ENBRIDGE INC

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

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

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

CORPORATE VISION AND STRATEGY

VISION

Enbridge, through its diversified businesses, fuels people's quality of life in a safe and socially responsible manner. Our vision is to provide energy in a more planet-friendly way, everywhere people need it. In pursuing this vision, we seek to play a critical role enabling the economic and social well-being of society by providing access to affordable, reliable, and secure energy through our infrastructure which transports, stores, distributes, and generates energy, including liquids, natural gas, renewable power, and lower-carbon fuels.

We aim to be a first-choice investment, supported by our investor value proposition of predictable and stable cash flows, a strong investment grade balance sheet to facilitate growth, 31 years of consecutive dividend increases, and a diversified opportunity set of growth projects in multiple jurisdictions to support continued EBITDA and distributable cash flow per share growth. Our assets are underpinned by long-term contracts, regulated cost-of-service tolling frameworks, power purchase agreements (PPAs), and other low-risk commercial arrangements.

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

STRATEGY

Our strategy is underpinned by a deep understanding of local, North American and global energy fundamentals. Through disciplined capital allocation, aligned with our outlook on energy markets, we have become an industry leader with a diversified portfolio of infrastructure super systems across the North American continent, creating a platform for incremental growth. Our robust opportunity set across all businesses, strategic partnerships, and ongoing efficiency improvements position us to drive our business forward. We remain confident in our balanced growth strategy and expect to continue to invest in our diversified footprint of both conventional businesses and complementary lower-carbon opportunities. This includes expanding our gas transmission and storage assets to meet LNG export demand, increasing our gas distribution footprint to meet growing natural gas demand, and continually optimizing and expanding our liquids system. We plan to capitalize on North American electrification trends, including the expansion of data centers, where we can provide integrated customer solutions through our natural gas and renewable power businesses, as well as infrastructure to support ongoing coal-to-gas conversions. Additionally, we are committed to effectively managing our emissions from our operations and building lasting relationships with our stakeholders.

Our assets have reliably generated low-risk, resilient cash flows through multiple commodity cycles as well as various economic and geopolitical environments. We believe that our asset quality, diversity, and ability to provide comprehensive solutions to customers are key differentiators that enable us to be flexible in an uncertain business environment.

As an industry leader that continues to create value over the short and long term, we maintain a robust strategic planning process. We regularly conduct scenario and resiliency analysis on both our assets and business strategy, including testing various opportunities for value enhancements and optimizations. Our Board of Directors (the Board) reviews and provides input on Enbridge's strategy during a dedicated annual strategic planning session and receives updates throughout the year. This enables the Board to monitor progress and consider adjustments as needed.

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

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Our Liquids Pipelines business saw strong volumes on the Mainline System. Newly sanctioned investments include: Mainline Capital Investment, Mainline Optimization Phase 1 (which will increase capacity by 250 thousand barrels per day (kbpd)), Southern Illinois Connector project, and the Pelican Carbon Dioxide (CO 2) Hub, partnering with Occidental Petroleum Corporation. Mainline Optimization Phase 2 is in development, subject to finalizing commercial agreements, securing the necessary environmental and regulatory approvals, and meeting investment criteria. We continue to pursue capital efficient optimizations and expansions to provide customers with incremental egress options for North American liquids.

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Our Gas Transmission business grew our Permian natural gas infrastructure presence through a 10% stake in the 2.5 billion cubic feet per day (bcf/d) Matterhorn Express Pipeline, reaching final investment decision on the 3.7 bcf/d Eiger Express Pipeline, and sanctioning the US Gulf Coast Storage Growth Program with 23 billion cubic feet (bcf) of incremental capacity. We made progress in the US Northeast region by sanctioning the Algonquin Gas Transmission Enhancement project. We strengthened our Canadian presence by sanctioning the Birch Grove project, and a 40 bcf expansion of the Aitken Creek gas storage facility (Aitken Creek) to support growing west coast LNG export demand. With the additional growth projects, Gas Transmission comprises approximately 50% of Enbridge’s secured capital program. We continue to work with customers on opportunities to supply gas for new power generation that supports data centers and overall demand growth, and capitalize on strong gas fundamentals to deliver safe, reliable, and lower-carbon energy to North Americans while simultaneously growing LNG exports.

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Our Gas Distribution and Storage business added approximately 68,000 new customers across our utility jurisdictions, reached supportive settlements on rate cases in North Carolina and Utah, continued to advance data center and power generation opportunities, and doubled the capacity of the T-15 Reliability Project which is expected to deliver 0.51 bcf/d to Duke Energy’s Roxboro power plant in North Carolina. We remain committed to assessing low-risk, capital investment opportunities, and providing safe, affordable and reliable energy to customers in Ontario, Québec, Ohio, North Carolina, Utah, Wyoming, and Idaho.

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Our Renewable Power Generation business continued to execute on growth opportunities, including our onshore business where we brought into service the 130 megawatt (MW) Orange Grove Solar facility and advanced construction on the 815 MW Sequoia Solar project, including completion of the first phase during the fourth quarter of 2025. We also sanctioned the 152 MW Easter renewable power and 600 MW Clear Fork Solar projects in Texas, and the Cowboy Phase 1 project, a 365 MW solar farm and an on-site 135 MW battery energy storage system, in Wyoming. We also continued to progress opportunities in our offshore wind business in Europe, including placing the 25 MW Provence Grand Large floating offshore wind project into service, continuing the construction of the Courseulles (Calvados) Offshore Wind project, and successfully implementing a range of portfolio rationalization and cost-efficiency measures.

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We continued to make meaningful progress toward our sustainability goals, reducing emissions from our operations through multiple pathways, including system modernization, and continuing to invest in our lower-carbon businesses. We updated our Indigenous Reconciliation Action Plan to reaffirm our commitment to reconciliation (including new and renewed commitments) and report on our progress, including advancing vital economic partnerships.

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We continued to recycle capital at attractive valuations; in 2025, this included Stonlasec8 Indigenous Investments Limited Partnership (the First Nations Partnership), a group of 38 First Nations in British Columbia (BC), investing in the Westcoast natural gas pipeline system for a 12.47% redeemable noncontrolling interest. We remain focused on disciplined capital allocation, portfolio optimization and diversification, the continued enhancement of our industry-leading cash flow profile and financial strength and flexibility. In addition, we continue to prioritize operating cost reductions across our business to increase our competitiveness and profitability.

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

Looking ahead, our near-term strategic priorities remain similar to past years. As always, our top priorities include proactively advancing the safety of our people and assets, protecting the environment, and maintaining system reliability. We are focused on maintaining and enhancing the value of our existing assets through further optimization, prioritizing in-franchise organic growth, pursuing export-driven opportunities, and continuing to explore complementary lower-carbon investments.

