term take-or-pay offtake agreement with an investment grade counterparty and the facility is expected to enter service in 2029. GAS TRANSMISSION • Texas Eastern Modernization - The modernization of compression facilities in Pennsylvania and New Jersey to increase safety and reliability, as well as to reduce associated greenhouse gas emissions at multiple sites on our Texas Eastern system. The program has entered into service in stages over a period of years beginning in 2024, with all phases expected to be completed in 2026. • T-North Expansion (Aspen Point) - An expansion of our BC Pipeline system in northern BC that includes pipeline looping, additional compressor units and ancillary station modifications to support 535 million cubic feet per day (mmcf/d) of additional capacity. This expansion is expected to serve growing regional demand for natural gas and potential West Coast LNG exports and is underpinned by a cost-of-service commercial model with a target in-service date in 2026. • Tennessee Ridgeline Expansion - An expansion of the East Tennessee Natural Gas system that will provide additional natural gas for the Tennessee Valley Authority (TVA) to support the replacement of an existing coal-fired power plant as TVA continues to transition its power generation mix towards lower-carbon fuels. The proposed scope includes the installation of approximately 125 miles of 30-inch pipeline looping, one electric-powered compressor station and an 8-megawatt (MW) behind-the-meter solar array. We expect the project to enter service in 2026. 74 • Woodfibre LNG Project - Liquefaction and floating storage facilities in Squamish, BC, and an expansion of our BC Pipeline system, the construction of which is executed by our partner. Enbridge holds a noncontrolling equity interest in the project which is expected to be placed into service in 2027. Enbridge and its partners have agreed to updated commercial terms for the Woodfibre LNG Project. The preferred return will be set closer to completion of construction, de-risking Enbridge's return on capital, and our expected share of capital costs was updated in 2025. • T-South Expansion (Sunrise) - An expansion of our BC Pipeline system's T-South section that includes pipeline looping, additional compressor units and ancillary station modifications to support 300 mmcf/d of additional capacity. This expansion is driven primarily by an anticipated shortfall in capacity to deliver gas to the BC Lower Mainland and US Pacific Northwest markets following the commencement of deliveries to the Woodfibre LNG Project. The project is underpinned by a cost-of-service commercial model and is expected to be placed into service in 2028. In 2026, the CER recommended the project for approval to the Government of Canada's Governor in Council. • T-North Expansion (Birch Grove) - An expansion of our BC Pipeline system in northern BC that includes pipeline looping and ancillary station modifications to support 178 mmcf/d of additional capacity. The project is underpinned by a cost-of-service commercial model with a target in-service date in 2028. This expansion is driven by the need for natural gas producers in northeastern BC to access markets for their growing production, mainly from the prolific Montney formation. We expect to file our regulatory application for this project with the CER in the second quarter of 2026. • Canyon System Pipelines - The construction of two new offshore pipelines and additional crude oil and natural gas pipeline extensions to support bp's Kaskida and Tiber offshore developments in the USGC. This will include a 24/26-inch oil pipeline connecting to Shell Pipeline Company LP's Green Canyon 19 Platform and a 12-inch gas pipeline connecting to our existing Magnolia Gas Gathering Pipeline. The project is expected to enter service in 2029. • Algonquin Gas Transmission Enhancement - An enhancement of our Algonquin Pipeline to serve incremental demand across the northeastern US. The project is anticipated to enhance supply reliability and improve affordability by reducing winter price volatility for customers. We expect the project to enter service in 2029. • USGC Storage Growth Program - An expansion of our Egan Hub and Moss Bluff natural gas storage facilities in the USGC, to provide 16 billion cubic feet (Bcf) and 7 Bcf of new site capacity, respectively. Egan Hub will be expanded over two phases, with each phase expected to enter service in 2030 and 2033, respectively. The expansion of our Moss Bluff facility is expected to enter service in 2028. These projects are expected to improve site injection and withdrawal rates, optimizing existing capacity, and to offer storage capacity to USGC LNG facilities during periods of high demand. GAS DISTRIBUTION AND STORAGE • Moriah Energy Center - The construction of an LNG facility in Person County, North Carolina with 2 bcf of storage capacity. The facility is expected to enhance system reliability and to address supply constraints due to customer growth, and will be designed with trucking capabilities to support other LNG facilities. The project has an expected in-service date in 2027. • T-15 Reliability Project - Includes the construction of 45 miles of transmission pipe, a compressor station, and associated metering and regulation facilities in Rockingham, Caswell and Person counties in North Carolina. The project has a two-phased completion in 2027 and 2028. 75RENEWABLE POWER GENERATION• Sequoia Solar - An 815 MW solar farm located approximately 150 miles west of Dallas, Texas. The first phase of the project was completed in the fourth quarter of 2025, with the second phase expected to enter service in late 2026. Project revenues are underpinned by long-term fixed price power purchase agreements (PPA). • Clear Fork Solar - A 600 MW solar farm located near San Antonio, Texas, fully contracted under a long-term offtake agreement. The project has an expected in-service date in 2027. • Easter - A 152 MW onshore wind project near Amarillo, Texas, fully contracted under a long-term offtake agreement. The two-phased project is expected to achieve completion in 2026 and 2027. • Cowboy Phase 1 - A 365 MW solar farm and an on-site battery energy storage system (BESS), both located near Cheyenne, Wyoming. Renewable power generated by this project is fully contracted under a long-term offtake agreement and BESS capacity is contracted through a long-term fixed-price battery tolling agreement. BESS is currently approved for 135 MW, expandable up to 200 MW with further utility review and approval. Both components of the project are expected to fully enter service in 2027. • Courseulles (Calvados) Offshore Wind - An offshore wind project located off the northwest coast of France that is expected to generate approximately 448 MW of power. The project has an expected in-service date in 2027 and revenues are underpinned by a 20-year fixed price PPA. OTHER ANNOUNCED PROJECTS UNDER DEVELOPMENT LIQUIDS PIPELINES Mainline Optimization Phase 2 On November 7, 2025, we announced the Mainline Optimization Phase 2 (MLO2) project. MLO2 is expected to provide an additional 250 thousand barrels per day of egress from the Western Canadian Sedimentary Basin, leveraging capacity on our existing assets including the Dakota Access Pipeline, in which we have a 27.6% interest, Line 26 and the Chicap Pipeline system. The project is expected to enter service in 2028 and is subject to finalizing commercial agreements, securing the necessary environmental and regulatory approvals, and meeting investment criteria.LIQUIDITY AND CAPITAL RESOURCESThe maintenance of financial strength and flexibility is fundamental to our growth strategy, particularly in light of the significant number and size of capital projects currently secured