Enbridge Inc. (NYSE:ENB) Q4 2025 Earnings Call Transcript

Enbridge Inc. (NYSE:ENB) Q4 2025 Earnings Call Transcript February 13, 2026

Enbridge Inc. misses on earnings expectations. Reported EPS is $ EPS, expectations were $0.6.

Marlon Samuel: Good morning, and welcome to the Enbridge Fourth Quarter 2025 Financial Results Conference Call. My name is Marlon Samuel, and I am the Vice President of Investor Relations and Insurance. Joining me this morning are Greg Ebel, President and CEO; Pat Murray, EVP and Chief Financial Officer and the heads of each of our business units. Colin Gruending, Liquid Pipelines; Matthew Akman, Gas Transmission; Michele Harradence, Gas Distribution and Storage; and Allen Capps, Renewable Power. [Operator Instructions] Please note, this conference call is being recorded. As per usual, this call is being webcast, and I encourage those listening to follow along with the supporting slides. We will try to keep the call to roughly 1 hour.

And in order to answer as many questions as possible, we will be limiting questions to one plus a single follow-up if necessary. We will be prioritizing questions from the investment community. So if you are a member of the media, please direct your inquiries to our communications team, who will be happy to respond. As always, our Investor Relations team will be available following the call for any follow-up questions. On to Slide 2, where I will remind you that we will be referring to forward-looking information on today’s presentation and Q&A. By its nature, this information contains forecast assumptions and expectations about future outcomes, which are subject to the risks and uncertainties outlined here and discussed more fully in our public disclosure filings.

We will also be referring to non-GAAP measures summarized below. With that, I will turn it over to Greg Ebel.

Gregory Ebel: Thank you, Marlon, and good morning, everyone, and thanks for joining for our Q4 call. First off, let me welcome Matthew Akman in his new role as EVP and President of Gas Transmission and Allen Capps to his new role as Head of Corporate Strategy and President of Power and introduce Marlon Samuel as the new VP of Investor Relations. Their backgrounds and experience have positioned them exceptionally well for success in these roles, and I know they look forward to working with you. Today, we’ll recap another successful year, followed by an update on our opportunity set through the end of the decade before providing updates on our 4 businesses since our last quarterly earnings call. Pat will then walk through our record financial results, capital allocation priorities and give a refreshed view of our annual investment capacity.

Lastly, I’ll end the presentation with a few reminders on Enbridge’s first choice value proposition before we open the line for any questions from the investment community. We had another great year of record financial results, exceeding the midpoint of our 2025 guidance for both EBITDA and DCF per share, marking the 20th year of achieving or exceeding our annual financial guidance. As we announced in December, we have now increased our dividend for 31 consecutive years, extending our status as one of the few dividend aristocrats in our sector. Our debt-to-EBITDA remains within our leverage range of 4.5 to 5x, maintaining our strong investment-grade credit profile while growing our investment capacity. From a growth and execution standpoint, we sanctioned $14 billion of capital across all businesses and placed $5 billion of assets into service during the past year.

Our growth backlog has grown 35% since our Investor Day last March, underlying the ongoing and extended business and earnings growth opportunity we have before us. We continue to develop our relationship with our Whistler JV partners, acquiring a 10% interest in the operating Matterhorn Express pipeline. We also announced a historic investment in our West Coast pipeline system by 38 First Nations groups, allowing Enbridge to create alignment with indigenous communities and helping to advance economic reconciliation while actively recycling capital. Operationally, our assets remain highly utilized during the quarter with the mainline transporting approximately 3.1 million barrels per day on average. Our gas systems were also highly utilized in the quarter.

And in recent weeks, we saw a number of all-time peak demand days for both our Gas Transmission and Gas Distribution and storage assets. To provide a couple of impressive stats, Texas Eastern recently hit new peak records, transporting over 15 Bcf per day in January. And in our utilities, Enbridge Gas Ohio hit its third highest throughput day in the company’s 128-year history. And in the severely energy infrastructure short in New England, our Algonquin pipeline saw 9 of its top 25 all-time volume days this winter, underlying the need for energy affordability creating expansions of natural gas infrastructure in that region. At the utilities, we reached constructive settlements at both Enbridge Gas, North Carolina and Enbridge Gas, Utah and filed a new rate case at Enbridge Gas, Ohio.

Lastly, we successfully extended contracts on a number of LP assets. And once again, our gas transmission assets had another 100% contract renewal rate with customers on our major pipelines. So now let’s dive into exactly where we allocated our growth capital in 2025. Taking a look at the map, you can see we won more than our fair share of opportunities this past year, sanctioning over $14 billion of capital in 2025, putting us ahead of where we forecasted during last year’s Investor Day. In Liquids, we FID-ed over $4 billion of projects, locking in the majority of opportunities we laid out for the Western Canadian Sedimentary Basin growth within the year. In Gas Transmission, we sanctioned projects supported by natural gas fundamentals, including industrial and data center demand, the LNG build-out, our customers’ storage needs and deepwater offshore opportunities.