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

We aim to invest on an attractive, risk-adjusted basis to advance our strategy and maintain an enduring competitive advantage.

Our key strategic priorities include:

Safety and Operational Reliability

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

Extend Growth

The cornerstone of our growth lies in the successful execution of our slate of secured projects (currently $39 billion through 2033) on schedule and within estimated costs, while maintaining standards for safety, quality, customer satisfaction, and environmental and regulatory compliance. For a discussion of our current portfolio of capital projects, refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Growth Projects - Commercially Secured Projects.

Our high-quality growth opportunities continue to evolve based on a more positive policy landscape for conventional energy infrastructure. We continue to direct capital towards optimal uses, prioritizing balance sheet strength, investment in capital efficient growth, and regulated utility or utility-like projects. Our scale and diversification drive competitive advantages across the enterprise and generate opportunities for collaboration across businesses. Our four business units share commercial advantages and strong stakeholder relationships that enable opportunities to cross-sell to customers across the business units, providing additional value and the potential for future growth. We carefully assess our investable capacity, deploying capital to the most value-enhancing opportunities available to us, including further organic growth, and complementary accretive "tuck-in" acquisitions that improve our competitive positioning or further strengthen our balance sheet.

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

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Our infrastructure within the Liquids Pipelines business will remain a vital connection between key supply basins and demand-pull markets such as the refinery hubs in the US Midwest, eastern Canada, and the US Gulf Coast. We are advancing discussions with customers for additional Western Canadian Sedimentary Basin (WCSB) pipeline capacity. We continue to explore capital efficient growth opportunities via system expansions and optimization of operations. Our crude oil export infrastructure will also enable the opportunity to transport lower-carbon fuels and NGL. Leveraging our transportation expertise, we expect additional new growth opportunities for carbon capture and storage in jurisdictions with supportive regulatory regimes.

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Our Gas Transmission business seeks opportunities to extend and expand pipelines and storage, driven by new load demand from gas-fired power generation (to support opportunities like data centers, electrification, coal-to-gas, and reshoring manufacturing), industrial growth, and coastal LNG plants. Our strategic asset positions produce opportunities to accelerate growth and meet customer needs. Our rate regulated cost-of-service business model creates secured growth opportunities that yield predictable, low-risk cash flows. We are also focused on facilitating the connection of new gas supply to key demand centers and the build-out of our Permian gas value chain.

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Our Gas Distribution and Storage business continues to be well positioned to capitalize on the growth offered by the increased need for power, including data centers, modernization of assets, storage development, and major projects supporting commercial and industrial customers' growth needs. We expect to continue to grow our gas utility business through the addition of residential, commercial and industrial sector customers, making capital investments consistent with our regulatory construct.

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Our Renewable Power Generation business continues to be well positioned to capitalize on the continued demand for renewable power, including data centers, through disciplined capital allocation and opportunistic development in supportive jurisdictions. We continue to leverage our strong internal capabilities and customer relationships to execute our development portfolio of high-quality assets.

In addition, we aim to drive growth through optimization and modernization of our systems, including the application of drag-reducing agents and pump station modifications to optimize throughput on our liquids system, capital efficient compression projects in our gas transmission business, and modernization and value chain integration to enhance reliability for customers at our gas utilities. We prioritize the execution of toll settlements and rate case filings to optimize revenue within our liquids, gas transmission and gas distribution businesses. Finally, we are focused on improving productivity and efficiency across all our businesses through innovation, process improvement, and system enhancements.

Maintain Financial Strength and Flexibility

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

Disciplined Capital Allocation

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

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

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

An "All-of-the-Above" Approach to Energy Evolution

As the global population grows and standards of living continue to improve around the world, we expect energy demand to rise. We, and the communities in which we operate, increasingly recognize the need for affordable, secure and reliable energy while concurrently focusing on environmental impacts. Through collaboration with our stakeholders (including regulators, policymakers, customers, and Indigenous partners), we aim to balance these factors and believe this will take an "all-of-the-above" approach. As a company with diverse energy infrastructure, we are uniquely positioned to help support the energy transition or energy evolution. To meet increased demand across North America and around the world, while continuing to drive down emissions intensity, we believe an energy evolution, which will take all forms of energy, will be required.

Our portfolio of oil, natural gas, and renewable power assets is critical to maintaining a balanced approach that we believe enables a durable energy evolution. For us, this includes reducing the emissions intensity of the conventional fuels we transport and store, facilitating the shift from higher emission energy sources to natural gas, advancing the integration of renewable energy sources, and investing in infrastructure for emerging lower-carbon solutions, all while supporting projects that meet our risk and return criteria.

We work closely with our customers, stakeholders, and third-party experts to monitor the evolving energy system and actively leverage our execution and sustainability capabilities to advance our positioning as a differentiated energy provider.

STRATEGIC ENABLERS

To successfully execute our strategy and build competitive advantages, we focus on sustainability, operations and development, talent, technology, and growth capabilities.

Sustainability

Sustainability is foundational to Enbridge’s strategy and long-term value creation. Our performance as a safe operator, environmental steward, inclusive employer, and responsible corporate citizen directly supports our ability to deliver reliable and affordable energy.

Since setting our sustainability goals in 2020, we have made considerable progress integrating sustainability into our strategy, governance, operations, and decision-making. We have linked sustainability performance to incentive compensation and are making meaningful progress toward these goals by executing on our action plans. Our 24 th annual Sustainability Report details our progress and can be found athttps://www.enbridge.com/sustainability-reports.

Unless otherwise specifically stated, none of the information contained on, or connected to, the Enbridge website, including our annual Sustainability Report, is incorporated by reference in, or otherwise part of, this Annual Report on Form 10-K.

Operations and Development

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

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

Talent

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

Technology

We recognize the vital role technology plays in helping us achieve our strategic objectives. Our digital business enablement strategy focuses on innovation and digital technology solutions that further our safety and reliability, maximize revenues, reduce costs, and enable transition to new energy solutions. We focus on the resilience and reliability of our systems from a cybersecurity perspective, including enhancing our capabilities and educating our workforce to protect our critical infrastructure system from increasing threats. We continue to leverage artificial intelligence (AI) to drive advancements in safety, emissions reduction, and asset optimization. Examples include the application of machine learning to optimize energy usage and the use of advanced AI models to support pipeline system optimization. This strategy has also enabled us to make AI accessible across Enbridge in various forms, from self-service tools to custom-built solutions.