or under development. Access to timely funding from capital markets could be limited by factors outside our control, including but not limited to, financial market volatility resulting from economic and political events both inside and outside North America. To mitigate such risks, we actively manage financial plans and strategies to help ensure we maintain sufficient liquidity to meet routine operating and future capital requirements. In the near term, we generally expect to utilize cash from operations together with commercial paper issuances and/or credit facility draws and the proceeds of capital market offerings to fund liabilities as they become due, finance capital expenditures and acquisitions and fund debt retirements. We target to maintain sufficient liquidity through securement of committed credit facilities with a diversified group of banks and financial institutions to enable us to fund all anticipated requirements for approximately one year without accessing the capital markets. Material contractual obligations arising in the normal course of business primarily consist of long-term contracts, annual debt maturities and related interest obligations, rights-of-way and leases. See Part II. Item 8. Financial Statements and Supplementary Data - Note 17 - Debt, Note 26 - Leases and Note 30 - Commitments and Contingencies for amounts outstanding at December 31, 2025. 76 Long-term contracts are contracts that we have signed for the purchase of services, pipe and other materials totaling $14.0 billion which are expected to be paid over the next five years. Long-term contracts primarily consist of the following purchase obligations: firm capacity payments for natural gas and crude oil transportation and storage contracts, natural gas purchase commitments and power commitments. Our financing plan is regularly updated to reflect evolving capital requirements and financial market conditions and identifies a variety of potential sources of debt and equity funding alternatives.CAPITAL MARKET ACCESSWe enable access to capital markets, subject to market conditions, through maintenance of shelf prospectuses that allow for issuances of long-term debt, equity and other forms of long-term capital when market conditions are attractive. In accordance with our funding plan, we completed the following long-term debt issuances totaling $4.6 billion and US$4.7 billion in 2025. Entity Issuance date Type of issuance Amount (millions of Canadian dollars, unless otherwise stated) Enbridge Inc. February 2025 Floating rate notes $400 Enbridge Inc. February 2025 Medium-term notes $2,400 Enbridge Inc. June 2025 Senior notes US$2,250 Enbridge Inc. September 2025 Fixed-to-fixed subordinated notes $1,000 Enbridge Inc. November 2025 Senior notes US$1,500 Enbridge Gas Inc. September 2025 Medium-term notes $800 The East Ohio Gas Company June 2025 Senior notes US$500 The East Ohio Gas Company December 2025 Senior notes US$400 Credit Facilities and Liquidity To ensure ongoing liquidity and to mitigate the risk of capital market disruption, we maintain access to funds through committed bank credit facilities and actively manage our bank funding sources to optimize pricing and other terms. The following table provides details of our committed credit facilities as at December 31, 2025:Maturity 1Total Facility Draws 2Available (millions of Canadian dollars)Enbridge Inc. 2027-2049 8,033 6,488 1,545 Enbridge (U.S.) Inc. 2027-2030 10,307 4,636 5,671 Enbridge Pipelines Inc. 2027 2,000 1,024 976 Enbridge Gas Inc. 2027 2,500 1,030 1,470 Total committed credit facilities 22,840 13,178 9,6621 Maturity date is inclusive of the one-year term out option for certain credit facilities. 2 Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.In July 2025, we renewed approximately $8.8 billion of our 364-day extendible credit facilities, extending the maturity dates to July 2027, which includes a one-year term out provision from July 2026. We also renewed approximately $7.8 billion of our five-year credit facilities, extending the maturity dates to July 2030. Further, we extended the maturity dates of our three-year credit facilities to July 2028. In July 2025, Enbridge Gas Ontario and Enbridge Pipelines Inc. extended the maturity dates of their $2.5 billion and $2.0 billion 364-day extendible credit facilities, respectively, to July 2027, which includes a one-year term out provision from July 2026. 77 In addition to the committed credit facilities noted above, we maintain $1.6 billion of uncommitted demand letter of credit facilities, of which $932 million was unutilized as at December 31, 2025. As at December 31, 2024, we had $1.4 billion of uncommitted demand letter of credit facilities, of which $931 million was unutilized. As at December 31, 2025, our net available liquidity totaled $10.8 billion (December 31, 2024 - $14.4 billion), consisting of available credit facilities of $9.7 billion (December 31, 2024 - $12.6 billion) and unrestricted cash and cash equivalents of $1.1 billion (December 31, 2024 - $1.8 billion) as reported in the Consolidated Statements of Financial Position. Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at December 31, 2025, we were in compliance with all such debt covenant provisions. Cash flow growth, ready access to liquidity from diversified sources and a stable business model have enabled us to manage our credit profile. We actively monitor and manage key financial metrics with the objective of sustaining investment grade credit ratings from the major credit rating agencies and ongoing access to bank funding and term debt capital on attractive terms. Key measures of financial strength that are closely managed include the ability to service debt obligations from operating cash flow and the ratio of debt to EBITDA. There are no material restrictions on our cash. Total restricted cash of $83 million, as reported in the Consolidated Statements of Financial Position, primarily includes reinsurance security, cash collateral, future pipeline abandonment costs collected and held in trust, amounts received in respect of specific shipper commitments and capital projects. Cash and cash equivalents held by certain subsidiaries may not be readily accessible for alternative uses by us. Excluding current maturities of long-term debt, as at December 31, 2025 and December 31, 2024, we had negative working capital positions of $2.8 billion and $2.9 billion, respectively. In both 2025 and 2024, the major contributing factors to the negative working capital position were the current liabilities associated with our growth capital program. To address this negative working capital position, we maintain significant liquidity in the form of committed credit facilities and other sources as previously discussed, which enable the funding of liabilities as they become due.SOURCES AND USES OF CASHYear ended December 31, 2025 2024 2023(millions of Canadian dollars)Operating activities 12,270 12,600 14,201 Investing activities (10,503 ) (20,363 ) (6,043 ) Financing activities (2,400 ) 3,544 (2,864 ) Effect of translation of foreign denominated cash and cash equivalents and restricted cash (47 ) 234 (216 ) Net change in cash and cash equivalents and restricted cash (680 ) (3,985 ) 5,078 78 Significant sources and uses of cash for the years ended December 31, 2025 and 2024 are summarized below:Operating ActivitiesTypically, the primary factors impacting cash provided by operating activities year-over-year include changes in our operating assets and liabilities in the normal course due to various factors, including the impact of fluctuations in commodity prices and activity levels on working capital within our business segments, the timing of tax payments, as well as timing of cash receipts and payments