Total capital secured in Gas Transmission during the year was approximately $4 billion, making significant progress on the $3 billion to $5 billion of opportunities we expected to sanction within 6 to 18 months of our Investor Day. In the utilities, we continue to invest approximately $3 billion of foundational capital per year to expand our systems and keep them safe and reliable. And finally, in Renewable Power, we’ve added $3 billion of capital to support technology and data center operations for companies like Meta. This places us well ahead of the timing we outlined at the Investor Day, where we showed $3 billion of late-stage opportunities with potential FIDs between 2026 and 2027. In total, our power and natural gas projects currently under construction are now completed, support over 7 gigawatts of power generation across multiple businesses.

I think it’s safe to say that just under a year since Enbridge Day, we have made tremendous progress on the commitments we laid out and continue to work hard to advance additional accretive projects. Continuing the momentum from 2025, our teams are busy advancing opportunities from our unsanctioned backlog. With fundamentals supporting expansion in each of our 4 businesses, we expect to reach FID on another $10 billion to $20 billion of growth projects over the next 24 months that will enhance energy security and affordability in North America and beyond. Gas Transmission has the largest opportunity set of our core franchises, driven by industrial and power demand, along with growing LNG exports and storage. Potential projects include expansions on Vector, Valley Crossing, Texas Eastern, Algonquin, opportunities in the U.S. Southeast and the Homer City redevelopment as well as additional storage expansions at Tres Palacios.

In Liquids, supported by the WCSB production growth and overall global demand, we continue to advance opportunities, including MLO 2 and 3 and expansions to our regional oil sand assets. We’ll continue to invest about $3 billion a year in our gas utilities to support new customer connections as well as opportunities driven by new power demand, including data centers. And in renewable power, we will remain opportunistic advancing projects to support demand driven by hyperscalers and other large tech companies and/or those seeking power from lower carbon sources. Now let’s jump into the BU updates, starting with the Liquids segment. In light of recent geopolitical events, let’s take a step back and remind everyone of our irreplaceable Liquids footprint.

Our mainline is a vital connection between the growing production in the Western Canadian Sedimentary Basin and the refiners in PADD 2 and PADD 3, which are consistently drawing higher volumes of Canadian heavy crude. We saw strong demand throughout the year on the mainline, which was apportioned for all but 3 of the last 12 months, delivering on average 3.1 million barrels per day. In fact, the mainline was also in double-digit apportionment in January and February of 2026. Given Enbridge’s unique asset footprint and our expectation that the low-cost established WCSB production and demand continues to grow, we do not expect any material impact from the recent geopolitical events involving Venezuela. In Q4, supported by growing production, we sanctioned the first phase of mainline optimization, which will add 150,000 barrels per day of additional egress out of the basin.

The project also includes a 100,000 barrel per day expansion on Flanagan South and is expected to cost USD 1.4 billion and enter service by the end of 2027. As part of MLO1, the majority of our customers elected to extend their Flanagan South take-or-pay contracts beyond 2040. We’re also commercializing mainline optimization Phase 2, which could add another 250,000 barrels per day of incremental egress in the 2028 time frame. Customers remain very interested in moving this project ahead, and it showcases the benefit of existing assets in the ground as this project leverages underutilized capacity on assets such as Line 26, Dakota Access and Chicap. MLO3 is also making progress. And although we’re not in a position to provide much detail right now, the project will create further significant egress opportunities to support our customers well into the future.

A quick update on Line 5. The U.S. District Court recently ruled in our favor, preventing the State of Michigan from taking further action to shut down Line 5. And the U.S. Army Corps of Engineers issued their final EIS, another step in the right direction for the Line 5 tunnel project. In our Gulf Coast and Permian franchise, the 80,000 barrel per day expansion of Gray Oak pipeline entered service in 2025 and the remaining 40,000 barrel per day expansion is on track to enter service in the first half of 2026. Lastly, we continue to expand our storage footprint at the Enbridge Ingleside facility as well as explore additional service offerings off the docks at Corpus Christi. Now let’s turn to our Gas Transmission business. Our Gas Transmission franchise is well positioned to serve growing energy demand across the continent, and the team is currently working on a number of exciting projects.