Growth Capabilities

To achieve our vision, we emphasize specific capabilities, including the ability to offer integrated and differentiated solutions, that will help us grow and build competitive advantages within our core and potential new businesses. We continue to focus on our customers so that we are responsive to their needs. We are continuing to invest in leading corporate development capabilities to enable us to identify and execute on attractive acquisitions and capital recycling opportunities. Finally, we believe that the future energy system will not only continue to be highly integrated but will also become more complex. Strengths in partnership structuring and relationship management is an important factor in building and maintaining robust energy infrastructure systems.

BUSINESS SEGMENTS

During 2025, our activities were carried out through four business segments: Liquids Pipelines, Gas Transmission, Gas Distribution and Storage, and Renewable Power Generation, as discussed below.

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

MAINLINE SYSTEM

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

Tolling Framework

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

The MTS includes:

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

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

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

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

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

Lakehead System Local Tolls

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

The Lakehead tolls are subject to the Lakehead System Settlement approved by the FERC on November 27, 2023.

The Lakehead System Settlement establishes a depreciation truncation date of December 31, 2048 for the rate base applicable to the Index and FSM, and sets out on the terms for future recovery - through the Facilities Surcharge - of two Line 5 projects: the Wisconsin Relocation Project and the Straits of Mackinac Tunnel.

REGIONAL OIL SANDS SYSTEM

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

The combined capacity of the intra-Alberta long-haul pipelines is approximately 1.1 mmbpd to Edmonton and 1.4 mmbpd into Hardisty, with Norlite providing approximately 230 kbpd of diluent capacity into the Fort McMurray region. We have a 50% interest in the Woodland Pipeline and a 70% interest in Norlite. The Regional Oil Sands System is anchored by long-term agreements with multiple oil sands producers that provide cash flow stability and also include provisions for the recovery of some of the operating costs of this system.

Athabasca Indigenous Investments Limited Partnership, an entity representing 23 First Nation and Metis communities, own an 11.6% non-operating interest in the seven intra-Alberta long-haul pipelines in the Regional Oil Sands System.

GULF COAST AND MID-CONTINENT SYSTEMS

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

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

Spearhead Pipeline is a 938 kilometer (583 mile), 22-to-24-inch diameter long-haul pipeline that delivers crude oil from Flanagan, Illinois, a delivery point on the Lakehead System, to Cushing, Oklahoma. The Spearhead Pipeline has a capacity of approximately 193 kbpd.

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

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

Gray Oak is a 1,368 kilometer (850 mile) crude oil system, transporting light crude oil, with origination points in the Eagle Ford and Permian Basins in West Texas. Gray Oak has delivery points at the US Gulf Coast and Houston refining region. As part of a phased expansion, Gray Oak added 80 kbpd to its capacity in 2025, bringing the current average annual capacity to 980 kbpd; phase two of the expansion is expected to add a further 40 kbpd to the system, and increase average annual capacity to 1.0 mmbpd in 2026. Our effective economic interest in Gray Oak is 68.5%. Enbridge has been the operator of Gray Oak since April 2023.

We own 100% of the EIEC, the largest crude oil export terminal by volume in North America. EIEC has an export capability of 1.6 mmbpd. EIEC’s total storage capability is 17.6 million barrels with construction underway to add a further two million barrels of storage in early 2026 as part of a Phase VII expansion project. We also own 100% interest in each of the 300-kbpd Viola pipeline, and the 350-thousand barrel Taft Terminal, both located near Corpus Christi, Texas. Additionally, in October 2024 we completed the acquisition of two marine docks and land adjacent to EIEC. This acquisition adds crude oil export capacity and streamlines existing EIEC operations by increasing Very Large Crude Carrier windows on the primary facility docks. We also have a total 30% non-operating ownership interest in Cactus II Pipeline, a pipeline that travels from Wink to Ingleside within Texas.

OTHER

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

The Southern Lights Pipeline is a single stream 2,560 kilometer (1,591 mile) 198 kbpd 16/18/20-inch diameter pipeline that ships diluent from the Manhattan Terminal near Chicago, Illinois to delivery facilities, located in Edmonton, Alberta. The Canadian portion of the Southern Lights Pipeline receives tariff revenues under long-term contracts with committed shippers, in addition to both the Canadian and US segments receiving toll revenue from uncommitted transportation movements. The Southern Lights Pipeline capacity is approximately 90% contracted with the remaining capacity made available for uncommitted volumes. A fully subscribed open season was completed in December 2024, which ensures contract levels remain at 90% through mid-2030.

The Express-Platte System consists of the Express Pipeline and the Platte Pipeline, and crude oil storage of approximately 5.6 million barrels. It is an approximately 2,736 kilometer (1,700 mile) long, 20-to-24-inch diameter crude oil transportation system, which begins at Hardisty, Alberta, and terminates at Wood River, Illinois. The 310 kbpd Express Pipeline carries crude oil to US refining markets in the Rocky Mountains area, including Montana, Wyoming, Colorado and Utah. The 145 to 164 kbpd Platte Pipeline, which interconnects with the Express Pipeline at Casper, Wyoming, transports crude oil predominantly from the Bakken shale and western Canada to refineries in the Midwest. The Express Pipeline capacity is typically committed under long-term take-or-pay contracts with shippers. A small portion of the Express Pipeline capacity and all of the Platte Pipeline capacity is used by uncommitted shippers who pay only for the pipeline capacity they actually use in a given month.

The Bakken System consists of the North Dakota System and the Bakken Pipeline System, with total length of 3,080 kilometers (1,914 miles) and 30-inch diameter. The North Dakota System services the Bakken Basin in North Dakota and is comprised of a crude oil gathering and interstate pipeline transportation system. The gathering system provides delivery to Clearbrook, Minnesota for service on the Lakehead system or a variety of interconnecting pipelines. The interstate portion of the system has both US and Canadian components that extend from Berthold, North Dakota into Cromer, Manitoba.

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

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

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

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

Feeder Pipelines and Other also includes Patoka Storage, the Toledo pipeline system and the Norman Wells (NW) System. Patoka Storage is comprised of four storage tanks with 480 thousand barrels of shell capacity located in Patoka, Illinois. The 180 kbpd Toledo pipeline system connects with the Lakehead System and delivers to Ohio and Michigan. The 45 kbpd NW System transports crude oil from Norman Wells in the Northwest Territories to Zama, Alberta and has a cost-of-service rate structure based on established terms with shippers. In January 2026, our sole customer of the NW system announced that they will cease operations in Norman Wells later in 2026.

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

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

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

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

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

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

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

Our Mainline System was effectively fully utilized in 2025, delivering 3.1 mmbpd. Refinery demand in the upper Midwest PADD II market has been strong. On the US Gulf Coast, lower supply of heavy crude from Latin America and the Middle East continues to drive increased demand for Canadian heavy crude. Many of the refineries connected to the Mainline System are complex and competitive in the global context.