generally. Refer to Part II. Item 8. Financial Statements and Supplementary Data - Note 28 - Changes in Operating Assets and Liabilities. Cash provided by operating activities is also impacted by changes in earnings and certain infrequent or other non-operating factors, as discussed in Results of Operations , as well as Distributions from equity investments.Investing ActivitiesCash used in investing activities primarily relates to capital expenditures to execute our capital program, which is further described in Growth Projects - Commercially Secured Projects . The timing of project approval, construction and in-service dates impacts the timing of cash requirements. Cash used in investing activities is also impacted by acquisitions, dispositions, and changes in contributions to, and distributions from, our equity investments. A summary of cash additions to property, plant and equipment for the years ended December 31, 2025, 2024 and 2023 is set out below: Year ended December 31, 2025 20242023(millions of Canadian dollars) Liquids Pipelines 1,358 1,157 1,158 Gas Transmission 3,176 2,453 1,890 Gas Distribution and Storage 3,318 2,381 1,451 Renewable Power Generation 947 661 100 Eliminations and Other 174 59 55 Total capital expenditures 8,973 6,711 4,654 2025The decrease in cash used in investing activities primarily resulted from the following factors:• the absence in 2025 of the acquisitions of EOG, Questar, PSNC, and Tomorrow RNG; • the absence in 2025 of the acquisitions of equity interests in the Whistler Parent JV and DBR and contributions to our Fox Squirrel Solar investment; partially offset by • the absence in 2025 of proceeds received from the disposition of our interests in the Alliance Pipeline, Aux Sable, and NRGreen Power Limited Partnership (NRGreen); and • a full year of capital expenditures from EOG, Questar, and PSNC, and higher capital expenditures from growth projects in our Gas Transmission and Renewable Power Generation segments. 2024 The increase in cash used in investing activities primarily resulted from the following factors: • the acquisitions of EOG, Questar, PSNC, and Tomorrow RNG in 2024; • increased capital expenditures from the acquisitions of EOG, Questar and PSNC and from growth projects in our Gas Transmission segment; and • the acquisition of an equity interest in the Whistler Parent JV and DBR and contributions to our Fox Squirrel Solar investment in 2024; partially offset by • proceeds received from the dispositions of our interests in the Alliance Pipeline, Aux Sable, and NRGreen in 2024. 79Financing ActivitiesCash used in financing activities primarily relates to issuances and repayments of external debt, as well as transactions with our common and preference shareholders relating to dividends, share issuances, and share redemptions. Cash used in financing activities is also impacted by changes in distributions to, and contributions from, noncontrolling interests and redeemable noncontrolling interest. 2025The increase in cash used in financing activities primarily resulted from the following factors:• lower commercial paper and credit facility draws in 2025 compared to 2024; and • the absence in 2025 of the at-the-market program, which resulted in the issuance of 51,298,629 common shares for aggregate net proceeds of $2.5 billion in 2024; partially offset by • higher long-term debt issuances in 2025 compared to 2024, and • proceeds of $712 million, net of transaction costs, received from the First Nations Partnership for their noncontrolling interest investment in our BC pipeline system. 2024 The increase in cash provided by financing activities primarily resulted from the following factors: • net commercial paper and credit facility draws in 2024 compared to net repayments in 2023; • the at-the-market program, which resulted in the issuance of 51,298,629 common shares for aggregate net proceeds of $2.5 billion in 2024; and • lower net repayments of short-term borrowings in 2024 compared to 2023; partially offset by • higher long-term debt repayments and lower long-term debt issuances in 2024 compared to 2023; • the absence in 2024 of the public offering of common shares, which closed on September 8, 2023 for gross proceeds of $4.6 billion; and • increased common share dividend payments primarily due to the increase in our common share dividend rate and an increase in the number of common shares outstanding. OFF -BALANCE SHEET ARRANGEMENTSWe enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties and can include financial guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. Please see Part II. Item 8. Financial Statements and Supplementary Data - Note 31 - Guarantees for further discussion of guarantee arrangements.We do not have material off-balance sheet financing entities or structures, except for guarantee arrangements and financings entered into for our equity investments. For additional information on these commitments, please refer to Part II. Item 8. Financial Statements and Supplementary Data - Note 30 - Commitments and Contingencies and Note 12 - Variable Interest Entities .We do not have material off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.80OUTSTANDING PREFERENCE SHARES Characteristics of our outstanding preference shares are as follows:Dividend Rate Dividend 1 Per Share Base Redemption Value 2,3 Redemption and Conversion Option Date 2,3 Right to Convert Into 3,4(Canadian dollars unless otherwise stated)Preference Shares, Series A 5.50% $1.37500 $25 — — Preference Shares, Series B 5.20% $1.30050 $25 June 1, 2027 Series C Preference Shares, Series D 5.41% $1.35300 $25 March 1, 2028 Series E Preference Shares, Series F 5.54% $1.38450 $25 June 1, 2028 Series G Preference Shares, Series G 5 4.84% $1.21000 $25 June 1, 2028 Series F Preference Shares, Series H 6.11% $1.52800 $25 September 1, 2028 Series I Preference Shares, Series I 6 4.45% $1.11250 $25 September 1, 2028 Series H Preference Shares, Series L 5.86% US$1.46448 US$25 September 1, 2027 Series M Preference Shares, Series N 6.70% $1.67400 $25 December 1, 2028 Series O Preference Shares, Series P 5.92% $1.47950 $25 March 1, 2029 Series Q Preference Shares, Series R 6.31% $1.57850 $25 June 1, 2029 Series S Preference Shares, Series 1 6.70% US$1.67593 US$25 June 1, 2028 Series 2 Preference Shares, Series 3 5.29% $1.32200 $25 September 1, 2029 Series 4 Preference Shares, Series 4 7 4.71% $1.17750 $25 September 1, 2029 Series 3 Preference Shares, Series 5 6.68% US$1.67075 US$25 March 1, 2029 Series 6 Preference Shares, Series 7 5.99% $1.49700 $25 March 1, 2029 Series 8 Preference Shares, Series 9 5.67% $1.41800 $25 December 1, 2029 Series 10 Preference Shares, Series 11 8 5.48% $1.36925 $25 March 1, 2030 Series 12 Preference Shares, Series 13 9 5.40% $1.34875 $25 June 1, 2030 Series 14 Preference Shares, Series 15 10 5.63% $1.40650 $25 September 1, 2030 Series 16 Preference Shares, Series 19 6.21% $1.55300 $25 March 1, 2028 Series 20 1 The holder is entitled to receive a fixed cumulative quarterly preferential dividend, as declared by the Board of Directors. With the exception of Preference Shares, Series A, such fixed dividend rate resets every five years beginning on the initial Redemption and Conversion Option Date. Preference Shares, Series G, Series I and Series 4 contain a feature where the dividend rate resets on a quarterly basis. The Preference Shares, Series 19 contain a feature where the fixed dividend rate, when reset every five years, will not be less than 4.90%. No other series of preference shares has this feature.2 Preference Shares, Series A may be redeemed any time at our option. For all other series of preference shares, we may at our option, redeem all or a portion of the outstanding preference shares for the Per Share Base Redemption Value plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter. 3 The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on a one-for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an ascribed issue price equal to the Per Share Base Redemption Value.4 With the exception of Preference Shares, Series A, after the Redemption and Conversion Option Date, holders may elect to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/number of days in year) x three-month Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q), 2.5% (Series S), 2.4% (Series 4), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7% (Series 16), or 3.2% (Series 20); or US$25 x (number of days in quarter/number of days in year) x three-month US Government treasury bill rate + 3.2% (Series M), 3.1% (Series 2), or 2.8% (Series 6). 