These opportunities will address a range of demand drivers, including electric and gas utilities, LNG exports and emerging data center powered needs. Currently, we’re advancing over 50 potential data center opportunities that could require up to 10 Bcf per day of natural gas, and we expect to begin sanctioning these additional projects throughout 2026 and more in 2027. In the Permian, our JV investments in natural gas infrastructure are set to offer over 11 Bcf per day of long-haul capacity and are supported by over 2 Bcf of storage capacity at Waha. We’re announcing today that along with our partners, the sanctioning of Bay Runner, an extension of the Whistler pipeline, which will supply gas to Rio Grande LNG facility in combination with previously announced Rio Bravo Pipeline for total capacity of up to 5.3 Bcf per day.

We have also upsized the Eiger Express pipeline from 2.5 Bcf per day to 3.7 Bcf per day, driven by growing demand for natural gas transportation out of the Permian and supported by long-term customer contracts. Lastly, we’re extending our U.S. gas transmission modernization program another year into 2029 and to highlight that the Appalachia to Market II project is now in service. 2025 represented a milestone year for gas distribution and storage as it was the first full year of operations for the U.S. gas utilities as Enbridge Gas. In Ontario, we continue to efficiently run Canada’s largest natural gas distribution company with new rates in effect at the beginning of 2025. In Ohio, we received a somewhat disappointing rate case decision in the middle of the year, but maintained Enbridge Gas Ohio’s allowed ROE at 9.8% on a slightly higher equity component.

Since some time had passed since the original filing, we filed a new rate case at the end of 2025, updated with refreshed operating and financing costs. In Utah, we reached a supportive rate case settlement with rates in effect on January 1, 2026. And in North Carolina, we received a supportive outcome as well with rates in effect in November 2025 and welcome the addition of new major capital project riders to allow us to meet our customers’ growing needs and realize a quicker return of capital for our investors. Finally, with growing power demand in all jurisdictions, we are finding increased need for access to low-cost gas feedstock for up to 5 Bcf per day of power generation and associated demand growth. This will further grow our utilities well into the next decade.

Now I’ll move on to the Renewables segment. Building on the Clear Fork Solar project, which reached FID in mid-2025, we are excited to extend our partnership with leading technology companies like Meta Inc., sanctioning Cowboy Phase 1 and Easter Wind, supplying over 500 megawatts of renewable power to support data center operations. Cowboy Phase 1 is a 365-megawatt solar and 135-megawatt battery energy storage project in Wyoming with the output secured by a fixed offtake agreement and the battery component of the project secured by a fixed toll agreement. The full output has been secured by a MAG 7 technology company. The battery system will be supplied and operated by Tesla, the leading supplier in North America and can be expanded up to 200 megawatts after the approval from the utility, which is expected in the first half of 2026.

This project’s CapEx is USD 1.2 billion and is expected to enter service in 2027. Easter is an onshore wind project being built near Amarillo, Texas, with a capacity of 152 megawatts. This USD 400 million project is secured by a renewable power purchase agreement with Meta. In total, our power partnership with MAG 7 companies is set to provide over 1 gigawatt of renewable generation to support operations and add new generation to the local grids. Looking ahead, we still have over 1 gigawatt of projects in the queue that we’re advancing, remaining opportunistic while continuing to ensure these projects will realize mid-teen returns. Providing an update on 2 of our projects under construction, I’m happy to announce that the first phase of Sequoia Solar entered service in December, and our Courseulles Wind project in Europe remains on track to enter service in 2027.

With that, I’ll now pass it over to Pat to go over our financial performance.

Patrick Murray: Good morning, everyone, and thank you, Greg. I’m pleased to report again record fourth quarter and full year EBITDA, DCF and earnings per share. Compared to the fourth quarter of 2024, adjusted EBITDA is up $83 million. DCF is up $0.06 and EPS increased $0.13. In Liquids, strong mainline volumes, annual escalators and lower power costs led to year-over-year increase in the segment, net of earnings sharing. We experienced a strong fourth quarter in our Gas Transmission business with incremental contributions from the acquisition of an interest in Matterhorn and placed the Venice Extension into service. As well, we saw favorable spreads at Aitken Creek and had exciting recontracting on our U.S. Gas Transmission assets.

The gas distribution segment is up relative to last year, driven by rate escalation, customer growth in addition to colder weather and strong storage results in Ontario, higher rates in North Carolina and recovery of capital investments in Ohio also increased the EBITDA. In Renewables, results were lower compared to last year due to the absence of investment tax credits relating to the Fox Squirrel Solar project, which we put in service in Q4 of ’24. Lower maintenance costs due to increased buying power at our gas utilities and lower current income tax driven by investment tax credits and benefits from U.S. tax legislation changes further increased DCF per share year-over-year. I’m also pleased to reaffirm the 2026 guidance that we put out in early December.