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

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

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

GASTRANSMISSION

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

US GAS TRANSMISSION

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

The Texas Eastern interstate natural gas transmission system extends from supply and demand centers in the Gulf Coast region of Texas and Louisiana to supply and demand centers in Ohio, Pennsylvania, New Jersey and New York. Texas Eastern's onshore system has a peak day capacity of 12.1 bcf/d of natural gas on approximately 13,745 kilometers (8,541 miles) of pipeline and associated compressor stations. Texas Eastern is also connected to five affiliated storage facilities that are partially or wholly-owned by other entities within the US Gas Transmission business, including the Tres Palacios Holdings LLC storage facility that we acquired in 2023.

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

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

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

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

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

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

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

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

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

The Whistler Parent JV, formed in May 2024, holds a 100% interest in Whistler Pipeline, LLC (Whistler), a 450 mile intrastate pipeline with associated compressor stations that extends from the Permian Basin to Agua Dulce, Texas area with a capacity of 2.5 bcf/d, a 70% interest in ADCC Pipeline, LLC, a 40 mile pipeline that extends from Agua Dulce, Texas to Cheniere Energy’s Corpus Christi LNG export facility with a capacity of 1.7 bcf/d, and a 50% interest in Waha Gas Storage, LLC, a 2.0 bcf gas storage cavern facility connecting to key Permian egress pipelines including Whistler. We have a 19% interest in the Whistler Parent JV.

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

The MXP Parent JV, a joint venture formed by Enbridge, WhiteWater Midstream, ONEOK, Inc and MPLX LP, holds (i) a 100% interest in MXP, which owns the Matterhorn Express Pipeline, an approximately 580 mile intrastate pipeline with associated compressor stations that extends from the Permian Basin to the Katy, Texas area with a capacity of 2.5 bcf/d; and (ii) a 70% equity interest in the 3.7 bcf/d Eiger Express Pipeline, which has a route parallel to the Matterhorn Express Pipeline. We have a 10% interest in the MXP Parent JV.

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

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

CANADIAN GAS TRANSMISSION

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

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

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

On July 1, 2025, Westcoast completed a reorganization in which substantially all of the property and assets relating to the BC Pipeline were transferred to a newly formed partnership, Westcoast Energy Limited Partnership. On July 2, 2025, the First Nations Partnership, an entity representing 38 First Nations in BC, invested approximately $736 million in our Westcoast BC Pipeline. As at December 31, 2025, the First Nations Partnership owns a 12.47% redeemable noncontrolling interest in the BC Pipeline system. Subsequent to the First Nations Partnership's investment, we continue to manage and operate the pipeline system.

OTHER

Other consists primarily of our offshore and midstream assets.

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

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

On January 2, 2024, we acquired six operating landfill gas-to-RNG production facilities from Morrow Renewables located in Texas and Arkansas. These assets are operated under Tomorrow RNG, a wholly owned subsidiary of Enbridge and further advanced Enbridge’s low-carbon strategy by accelerating RNG production capacity across key markets.

Midstream assets include a 13.2% effective economic interest in DCP Midstream, LP (DCP). DCP is a joint venture, with a diversified portfolio of assets, engaged in the business of gathering, compressing, treating, processing, transporting, storing and selling natural gas; producing, fractionating, transporting, storing and selling NGL, and recovering and selling condensate. DCP owns and operates more than 33 plants and approximately 83,176 kilometers (51,683 miles) of natural gas and NGL pipelines, with operations in seven states across major producing regions.

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

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

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

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

Natural gas production in the Appalachian and Permian Basins has grown dramatically in the past decade. Today, these regions produce more than 58 bcf/d of natural gas on a combined basis. Improved technology and increased shale gas drilling have increased the supply of low-cost natural gas. As well, there has been, and continues to be, a corresponding increase in demand for our natural gas infrastructure in North America. Through a series of expansions and reversals on our core systems, combined with the execution of greenfield projects and strategic acquisitions, we have been able to meet the needs of both producers and consumers. Our US Gas Transmission systems were initially designed to transport natural gas from the Gulf Coast to the supply-constrained northeast markets. Our asset base now has the capability to transport diverse bi-directional supply to the Northeast, Southeast, Midwest, Gulf Coast and LNG markets on a fully subscribed and highly utilized basis.

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

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

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

Gulf Coast demand growth is being driven by an increase in the volume of LNG exports, an ongoing wave of gas-intensive petrochemical facilities and additional pipeline exports to Mexico. Demand in this region is anticipated to grow by approximately 20 bcf/d through 2040. The Gulf Coast market has been the beneficiary of low-cost capacity on our system as the relationship between supply and market centers has shifted. Such cost-effective capacity is difficult to access or replicate, offering existing shippers and transporters stability of capacity and utilization. Tide-water market access and proximity to Mexico continue to make this region a platform of global trade as pipeline and LNG exports continue their growth trajectory. In 2025, the US exported over 16 bcf/d of natural gas to LNG markets, primarily from the Gulf Coast region.

Western Canada is also a source of low-cost supply seeking access to premium markets in North America and globally. One of the few vital links to demand centers in the Pacific Northwest is our BC Pipeline, which is highly utilized. The continental supply profile has shifted to natural gas shale plays, such as the Montney and Duvernay within western Canada. These plays are expected to fulfill an integral role as Canada enters the global market as an LNG exporter. Western Canada's production is forecasted to increase from 19 bcf/d in 2025 to 25 bcf/d by 2040. This growth is supported by LNG exports growing from 0.5 bcf/d in 2025 to 5 bcf/d by 2040. These supply shifts have shaped our growth strategies and affect the nature of the projects anticipated in the capital expenditures discussed below in Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Growth Projects - Commercially Secured Projects.

Global energy demand is expected to increase approximately 20% by 2050, according to the 2025 International Energy Agency (IEA) report, driven primarily by economic growth in non-OECD countries. According to the IEA Stated Policy Scenario, natural gas will play an important role in meeting this energy demand, and gas consumption is anticipated to grow by approximately 16% during this period as one of the world’s most significant energy sources. North American exports are expected to play a significant part in meeting global demand, underscoring the ability of our assets to remain highly utilized by shippers, and highlighting the need for incremental transportation solutions across North America, as well as for the further build-out of export facilities to meet international demand.