5 The quarterly dividend per share paid on Preference Shares, Series G was decreased to $0.29836 from $0.32411 on December 1, 2025 due to reset on a quarterly basis. 6 The quarterly dividend per share paid on Preference Shares, Series I was decreased to $0.27432 from $0.29980 on December 1, 2025 due to reset on a quarterly basis. 7 The quarterly dividend per share paid on Preference Shares, Series 4 was decreased to $0.29034 from $0.31601 on December 1, 2025 due to reset on a quarterly basis. 8 The quarterly dividend per share paid on Preference Shares, Series 11 was increased to $0.34231 from $0.24613 on March 1, 2025,due to the reset of the annual dividend on March 1, 2025. 9 The quarterly dividend per share paid on Preference Shares, Series 13 was increased to $0.33719 from $0.19019 on June 1, 2025 due to the reset of the annual dividend on June 1, 2025. 10 The quarterly dividend per share paid on Preference Shares, Series 15 was increased to $0.35163 from $0.18644 on September 1, 2025 due to the reset of the annual dividend on September 1, 2025.DIVIDENDSWe have paid common share dividends in every year since we became a publicly traded company in 1953. In December 2025, we announced a 3% increase in our quarterly dividend to $0.9700 per common share, or $3.88 annualized, effective with the dividend payable on March 1, 2026, thereby declaring a dividend increase for 31 straight years. 81 For the years ended December 31, 2025 and 2024, total dividends paid in cash were $8.2 billion and $7.9 billion, respectively, which are reflected in Cash Flows from Financing Activities in the Consolidated Statements of Cash Flows. On December 2, 2025, our Board of Directors declared the following quarterly dividends. All dividends are payable on March 1, 2026 to shareholders of record on February 17, 2026.Dividend per share Common Shares 1$0.9700 Preference Shares, Series A $0.34375 Preference Shares, Series B $0.32513 Preference Shares, Series D $0.33825 Preference Shares, Series F $0.34613Preference Shares, Series G 2$0.29836 Preference Shares, Series H $0.38200Preference Shares, Series I 3$0.27432 Preference Shares, Series L US$0.36612 Preference Shares, Series N$0.41850Preference Shares, Series P $0.36988 Preference Shares, Series R $0.39463 Preference Shares, Series 1 US$0.41898 Preference Shares, Series 3 $0.33050 Preference Shares, Series 4 4 $0.29034 Preference Shares, Series 5 US$0.41769 Preference Shares, Series 7 $0.37425 Preference Shares, Series 9 $0.35450 Preference Shares, Series 11 $0.34231 Preference Shares, Series 13 $0.33719 Preference Shares, Series 15 $0.35163 Preference Shares, Series 19 $0.38825 1 The quarterly dividend per common share was increased 3% to $0.9700 from $0.9425, effective March 1, 2026. 2 The quarterly dividend per share paid on Preference Shares, Series G was decreased to $0.29836 from $0.32411 on December 1, 2025 due to reset on a quarterly basis. 3 The quarterly dividend per share paid on Preference Shares, Series I was decreased to $0.27432 from $0.29980 on December 1, 2025 due to reset on a quarterly basis. 4 The quarterly dividend per share paid on Preference Shares, Series 4 was decreased to $0.29034 from $0.31601 on December 1, 2025 due to reset on a quarterly basis. 82SUMMARIZED FINANCIAL INFORMATIONOn January 22, 2019, Enbridge entered into supplemental indentures with its wholly-owned subsidiaries, Spectra Energy Partners, LP (SEP) and EEP (together, the Partnerships), pursuant to which Enbridge fully and unconditionally guaranteed, on a senior unsecured basis, the payment obligations of the Partnerships with respect to the outstanding series of notes issued under the respective indentures of the Partnerships. Concurrently, the Partnerships entered into a subsidiary guarantee agreement pursuant to which they fully and unconditionally guaranteed, on a senior unsecured basis, the outstanding series of senior notes of Enbridge. The Partnerships have also entered into supplemental indentures with Enbridge pursuant to which the Partnerships have issued full and unconditional guarantees, on a senior unsecured basis, of senior notes issued by Enbridge subsequent to January 22, 2019. As a result of the guarantees, holders of any of the outstanding guaranteed notes of the Partnerships (the Guaranteed Partnership Notes) are in the same position with respect to the net assets, income and cash flows of Enbridge as holders of Enbridge's outstanding guaranteed notes (the Guaranteed Enbridge Notes), and vice versa. Other than the Partnerships, Enbridge subsidiaries (including the subsidiaries of the Partnerships, collectively, the Subsidiary Non-Guarantors), are not parties to the subsidiary guarantee agreement and have not otherwise guaranteed any of Enbridge's outstanding series of senior notes. Consenting SEP notes and EEP notes under GuaranteesSEP Notes 1 EEP Notes 23.38% Senior Notes due 2026 5.95% Notes due 2033 5.95% Senior Notes due 2043 6.30% Notes due 2034 4.50% Senior Notes due 2045 7.50% Notes due 2038 5.50% Notes due 2040 7.38% Notes due 2045 1 As at December 31, 2025, the aggregate outstanding principal amount of SEP notes was approximately US$1.7 billion. 2 As at December 31, 2025, the aggregate outstanding principal amount of EEP notes was approximately US$1.9 billion. 83Enbridge Notes under Guarantees USD Denominated 1 CAD Denominated 21.60% Senior Notes due 2026 3.20% Senior Notes due 2027 5.90% Senior Notes due 2026 5.70% Senior Notes due 2027 4.25% Senior Notes due 2026 3.55% Senior Notes due 2028 5.25% Senior Notes due 2027 4.90% Senior Notes due 2028 3.70% Senior Notes due 2027 6.10% Senior Notes due 2028 4.60% Senior Notes due 2028 Floating Rate Senior Notes due 2028 6.00% Senior Notes due 2028 2.99% Senior Notes due 2029 4.20% Senior Notes due 2028 4.21% Senior Notes due 2030 5.30% Senior Notes due 2029 3.90% Senior Notes due 2030 3.13% Senior Notes due 2029 7.22% Senior Notes due 2030 4.90% Senior Notes due 2030 7.20% Senior Notes due 2032 6.20% Senior Notes due 2030 6.10% Sustainability-Linked Senior Notes due 2032 4.50% Senior Notes due 2031 5.36% Sustainability-Linked Senior Notes due 2033 5.70% Sustainability-Linked Senior Notes due 2033 3.10% Sustainability-Linked Senior Notes due 2033 2.50% Sustainability-Linked Senior Notes due 2033 4.73% Senior Notes due 2034 5.63% Senior Notes due 2034 4.56% Senior Notes due 2035 5.55% Senior Notes due 2035 5.57% Senior Notes due 2035 5.20% Senior Notes due 2035 5.75% Senior Notes due 2039 4.50% Senior Notes due 2044 5.12% Senior Notes due 2040 5.50% Senior Notes due 2046 4.24% Senior Notes due 2042 4.00% Senior Notes due 2049 4.57% Senior Notes due 2044 3.40% Senior Notes due 2051 4.87% Senior Notes due 2044 6.70% Senior Notes due 2053 4.10% Senior Notes due 2051 5.95% Senior Notes due 2054 6.51% Senior Notes due 2052 5.76% Senior Notes due 2053 5.32% Senior Notes due 2054 4.56% Senior Notes due 2064 1 As at December 31, 2025, the aggregate outstanding principal amount of the Enbridge US dollar-denominated notes was approximately US$19.8 billion. 2 As at December 31, 2025, the aggregate outstanding principal amount of the Enbridge Canadian dollar-denominated notes was approximately $$14.5 billion. Rule 3-10 of the US SEC Regulation S-X provides an exemption from the reporting requirements of the Exchange Act for fully consolidated subsidiary issuers of guaranteed securities and subsidiary guarantors and allows for summarized financial information in lieu of filing separate financial statements for each of the Partnerships. 84 The following Summarized Combined Statement of Earnings and Summarized Combined Statements of Financial Position combines the balances of SEP, EEP, and Enbridge.Summarized Combined Statement of EarningsYear ended December 31, 2025(millions of Canadian dollars)Operating loss (63 ) Earnings 2,826 Earnings attributable to common shareholders 2,407Summarized Combined Statements of Financial PositionDecember 31, 2025 2024(millions of Canadian dollars)Cash and cash equivalents 391 2,000 Accounts receivable from affiliates 3,873 3,901 Short-term loans receivable from affiliates 6,239 3,892 Other current assets 467 499 Long-term loans receivable from affiliates 46,858 54,416 Other long-term assets 1,994 2,139 Accounts payable to affiliates 2,079 2,252 Short-term loans payable to affiliates 2,082 1,188 Trade payables and accrued liabilities 537 661 Other current liabilities 6,990 8,047 Long-term loans payable to affiliates 34,488 36,576 Other long-term liabilities 67,004 62,642The Guaranteed Enbridge Notes and the Guaranteed Partnership Notes are structurally subordinated to the indebtedness of the Subsidiary Non-Guarantors in respect of the assets of those Subsidiary Non-Guarantors. Under US bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee can be voided, or claims may be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time the indebtedness evidenced by its guarantee or, in some states, when payments become due under the guarantee: • received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee and was insolvent or rendered insolvent by reason of such incurrence; • was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or • intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they mature. The guarantees of the Guaranteed Enbridge Notes contain provisions to limit the maximum amount of liability that the Partnerships could incur without causing the incurrence of obligations under the guarantee to be a fraudulent conveyance or fraudulent transfer under US federal or state law. Each of the Partnerships is entitled to a right of contribution from the other Partnership for 50% of all payments, damages and expenses incurred by that Partnership in discharging its obligations under the guarantees for the Guaranteed Enbridge Notes.Under the terms of the guarantee agreement and applicable supplemental indentures, the guarantees of either of the Partnerships of any Guaranteed Enbridge Notes will be unconditionally released and discharged automatically upon the occurrence of any of the following events:85• any direct or indirect sale, exchange or transfer, whether by way of merger, sale or transfer of equity interests or otherwise, to any person that is not an affiliate of Enbridge, of any of Enbridge’s direct or indirect limited partnership of other equity interests in that Partnership as a result of which the Partnership ceases to be a consolidated subsidiary of Enbridge; • the merger of that Partnership into Enbridge or the other Partnership or the liquidation and dissolution of that Partnership; • the repayment in full or discharge or defeasance of those Guaranteed Enbridge Notes, as contemplated by the applicable indenture or guarantee agreement; • with respect to EEP, the repayment in full or discharge or defeasance of each of the consenting EEP notes listed above; • with respect to SEP, the repayment in full or discharge or defeasance of each of the consenting SEP notes listed above; or • with respect to any series of Guaranteed Enbridge Notes, with the consent of holders of at least a majority of the outstanding principal amount of that series of Guaranteed Enbridge Notes. The guarantee obligations of Enbridge will terminate with respect to any series of Guaranteed Partnership Notes if that series is discharged or defeased.The Partnerships also guarantee the obligations of Enbridge under its existing credit facilities.LEGAL AND OTHER UPDATESLINE 5 EASEMENT (BAD RIVER BAND) On July 23, 2019, the Bad River Band of the Lake Superior Tribe of Chippewa Indians (the Band) filed a complaint in the US District Court for the Western District of Wisconsin (the Court) over our Line 5 pipeline and right-of-way across the Bad River Reservation (the Reservation). Only a small portion of the total easements across 12 miles of the Reservation are at issue. The Band alleges that the continued operation of Line 5 across the Reservation constitutes a public nuisance under federal and state law and that the pipeline is in trespass on certain tracts of land where the Band holds ownership interests. The complaint seeks an Order prohibiting us from using Line 5 to transport crude oil and related liquids across the Reservation and requiring removal of the pipeline from the Reservation. Subsequently amended versions of the complaint also seek recovery of profits-based damages based on an unjust enrichment theory. Enbridge has responded to each claim in the initial and amended complaints with answers, defenses and counterclaims. On August 29, 2022, the Government of Canada released a statement formally invoking the dispute settlement provisions of the Agreement Between the US and Canada Concerning Transit Pipelines, 28 U.S.T. 7449 (1977) (1977 Transit Pipelines Treaty) in respect of this litigation, reiterating its concerns about the uninterrupted transmission of hydrocarbons through Line 5. On September 7, 2022, the Court issued a decision on cross-motions for summary judgment. The Court determined that the Band's nuisance claim raised factual issues that could not be resolved on summary judgment. The Court further determined that Enbridge is in trespass on 12 parcels on the Reservation and that the Band is entitled to some measure of profits-based damages and injunctive relief, with the level of damages and scope of the injunction to be determined at trial. The trial was held from October 24 to November 1, 2022. On May 9, 2023, the Band filed an Emergency Motion for Injunctive Relief requesting that the Court order Enbridge to purge and shutdown Line 5 on the Reservation due to significant erosion at a river bend known as Meander. After a hearing on May 18, 2023, the Court stated the Band had not demonstrated imminent harm and indicated a final ruling would follow. 