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

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

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

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

GASDISTRIBUTION AND STORAGE

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

There are three principal interrelated aspects of the natural gas distribution business in which our utilities are directly involved: Distribution, Transportation, and Storage. The number of customers, and approximate combined length of pipelines for each of our major distribution and transmission systems as at December 31, 2025 are as follows:

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

Distribution

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

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

Transportation

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

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

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

Storage

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

The storage facility at Dawn is located in southwestern Ontario and has a total working capacity of approximately 290 bcf in 35 underground facilities located in depleted gas fields. Dawn is the largest integrated underground storage facility in Canada and one of the largest in North America. A substantial amount of Enbridge Gas Ontario’s storage revenue is generated by fixed annual demand charges. There is approximately 60 bcf of underground storage in Ohio that provides additional flexibility for system reliability and managing the cost of supply for customers.

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

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

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

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

Enbridge continues to focus on promoting conservation as a strategy to improve affordability and energy efficiency by undertaking activities focused on reducing natural gas consumption through various demand side management programs offered across all markets.

Supply and demand are also impacted by the legislative environments in which our utilities operate. For example, effective April 1, 2025 the federal carbon levy unit rate in Ontario was set to zero. Additionally in June 2025, the Government of Ontario’s first Integrated Energy Plan, which emphasizes energy affordability and customer choice, identified natural gas as a critical and vital component of Ontario’s energy mix. In 2023, House Bill 507 was signed in Ohio officially defining natural gas as a "green energy". In 2021, Ohio and Utah both passed bills (House Bill 201 and House Bill 17, respectively) prohibiting bans on natural gas. The laws prohibit municipalities and counties from enacting "an ordinance, a resolution, or a policy that prohibits, or has the effect of prohibiting, the connection or reconnection of an energy utility service." However, they do not block local or county officials from supporting electrification through incentives or restricting gas use in municipal or county buildings. In 2021, House Bill 951 was signed in North Carolina, directing the North Carolina Commission to develop a plan, known as the NC Carbon Plan, for a 70% reduction in carbon emissions in the electricity sector by 2030 that is driving coal-to-gas generation switching.

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

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

Magna LNG is a 1.3 bcf LNG facility located in Magna, Utah. The facility provides system reliability for Enbridge Gas Utah's customers in Salt Lake City and the surrounding counties. LNG is produced primarily during the warmer months of the year and then stored to be used when needed for reliability.

Renewable Power Generation consists primarily of investments in wind and solar power generation facilities, as well as an equity interest in geothermal power facilities. In Canada, our assets are located in Québec, Ontario and Alberta. In the US, our renewable assets are primarily in Texas, Ohio, Indiana, Colorado, and West Virginia. In Europe, we hold equity interests in operating offshore wind facilities in the coastal waters of the United Kingdom (UK), France, and Germany, as well as interests in offshore wind projects under construction or in active development in France and the UK.

Combined Renewable Power Generation investments represent approximately 4,100 MW of net generation capacity, which primarily consists of:

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1,399 MW generated by North American wind facilities;

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967 MW generated by operating North American solar facilities, with an additional 1,015 MW in projects under construction;

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621 MW generated by European offshore wind facilities; and

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97 MW expected to be generated by the Courseulles (Calvados) Offshore Wind Project in France, which is currently under construction.

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

Most of our investments in Canadian, US and European offshore wind and solar assets are held within joint ventures.

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

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

Strong load growth across North America is anticipated, driven by growing data center power demand and other large industrial load, as well as the continued electrification within the residential, transportation and industrial sectors. Additionally, corporate electricity end-users seeking to reduce their emissions continue to drive demand for renewable electricity and environmental attributes.

In response to the growing demand outlook, North America requires significant new generation capacity from preferred technologies. Gas-fired and renewable energy facilities, including solar and wind (which make up the bulk of our renewable power assets), are generally the preferred sources to meet the increased load.

Falling capital and operating costs of wind and solar, combined with their improving capacity factors, are expected to reinforce the long-term competitiveness of renewable energy and sustain investment, even in the absence of government incentives. Aside from the construction of new wind and solar facilities, other growth opportunities include repowering projects to increase output from and extend the project-life of our existing facilities.

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

Through our European joint ventures, we continue to explore opportunities in European offshore wind to meet the growing demand.

ELIMINATIONSAND OTHER

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

REGULATION

Our assets and activities are subject to extensive governmental and environmental regulation by various federal, provincial, state and local authorities. These include operational regulations related to safety and environmental protection and economic regulations governing the rates we charge customers for our services. These requirements impact our operations, capital expenditures, earnings, cash flows, financial and competitive positions. Non-compliance may result in fines, penalties, remediation, operating restrictions, increased regulatory and stakeholder scrutiny, increased operating and compliance costs and potential reputational damage. We continually monitor rulemakings and rate proceedings and incorporate compliance investments into our capital plans. We maintain regulatory compliance programs and management systems to mitigate these potential risks.

GOVERNMENT REGULATION

Operational Regulations

US

In the US, our liquids and natural gas pipeline operations are subject to pipeline safety laws and regulations administered by the Pipeline and Hazardous Materials Safety Administration (PHMSA), an agency within the US Department of Transportation (DOT) as well as by certain state regulatory authorities. These laws and regulations require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our interstate and intrastate pipelines, including, among other things, requirements to monitor and maintain the integrity of our pipelines and to operate them within permissible design limits, such as pressures. Pipeline failure or failures to comply with applicable regulations could result in a variety of enforcement measures, for example, reduction of allowable operating pressures, which would reduce available capacity on our pipelines. PHMSA continues to review existing regulations and establishes new regulations to support safety standards that are designed to improve operations integrity management processes and reduce methane emissions.

Canada

In Canada, our liquids and natural gas pipeline operations are subject to safety regulations administered by the CER or provincial regulators. Applicable legislation and regulations require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our pipelines. Among other obligations, this regulatory framework imposes requirements to monitor and maintain the integrity of our pipelines. The CER has authority to impose a variety of enforcement measures, including administrative monetary penalties for non-compliance, and may impose financial requirements for future abandonment costs and major pipeline releases. In the event of a significant release or other noncompliance, the CER could impose pressure restrictions, which could result in adverse operational and financial impacts. As in the US, laws and regulations aimed at enhancing pipeline safety in Canada have continued to evolve and are being monitored on an ongoing basis.

Economic Regulations

Pipelines and Facilities

Our pipeline and facility operations are subject to economic regulation by various regulators in both Canada and the US, including the CER and the FERC. These regulators oversee transportation and storage rates, tolls, and tariffs for our assets. Our ability to establish transportation and storage rates on our US interstate natural gas facilities and transportation rates on our US interstate oil pipelines is subject to regulation by the FERC, whose rulings and policies impact our ability to recover the full cost of operating these pipeline and storage assets, including a reasonable rate of return. Tolls of our inter-provincial pipelines in Canada are subject to the regulation by the CER. Regulatory or administrative actions by the CER, FERC and other regulators, including rate proceedings, review of proposed commercial arrangements (for example, toll settlements with shippers), decisions on applications (for example, new expansion projects), and regulatory policies (for example, depreciation and amortization policies), can affect our business. The rejection or revision of applications for approval of new tariff, tolling or rate structures or proposed commercial arrangements, or changes in interpretation of existing regulations by courts or regulators, could have an adverse effect on our revenues and earnings.

Tax policy changes could also affect both existing assets and future development opportunities. For instance, recent updates to US tax legislation implemented in the One Big Beautiful Bill Act provides for immediate expensing of capital expenditures as well as changes to allow for additional interest expense to be deducted. In addition, Canada and the US have extended tax incentives for Carbon Capture, Utilization, and Storage investments. Tax policy changes, along with introduction of tariffs, could change capital costs and impact development plans.

Natural Gas Utilities

Our natural gas utility operations in Canada and the US are regulated by provincial and state utility regulators.

Gas Regulation in Canada

Enbridge Gas Ontario's operations are regulated by the OEB and Enbridge Gaz Québec's operations are regulated by the Québec Régie de l’énergie.

Enbridge Gas Ontario is operating under a multi-year rate framework established by the OEB that began with cost-of-service base rates for 2024 and is followed by a price cap incentive rate-setting mechanism for 2025–2028.

Enbridge Gaz Québec is operating under a multi-year rate framework established by the Régie de l’énergie that began with cost-of-service base rates for 2025 and streamlined rate-setting method that includes a parametric formula for indexing operating costs applicable for years 2026 and 2027. Enbridge Gaz Québec also has a full revenue decoupling mechanism in place since 2024 and will remain in effect through 2027 (inclusive).

Gas Regulation in Ohio

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

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

Gas Regulation in North Carolina

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

Gas Regulation in Utah, Wyoming, and Idaho

Enbridge Gas Utah, Enbridge Gas Wyoming, and Enbridge Gas Idaho are subject to regulation of rates and other aspects of its business by the Utah Commission, the Wyoming Commission, and the Idaho Commission, respectively. The Idaho Commission has contracted with the Utah Commission for rate oversight of Enbridge Gas Idaho’s operations in a small area of southeastern Idaho.

Base rates are set based on the cost-of-service by rate class. Base rates are designed primarily based on rate design methodology in which the majority of operating costs are recovered through volumetric charges. The volumetric charges for the residential and small commercial customers in Utah and Wyoming are subject to revenue decoupling and adjusted for changes in usage per customer.

Crude Oil Marketing

The crude oil marketing business is regulated by government authorities in the areas of commodity trading, import and export compliance and the transportation of commodities. In the US, commodity marketing is regulated by the Commodity Futures Trading Commission, the FERC, the SEC, the Federal Trade Commission, various commodity exchanges, the US Department of Justice, and state regulators. In Canada, provincial and other territorial securities regulators similarly regulate commodity marketing within Canada. These various regulators enforce, among other things, the prohibition of market manipulation, fraud and disruptive trading. The transportation of crude oil and NGL by railcar or truck is regulated by the US DOT, Transport Canada and provincial or state regulatory agencies, which require compliance with security, safety, emergency management, and environmental laws and regulations related to ground transportation of commodities. Non-compliance with governing rules and regulations could result in fines, penalties, remediation and operating restrictions.

Renewable Power Generation

Renewable Power Generation is subject to numerous operational rules and regulations mandated by governments and applicable regulatory authorities. The North American Electric Reliability Corporation (NERC) is an international regulatory authority responsible for establishing and enforcing reliability standards to reduce risks to the reliability and security of the grid in Canada, the US, and Mexico. It is subject to oversight from the FERC in the US and provincial governments in Canada. The FERC has authority over many markets in the US and is tasked with ensuring safe, reliable, and secure interstate transmission of electricity, natural gas, and oil. This includes establishing reliability standards, market rates, and determining certain pricing aspects of transmission development and access, among others. NERC and FERC standards and pricing decisions are also updated from time to time.

Policy changes in both Canada and the US could affect both existing assets and future development opportunities for Renewable Power Generation. For instance, in Canada, the Clean Electricity Regulations, which came into force in 2025, require Canada’s electricity grid to reach net-zero by 2050 with initial limitations beginning in 2035. Canada has also implemented legislation introducing a tax credit for low-emission generation, storage and transmission projects. In the US, legislation such as the One Big Beautiful Bill Act, phases out clean energy tax credits and creates limits on foreign content. Conversely, the current US administration’s directive to implement an AI action plan could lead to higher electricity demand, supporting new opportunities.

Renewable Power Generation is also subject to provincial and state regulations governing the energy resource mix on the grid, emissions levels of the electricity grid, and market regulations related to emergency operations, extreme weather preparedness, and market participation, among others. These regulations may change from time to time, which could impact our operations and increase the costs of participating in regional electricity markets. Other state and provincial governments are also prioritizing reliability and more dispatchable generation characteristics in their markets.

Our Renewable Power Generation assets in France and Germany operate under federal policies and are also subject to directives and regulations established and enforced by the European Union (EU). The EU is also responsible for establishing environmental protection rules and permitting standards. The federal policies and regulations in place are subject to change from time to time, which could impact our operations and related expenditures; however, the EU’s general direction is to facilitate increased renewable power integration to its grid.

The UK government is responsible for establishing renewable energy and carbon pricing policies for the entire UK, as well as long-term electricity sector planning and procurement. Each country within the UK (e.g., England, Scotland) is also responsible for establishing its own environmental and permitting regulations. The offshore wind sector is further supported by the UK’s commitment to reaching net zero by 2050.

ENVIRONMENTAL REGULATION

Our operations across all business segments are subject to extensive environmental laws, regulations, and policies at the federal, provincial or state, and municipal levels. These requirements apply across environmental domains, including air and water quality, waste and land management, habitat protection, wildlife and protected species, noise, emergency response, and the remediation of historical contaminated sites, among others. Because these laws vary by jurisdiction, continue to evolve, and may at times conflict, they introduce regulatory uncertainty and compliance complexity. Meeting these obligations can require significant capital investment and increase operating costs, and non‑compliance or environmental incidents can result in substantial remediation obligations, enforcement actions, financial penalties, operational interruptions, or mandatory deployment of advanced pollution‑control technologies. Regulatory breaches may also lead to third‑party liability claims and reputational impacts, contributing to long‑term risk exposure. Refer to Item 1A. Risk Factors - Risks Related to Government Regulation and Legal Risks for further discussion.