86 On June 26, 2023, the Court issued its Final Order ruling that: (1) Enbridge shall adopt and implement its 2022 Monitoring and Shutdown Plan with the Court's modifications by July 5, 2023; (2) Enbridge owes the Band $5,151,668 for past trespass on the 12 allotted parcels; (3) Enbridge must continue to make quarterly payments using the Court's formula, for as long as Line 5 operates in trespass on those parcels (approximately $400,000 per year); (4) Enbridge must cease operation of Line 5 on any parcel within the Band's tribal territory lacking a valid right-of-way by June 16, 2026 and thereafter arrange prompt, reasonable remediation at those sites; and (5) The Court declined to allow for completion of the Wisconsin Relocation Project prior to having to cease operations. The Final Judgment was entered on June 29, 2023. Enbridge filed its Notice of Appeal on June 30, 2023 and the Band filed its Notice of Cross Appeal on July 27, 2023. On December 12, 2023, the US Court of Appeals for the Seventh Circuit requested that the US file a brief in the appeal as amicus curiae to address the effect of 1977 Transit Pipelines Treaty, and any other issues that the US believes to be material. The US filed its brief on April 8, 2024. As invited by the Court of Appeals, on April 29, 2024, Enbridge and the Band filed responses to the US amicus brief. A decision from the Court of Appeals is expected in early 2026. On January 27, 2026, Enbridge filed a Motion to Stay or Modify the portion of the Court’s June 29, 2023 Final Judgment requiring Enbridge to cease operation of Line 5 on any parcel without a valid right-of-way by June 16, 2026. In March 2025, after receiving authorizations from tribal, federal, and state agencies, an erosion mitigation project was successfully installed at the Meander. MICHIGAN LINE 5 DUAL PIPELINES - STRAITS OF MACKINAC EASEMENT Michigan Attorney General Lawsuit In 2019, the Michigan Attorney General initiated legal action in the Michigan Ingham County Circuit Court (Michigan Circuit Court) seeking to invalidate the 1953 easement that authorizes the operation of Enbridge’s Line 5 pipeline in the Straits of Mackinac. The Attorney General’s case was later moved to US federal court in December 2021, following a November 16, 2021 ruling which held that the similar (and now dismissed) 2020 lawsuit brought by the Governor of Michigan to force the shutdown of Line 5 raised important federal issues that should be heard in federal court. In June 2024, the US Court of Appeals for the Sixth Circuit (Sixth Circuit) ruled that the case should proceed in state court. Enbridge’s request for a rehearing was denied in August 2024. Oral argument on long-standing cross motions for summary disposition was held in January 2025 in the Michigan Circuit Court. A decision is expected in 2026. Separately, in January 2025, Enbridge petitioned the US Supreme Court to review the Sixth Circuit’s decision. The Court granted the petition in June 2025. Briefing is complete, with oral argument and a decision expected in 2026. In the interim, Enbridge requested that the Michigan Circuit Court pause proceedings pending the US Supreme Court’s ruling. This motion was denied. In parallel, the US Army Corps of Engineers (Army Corps) announced in April 2025 that the Line 5 Tunnel Project qualified for review under emergency and special processing procedures. On November 13, 2025, the Army Corps issued a Supplemental Draft Environmental Impact Statement with a public comment period ending in December 2025. On February 6, 2026, the Army Corps issued its Final Environmental Impact System. We expect a Record of Decision to be issued in 2026. Enbridge Lawsuit On November 24, 2020, Enbridge filed a complaint in the US District Court in the Western District for Michigan (US District Court) seeking declaratory and injunctive relief to prevent the Governor of Michigan and Director of the Michigan Department of Natural Resources (Michigan State Officials) from interfering with the continued operation of Line 5. The Government of Canada has reiterated its support for the pipeline, emphasizing the relevance of the 1977 Transit Pipelines Treaty and the matter’s importance to Canada. 87 In January 2022, Michigan State Officials moved to dismiss the case, and Enbridge filed for summary judgment. On July 5, 2024, the US District Court denied the state’s motion to dismiss, prompting an immediate appeal to the Sixth Circuit. The case was stayed pending the outcome of the appeal. On April 23, 2025, the Sixth Circuit affirmed the US District Court’s ruling and a petition for rehearing en banc was denied on June 16, 2025. On June 24, 2025, the case was administratively transferred back to the US District Court and Michigan State Officials filed their Answer to Enbridge’s complaint. A case management order was issued on July 14, 2025, setting out a briefing schedule for Enbridge’s summary judgment motion and the state’s motion to abstain. On September 12, 2025, the US filed a statement of interest in the case. Briefing concluded on October 10, 2025 and oral argument was held on November 12, 2025. On December 17, 2025, the US District Court entered judgment in Enbridge’s favor and denied the Michigan State Officials motion to abstain or stay the federal action. In January 2026, the Michigan State Officials filed an appeal, and shortly thereafter in the Michigan Circuit Court, Enbridge and the Michigan Attorney General filed a stipulation to stay the Michigan Attorney General Lawsuit, pending the Sixth Circuit's decision. DAKOTA ACCESS PIPELINE We hold an effective 27.6% interest in the Bakken Pipeline System, which includes the Dakota Access Pipeline (DAPL). The Standing Rock Sioux Tribe and the Cheyenne River Sioux Tribe filed lawsuits in 2016 with the US Court for the District of Columbia (the District Court) challenging the Army Corps’ easement for DAPL, citing concerns over the adequacy of the Army Corps' environmental review and tribal consultation process. The Oglala Sioux and Yankton Sioux Tribes also filed lawsuits alleging similar claims in 2018. In 2017 and again in 2020, the District Court found deficiencies in the Army Corps’ environmental assessments and ordered the preparation of a full Environmental Impact Statement (EIS). In July 2020, the District Court vacated the easement and ordered the pipeline shut down, but that order was stayed by the US Court of Appeals for the District of Columbia. In January 2021, the US Court of Appeals upheld the requirement for an EIS and confirmed the easement’s vacatur, though it ruled that DAPL could continue operating absent an injunction. The US Supreme Court declined to review the case, and the Army Corps indicated it would not seek to halt operations during the review process. On September 8, 2023, the Army Corps released a draft EIS evaluating five alternatives, including continued operation, shutdown, rerouting, and removal of the pipeline. No preferred alternative was identified. The public comment period closed on December 13, 2023. On December 19, 2025, the Army Corps published the final EIS for DAPL. The final EIS includes an extensive analysis of spill risks from the pipeline, including the pipeline safety record of Energy Transfer Crude Oil Pipeline. The Army Corps must wait 30-days after publication of the final EIS before a Record of Decision and new easement may be issued. Accordingly, a Record of Decision and easement are expected in 2026. Separately, on October 15, 2024, the Standing Rock Sioux Tribe filed a new complaint in the District Court seeking a permanent injunction against DAPL’s operation, alleging that the Army Corps is unlawfully allowing continued operations without a valid easement or compliant Facility Response Plan. Dakota Access, LLC and 13 states intervened in support of continued operations. On March 28, 2025, the District Court dismissed the complaint. The Tribe filed a notice of appeal on May 27, 2025. The appeal process is expected to take six to 12 months. 88OTHER LITIGATION We and our subsidiaries are subject to various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our consolidated financial position or results of operations.CRITICAL ACCOUNTING POLICIES AND ESTIMATES Our consolidated financial statements are prepared in accordance with US GAAP, which requires management to make estimates, judgments and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. In making judgments and estimates, management relies on external information and observable conditions, where possible, supplemented by internal analysis as required. We believe our most critical accounting policies and estimates discussed below have an impact across the various segments of our business.GOODWILL IMPAIRMENT Goodwill represents the excess of the purchase price over the fair value of net identifiable assets upon acquisition of a business. The carrying value of goodwill, which is not amortized, is assessed for impairment annually or more frequently if events or changes in circumstances arise that suggest the carrying value of goodwill may be impaired. We perform our annual review of the goodwill balance on April 1.We perform our annual review for impairment at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete information is available, whether segment management regularly reviews the operating results of those components, and whether the economic and regulatory characteristics are similar. Our reporting units are Liquids Pipelines, Gas Transmission, Gas Distribution and Storage, and Renewable Power Generation. We have the option to first assess qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment assessment. When performing a qualitative assessment, we determine the drivers of fair value for each reporting unit and evaluate whether those drivers have been positively or negatively affected by relevant events and circumstances since the last fair value assessment. Our evaluation includes, but is not limited to, the assessment of macroeconomic trends (including the impact of changes in discount rates and rate base multiple), changes to regulatory environments, capital accessibility, operating income trends (including changes to projected cash flows from operations, expected future capital expenditures and forecasted rate base), and changes to industry conditions. Based on our assessment of qualitative factors, if we determine it is more likely than not that the fair value of the reporting unit is less than its carrying amount, a quantitative goodwill impairment assessment is performed. The quantitative goodwill impairment assessment involves determining the fair value of our reporting units and comparing those values to the carrying value of each reporting unit. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit's carrying value exceeds its fair value. This amount should not exceed the carrying amount of goodwill. The fair value of our reporting units is estimated using either a discounted cash flow technique or a combination of discounted cashflow and earnings multiples techniques. The determination of fair value using the discounted cash flow technique requires the use of estimates and assumptions related to discount rates, projected operating income, expected future capital expenditures, as well as terminal value growth rates for the Liquids Pipelines, Gas Transmission, and Renewable Power Generation reporting units, and projected regulatory rate base and rate base multiple for the Gas Distribution and Storage reporting unit. The determination of fair value using the earnings multiples technique requires assumptions to be made in relation to maintainable earnings and earnings multiples. 89The allocation of goodwill to held-for-sale and disposed businesses is based on the relative fair value of businesses included in the relevant reporting unit.On April 1, 2025, we performed our annual goodwill impairment assessment which consisted of a qualitative assessment for the Liquids Pipelines and Renewable Power Generation reporting units and did not identify any impairment indicators. We also chose to perform a quantitative assessment for the Gas Transmission and Gas Distribution and Storage reporting units which did not result in the recognition of any impairment charges. No indicators of goodwill impairment were identified during the remainder of 2025.ASSET IMPAIRMENT We evaluate the recoverability of our property, plant and equipment when events or circumstances, such as economic obsolescence, business climate, legal or regulatory changes, or other factors, indicate that we may not recover the carrying amount of our assets. We regularly monitor our businesses, the market and business environments to identify indicators that could suggest an asset may not be recoverable. If it is determined that the carrying value of an asset exceeds its expected undiscounted cash flows, we will assess the fair value of the asset. An impairment loss is recognized when the carrying amount of the asset exceeds its fair value. With respect to equity method investments, we assess at each balance sheet date whether there is objective evidence that the investment is impaired by completing a qualitative or quantitative analysis of factors impacting the investment. If there is objective evidence of impairment, we determine whether the decline below carrying value is other-than-temporary. If the decline is determined to be other-than-temporary, an impairment charge is recorded in earnings with an offsetting reduction to the carrying value of the investment. Asset fair value is determined using present value techniques. The determination of fair value using present value techniques requires the use of projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes to these projections and assumptions could result in revisions to the evaluation of the recoverability of the asset and the recognition of an impairment loss in the Consolidated Statements of Earnings.REGULATORY ACCOUNTINGCertain parts of our businesses are subject to regulation by various authorities including, but not limited to the CER, the FERC, the Alberta Energy Regulator, the BC Energy Regulator, the OEB, the Québec Régie de l’énergie, the Ohio Commission, the North Carolina Commission, the Utah Commission, the Wyoming Commission, and the Idaho Commission. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking, and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under US GAAP for non-rate-regulated entities.Key determinants in the ratemaking process are: • costs of providing service, including operating costs, capital invested, depreciation expense and taxes; • allowed rate of return, including the equity component of the capital structure and related income taxes; • interest costs on the debt component of the capital structure; and • contract and volume throughput assumptions.The allowed rate of return is determined in accordance with the applicable regulatory model and may impact our profitability. The rates for a number of our projects are based on a cost-of-service recovery model that follows the regulators' authoritative guidance. Under the cost-of-service tolling methodology, we calculate tolls based on forecast volumes and cost. A difference between forecast and actual results causes an over- or under-recovery in any given year. 90 Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates, amounts collected from customers in advance of costs being incurred, or to be paid to cover future abandonment costs and for future removal and site restoration costs as approved by the regulator. If there are changes in our assessment of the probability of recovery for a regulatory asset, we reduce its carrying amount to the balance that we expect to recover from customers in future periods through rates. If a regulator later excludes from allowable costs all or a part of costs that were capitalized as a regulatory asset, we reduce the carrying amount of the asset by the excluded amounts. The recognition of regulatory assets and liabilities is based on the actions, or expected future actions, of the regulator. To the extent that the regulator's actions differ from our expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate regulation, we would generally not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned. A regulatory asset or liability is recognized in respect of deferred income taxes when it is expected the amounts will be recovered or settled through future regulator-approved rates. As at December 31, 2025 and 2024, our regulatory assets