Across Canada and the US, our operations are governed by multi-layered environmental regulatory regimes that differ in scope, structure, and enforcement. In Canada, oversight is shared between federal legislation and provincial frameworks that regulate emissions, carbon pricing, land use, and permitting, creating distinct compliance pathways across provinces.

In the United States, federal air regulations under the Clean Air Act, administered by the US Environmental Protection Agency (EPA), drive significant operational and financial implications, with standards for criteria pollutants, hazardous air pollutants, and methane requiring ongoing investment in detection, monitoring, and advanced control technologies. While recent federal actions have introduced uncertainty, including potential revisions or pauses to certain reporting and compliance requirements, the long‑term trend points toward increasingly stringent emissions controls and the possibility of methane fees. Enbridge anticipates that continued EPA rulemaking, together with state‑level programs that may exceed federal baselines or address gaps left by federal adjustments, is expected to require sustained adaptability, proactive compliance planning, and careful cost management.

Air Quality

On March 7, 2025, Canada published the Reduction in the Release of Volatile Organic Compounds (VOC) (Storage and Loading of Volatile Petroleum Liquids) Regulations (VOC Regulations), which impact our Liquids Pipelines assets, specifically petroleum liquid storage tanks and loading operations. The VOC Regulations require emission control equipment, record keeping, inspections and maintenance of in-scope storage tanks and loading racks. Liquids Pipelines has implemented a structured program to meet all requirements. These regulatory changes will require additional capital and operating expenditures, and we continue to monitor developments and coordinate across functions to enable timely compliance.

Proposed amendments to the Canadian federal methane regulations are part of the government’s effort to achieve at least a 75% reduction in methane emissions from the oil and gas sector by 2030, relative to 2012 levels. These proposed amendments aim to further reduce methane emissions by limiting venting, imposing gas destruction, and increasing fugitive emissions management, affecting our Gas Transmission and Gas Distribution and Storage assets. An alternative performance-based compliance pathway using an emissions monitoring system is also proposed. The regulations are expected to be finalized by spring of 2026.

The Government of Canada adopted a pan-Canadian carbon pricing framework in 2016 through the Greenhouse Gas Pollution Pricing Act (GGPPA), establishing an output-based pricing system (OBPS) for industrial facilities. Part 1 of the GGPPA, which applied a consumer fuel charge, was repealed on April 1, 2025, and as a result Enbridge Gas Ontario removed the Federal Carbon Charge from customer bills. The OBPS under Part 2 continues to apply to large emitters, imposing compliance obligations for emissions above facility specific limits and enabling credits for emissions below those limits. In April 2025, the federal carbon price applicable to industrial emitters increased from $80 to $95 per tonne of carbon dioxide equivalent (CO 2 e), and under the GGPPA schedule the price will continue to rise by $15 per tonne annually to reach $170 per tonne of CO 2 e in 2030.

In March 2022, the Government of Canada published its 2030 Emissions Reduction Plan, which builds upon the pan-Canadian framework and the Net-Zero Emissions Accountability Act. This legislation establishes a roadmap to achieve a 40–45% reduction in GHG emissions by 2030 and net-zero emissions by 2050, supported by complementary policies and programs. Enbridge Gas Ontario, which distributes approximately 2.3 bcf/d of natural gas across Ontario and Québec, is directly affected by the requirements. These frameworks materially influence the Company’s operational planning, investment strategy, and compliance obligations. Enbridge Gas Ontario is actively assessing the role of its existing infrastructure in light of applicable government emission reduction policies.

In the US, several key EPA regulatory initiatives continue to affect our US operations as follows:

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The Good Neighbor Rule, which sets new nitrogen oxide emission limits for certain industrial sources, remains temporarily stayed nationwide pending litigation, creating uncertainty around timelines and compliance obligations.

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The New Source Performance Standards (NSPS) under 40 Code of Federal Regulations Part 60 Subparts OOOOb and OOOOc, imposes new VOC, sulfur dioxide, and methane requirements on new and existing crude oil and natural gas facilities, with certain compliance deadlines postponed to 2027 under a 2025 interim final rule.

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On January 15, 2026, the EPA finalized amendments to the NSPS applicable to stationary combustion turbines, introducing revised requirements to limit nitrogen oxides emissions and, in defined situations, requiring the installation of emissions control or monitoring equipment. The final rule also replaces the prior Subpart KKKK requirements for new sources. We continue to assess the potential capital, operating, and compliance cost impacts of this rule for current and planned turbine assets.

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In 2024, the EPA proposed updates to the National Ambient Air Quality Standards lowering the annual Fine Particulate Matter from 12.0 to 9.0 micrograms per cubic meter of air. For our Gas Transmission and Gas Distribution and Storage business units, this change would significantly increase regulatory and permitting obligations in regions that fail to meet the new threshold. However, the rule remains under reconsideration, and the EPA has not yet issued state recommendations for nonattainment designations.

Pursuant to US federal regulations, facilities emitting 25,000 metric tons CO 2 e per year or more must report GHG emissions through the Mandatory GHG Reporting Program. The EPA revised the program in 2024, to include additional sources and new measurement and calculation methodologies for the oil and gas sector, effective for the 2025 reporting year. These changes were designed to comply with the requirement under the Inflation Reduction Act to utilize more empirical data. We are preparing to report 2025 emissions in 2026; however, a proposal was issued in September 2025 to stop some of the reporting requirements and pause other portions of reporting until 2034.

Waste Management

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

Protected Species

The Canadian federal Species at Risk Act protects listed wildlife species and prohibits the destruction of or damage to critical habitat or residences. Similarly, in the US, the Endangered Species Act protects imperiled wildlife species. As additional species are proposed or newly listed to those acts, interactions with certain assets, particularly wind power generation, may increase, potentially affecting permitting, operation and associated expenditures of our Renewable Power Generation assets.

Other Regulations

New York’s State Climate Leadership and Community Protection Act

Enacted in 2019, the Climate Leadership and Community Protection Act (Climate Act) is one of the most ambitious climate laws in the US. It mandates economy-wide GHG reductions of 40% by 2030, at least 85% by 2050 from 1990 levels, and requires 100% zero-emission electricity by 2040. The Climate Act established a Climate Action Council to develop a plan to achieve these targets and directed the Department of Environmental Conservation to adopt enforceable regulations. It also provides for an economy-wide cap-and-invest program and a mandatory GHG reporting system. In March 2025, New York released its Mandatory GHG Reporting Program, requiring owners and operators to report direct and indirect GHG emissions beginning with 2026 data, with reporting commencing in 2027 and subject to third-party verification. We are preparing to comply with these additional tracking and reporting requirements while evaluating emissions-reduction strategies. Implementation timing for the cap-and-invest program remain uncertain; it is currently proposed for 2027–2028 but faces ongoing litigation. In addition to the fees associated with the cap-and-invest program, there are fines for minor errors associated with emissions reporting.