totaled $7.6 billion and our regulatory liabilities totaled $6.7 billion in both years.DEPRECIATIONDepreciation of property, plant and equipment, our largest asset with a net book value at December 31, 2025 and 2024, of $131.6 billion and $131.1 billion, respectively, is charged in accordance with two primary methods. For distinct assets, depreciation is generally provided on a straight-line basis over the estimated useful life of the asset commencing when it is placed in service. For largely homogeneous groups of assets with comparable useful lives, the pool method of accounting is followed whereby similar assets are grouped and depreciated as a pool. When group assets are retired or otherwise disposed of, gains and losses are generally not reflected in earnings but are booked as an adjustment to accumulated depreciation.When it is determined that the estimated service life of an asset no longer reflects the expected remaining period of benefit, prospective changes are made to the estimated service life. Estimates of useful lives are based on third-party engineering studies, experience and/or industry practice. There are a number of assumptions inherent in estimating the service lives of our assets including the level of development, exploration, drilling, reserves and production of crude oil and natural gas in the supply areas served by our pipelines, as well as the demand for crude oil and natural gas and the integrity of our systems. Changes in these assumptions could result in adjustments to the estimated service lives, which could result in material changes to depreciation expense in future periods in any of our business segments. For certain rate-regulated operations, depreciation rates are approved by the regulator and the regulator may require periodic studies or technical updates on useful lives which may change depreciation rates.The successful efforts method of accounting is used for cost-of-service reserves developed and produced by Wexpro for gas utility affiliate, Questar. Cost-of-service reserves are properties for which the operations and return on investment are subject to the Wexpro Agreements. Under the successful efforts method, Wexpro capitalizes the costs of acquiring leaseholds, drilling development wells, drilling successful exploratory wells, and purchasing related support equipment and facilities. Geological and geophysical studies are expensed as incurred. Capitalized costs of development wells and leaseholds are amortized on a field-by-field basis using the unit-of-production method and the estimated proved developed or total proved natural gas and crude oil reserves. 91PENSION AND OTHER POSTRETIREMENT BENEFITS We use certain assumptions relating to the calculation of defined benefit pension and other postretirement liabilities and net periodic benefit costs. These assumptions comprise management's best estimates of expected return on plan assets, future salary levels, other cost escalations, retirement ages of employees, and other actuarial factors including discount rates and mortality. We determine discount rates by reference to rates of high-quality long-term corporate bonds with maturities that approximate the timing of future payments anticipated to be made under each of the respective plans. The expected return on plan assets is determined using market-related values and assumptions on the asset mix consistent with the investment policy relating to the assets and their projected returns. The assumptions are reviewed annually by our independent actuaries. Actual results that differ from results based on assumptions are amortized over future periods and, therefore, could materially affect the expense recognized and the recorded obligation in future periods.The following sensitivity analysis identifies the impact on the consolidated financial statements for the year ended December 31, 2025 of a 0.5% change in key pension and other postretirement benefits (OPEB) obligation assumptions: Canada United States Obligation Expense Obligation Expense(millions of Canadian dollars) PensionDecrease in discount rate 281 7 90 2 Decrease in expected return on assets — 25 — 10 Decrease in rate of salary increase (54 ) (8 ) (18 ) (3 )OPEBDecrease in discount rate 11 1 7 — Decrease in expected return on assets N/A N/A — 1CONTINGENT LIABILITIESProvisions for claims filed against us are determined on a case-by-case basis. Case estimates are reviewed on a regular basis and are updated as new information is received. The process of evaluating claims involves the use of estimates and a high degree of management judgment. Claims outstanding, the final determination of which could have a material impact on our financial results and certain subsidiaries and investments, are detailed in Legal and Other Updates and Part II . Item 8. Financial Statements and Supplementary Data - Note 30 - Commitments and Contingencies . In addition, any unasserted claims that later may become evident could have a material impact on our financial results and certain subsidiaries and investments.ASSET RETIREMENT OBLIGATIONSAsset retirement obligations (ARO) associated with the retirement of long-lived assets are measured at fair value and recognized as Other current liabilities or Other long-term liabilities in the period in which they can be reasonably determined. Fair value approximates the cost a third party would charge to perform the tasks necessary to retire such assets and is recognized at the present value of expected future cash flows. The discount rates used to estimate the present value of expected future cash flows for the years ended December 31, 2025 ranged from 3.0% to 9.0% (2024 - 1.5% to 9.0%). Asset retirement cost is added to the carrying value of the associated asset and depreciated over the asset's useful life. The corresponding liability is accreted over time through charges to earnings and is reduced by actual costs of decommissioning and reclamation. Our estimates of retirement costs could change as a result of changes in cost estimates and regulatory requirements. Currently, for the majority of our assets, there is insufficient data or information to reasonably determine the timing of settlement for estimating the fair value of the ARO. In these cases, the fair value of ARO is considered indeterminate for accounting purposes, as there is no data or information that can be derived from past practice, industry practice or the estimated economic life of the asset. 92 In 2009, the CER issued a decision related to the Land Matters Consultation Initiative (LMCI), which required holders of an authorization to operate a pipeline under the CER Act to file a proposed process and mechanism to set aside funds to pay for future abandonment costs in respect of the sites in Canada used for the operation of a pipeline. The CER's decision stated that, while pipeline companies are ultimately responsible for the full costs of abandoning pipelines, abandonment costs are a legitimate cost of providing service and are recoverable from the users of the pipeline upon approval by the CER. Following the CER's final approval of the collection mechanism and the set-aside mechanism for LMCI, we began collecting and setting aside funds to cover future abandonment costs effective January 1, 2015. The funds collected are held in trusts in accordance with the CER decision. The funds collected from shippers are reported within Transportation and other services revenues and Restricted long-term investments and cash. Concurrently, we reflect the future abandonment cost as an increase to Operating and administrative expense and Other long-term liabilities.CHANGES IN ACCOUNTING POLICIESRefer to Part II. Item 8. Financial Statements and Supplementary Data - Note 3 - Changes in Accounting Policies .