BC’s Greenhouse Gas Industrial Reporting and Control Act

In 2024, BC transitioned from an explicit carbon pricing system for large emitters, to the BC OBPS. The BC OBPS is an industrial carbon pricing system and is mandatory for facilities emitting over 10,000 tonnes of CO 2 e per year. Pipelines are treated as a Linear Facility Operation, resulting in the aggregation of all emission sources. Carbon prices are aligned with the federal benchmark and support provincial targets to reduce emissions by 40% by 2030, 60% by 2040, and 80% by 2050. The BC OBPS covers our Gas Transmission assets in BC, including the Westcoast Pipeline System and Aitken Creek, and imposes an annual obligation for stationary combustion, useful venting, and flaring emissions. Facilities exceeding their limit may comply through earned credits, offset units, or direct payment. However, if annual emissions are below the limit, the assets will earn credits to be banked for future use or sold to other operations.

Alberta’s Technology Innovation and Emissions Reduction Regulation

In May 2025, the Government of Alberta announced a freeze on its industrial carbon price under the Technology Innovation and Emissions Reduction (TIER) Regulation at CAD $95 per tonne of CO 2 e. Amendments adopted in December 2025 introduced a Direct Investment compliance option and opt-out provisions for smaller facilities, effective in 2026 and retroactive for 2025. We currently have two assets subject to TIER, which are Liquids Pipelines’ South Edmonton Terminal Natural Gas Power Plant and Gas Transmission’s Westcoast Gordondale natural gas compressor station, both of which submitted opt-out applications as of April 1, 2025, and received approval on January 30, 2026 for both facilities. As of December 31, 2025, compliance obligations remained in place; however, the price freeze stabilizes near-term costs compared to prior projections, while benchmark tightening continues at 2% annually. We expect to recognize a reduction in TIER compliance costs in 2026, corresponding to payment for the 2025 reporting year based on the compliance obligations as of March 31, 2025. These changes are not expected to have a material financial impact given the limited scope of regulated facilities and the announced opt-out provisions. We continue to monitor regulatory developments and evaluate TIER to manage cost and maintain compliance.

HUMAN CAPITAL RESOURCES

WORKFORCE SIZE AND COMPOSITION

As at December 31, 2025, we had approximately 14,800 regular employees, including approximately 2,600 unionized employees across our North American operations. Overall headcount rises to over 16,300 if temporary employees and contractors are included. While our strong preference is for direct employment relationships, where we have collectively bargained-for employees, we have mature working relationships with our labor unions and the parties have traditionally committed themselves to the achievement of renewal agreements without a work stoppage.

SAFETY

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

PRODUCTIVITY AND DEVELOPMENT

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

EXECUTIVE OFFICERS

The following table sets forth information regarding our executive officers as at February 13, 2026:

Gregory L. Ebel became President and Chief Executive Officer (CEO) on January 1, 2023, and is a member of the Board. Mr. Ebel was Chair of the Board from 2017 to 2022 and served as Chairman, President and CEO of Spectra Energy from 2009 until 2017. Prior to that time, Mr. Ebel served as Spectra Energy’s Group Executive and Chief Financial Officer (CFO) beginning in 2007, President of Union Gas Limited from 2005 until 2007, and Vice President, Investor & Shareholder Relations of Duke Energy Corporation from 2002 until 2005.

Patrick R. Murray was appointed Executive Vice President & CFO on July 1, 2023. Mr. Murray has oversight of Enbridge’s financial affairs including investor relations, financial reporting, financial planning, treasury, tax, insurance, risk and audit management functions. He also oversees Enbridge’s technology and information services teams. Prior to assuming his current role, Mr. Murray was Senior Vice President & Chief Accounting Officer of Enbridge from June 2020 to June 2023, Vice President, Financial Planning & Analysis and Controller from June 2019 to May 2020, and Vice President, Financial Planning & Analysis from February 2017 to June 2019.

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

Matthew A. Akman was appointed Executive Vice President & President Gas Transmission on January 1, 2026. He is responsible for the overall leadership and operations of Enbridge’s natural gas pipeline and midstream business across North America. Prior to assuming his current role, Mr. Akman was Executive Vice President, Corporate Strategy & President, Power from March 2023 to December 2025. Prior thereto, he was Senior Vice President, Corporate Strategy & President, Power from January 2023 to March 2023; Senior Vice President, Strategy, Power & New Energy Technologies from October 2021 to December 2022; and Senior Vice President, Strategy & Power from June 2019 to October 2021.

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

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

Allen C. Capps was appointed Senior Vice President, Strategy & President, Power on January 1, 2026. Mr. Capps is responsible for the overall leadership and operations of Enbridge’s power business and also leads our corporate strategy efforts. Prior to assuming his current role, Mr. Capps was Senior Vice President and Chief Commercial Officer, Gas Transmission from March 2022 to December 2025; Senior Vice President, Corporate Development and Energy Services from June 2019 to March 2022; and Senior Vice President and Chief Accounting Officer from February 2017 to June 2019.

Dean C. Patry was appointed Senior Vice President & Corporate Development Officer on November 17, 2025. He is responsible for mergers and acquisitions, capital allocation, investment review, and oversight of the Transaction Management Office. Prior to assuming his current role, Mr. Patry was Senior Vice President, Commercial & Strategy, Power from October 2023 to November 2025; and Senior Vice President, Operations & Engineering, Liquids Pipelines from July 2020 to September 2023. Mr. Patry joined Enbridge as Senior Vice President, Operations, Liquids Pipelines in May 2019.

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

ADDITIONAL INFORMATION

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

ENBRIDGE GAS INC.

Additional information about Enbridge Gas Inc. (operating as Enbridge Gas Ontario) can be found in its annual information form, financial statements and MD&A for the year ended December 31, 2025, which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to Enbridge Gas Ontario and are publicly available on SEDAR+ at www.sedarplus.ca. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.

ENBRIDGE PIPELINES INC.

Additional information about Enbridge Pipelines Inc. (EPI) can be found in its annual information form, financial statements and MD&A for the year ended December 31, 2025, which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to EPI and are publicly available on SEDAR+ at www.sedarplus.ca. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.

WESTCOAST ENERGY INC.

Additional information about Westcoast Energy Inc. (Westcoast) can be found in its financial statements and MD&A for the year ended December 31, 2025, which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to Westcoast and are publicly available on SEDAR+ at www.sedarplus.ca. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.