We continue to be confident that we’ll achieve our full year EBITDA expectations between $20.2 billion and $20.8 billion and DCF of between $5.70 and $6.10 per share. Our growth is driven by $8 billion of new assets expected to enter service throughout the year and across enterprise cost savings initiatives. So far, in ’26, the mainline has been apportioned in January and February, as Greg noted, and we’ve experienced colder-than-normal weather in most of the eastern parts of North America, providing a strong start going into the year. As a reminder, Q1 and Q4 are typically our strongest quarters, primarily driven by the higher earnings attributable to our gas utility franchises during winter periods, the absence of heat restrictions on our liquids assets as well as more peak days in gas transmission.

Now let’s discuss our capital allocation priorities, which also remain unchanged in ’26. We’re committed to continued equity self-funding and benefit from the natural stability of our regulated assets and predictable cash flow streams. On the leverage front, our balance sheet remains strong. Our debt to adjusted EBITDA sits up 4.8 and our 4.5 to 5x range remains unchanged. Core to our value proposition, we will continue to sustainably return capital to shareholders through dividends with $40 billion to $45 billion of distributions expected to be paid out over the next 5 years, all underpinned by growing regulated and contracted cash flows. And our 60% to 70% DCF payout target range remains unchanged as well, with us sitting right around the middle of the range today.

To fuel long-term growth, we’ll continue to target accretive brownfield projects supported by strong energy fundamentals. With the project additions this quarter, our current backlog now sits at $39 billion and extends through 2033, highlighting our ability to execute on the opportunity set we laid out in front of investors back in last March. With that, let’s look at our annual investment capacity and how that also continues to grow. As our cash flows grow, so does our annual investment capacity, which now sits between $10 billion to $11 billion annually, supporting investments in growth projects across all 4 of our core business units. Our balance sheet strength gives us the ability to pursue $6 billion to $7 billion of organic growth projects annually, in addition to the $4 billion of foundational capital that will support our utility growth programs, gas transmission modernization and liquids mainline capital investment.

We continue to realize improving returns, showcasing our efficient use and deployment of capital. That’s evident in our improving return on capital employed, which has consistently tracked upward these past number of years via optimizations of our business, annual cost savings from scale and technology advances and accretive M&A. These returns are further compounded by the project slate we sanctioned in 2025. On average, the growth projects have strong return on capital employed with an average of approximately 11% across all organic projects. Securing strong return projects, combined with cost and revenue optimizations on existing assets creates a compounding effect, which will continue to grow our investment capacity into the future. With that, I’ll turn it back over to Greg to close out the presentation.

Gregory Ebel: Well, thanks very much, Pat. And as you’ve just heard, it was a busy quarter, capping off an incredible year, and I’m proud of the rapid progress our teams have made since our last Enbridge Investor Day. In an ever-evolving North American energy landscape, Enbridge continues to be very well positioned to realize ongoing growth. Our disciplined capital allocation approach and our low-risk business profile continues to drive consistent long-term shareholder value and a first choice investor proposition. Supported by long-term agreements and regulatory frameworks, Enbridge generates predictable cash flows, which have enabled 31 consecutive years of dividend increases. And going forward, we expect to achieve 5% growth through the end of the decade, supported by our now $39 billion of secured growth capital.

Our scale and diversity provides us with capital optionality that few in our industry possess, and we will continue to evaluate accretive investments across our entire footprint. With that, I’ll open the call to questions.

Operator: [Operator Instructions] Your first question comes from the line of Sam Burwell from Jefferies.

Q&A Session

George Burwell: Noticed that the investment capacity increased by $1 billion, which makes sense. But the longer-term post ’26 growth trajectory still looks around 5%. So just curious how those 2 reconcile. And also curious if there might be maybe some underappreciated upside in ’27, ’28 EBITDA growth given that 2026 was a little bit of a softer year, but you’ve got a lot more capital entering service in 2027.

Gregory Ebel: Yes, I think it’s fair. I think TheStreet consensus still is probably like 3%. So as we’ve said, we’re very confident in getting to the 5% number. obviously, that capacity grows with EBITDA growth. And as we bring in more projects, I think it reconciles with that, right? So as we spend more capital, you need more capacity. We’ve got the more capacity with the EBITDA growth. So I’m not sure, Pat, I don’t know if there’s anything to add on that front.

Patrick Murray: Yes. I mean I think that we’ve always assumed that if we put projects in on time, on budget with good returns that, that capacity would continue to grow. And so that was baked in or acknowledged as we thought about our growth rate through the end of the decade. And we just get more and more confident, as Greg said, with the backlog of strong returning low-risk projects that we’ll be able to meet that. So I don’t think it just helps TheStreet to understand that we’ve got a fair amount of capacity here as we move forward.

Gregory Ebel: As I said, we’re comfortable with the 5% growth. I guess if — what other dynamics out there are we looking at? Obviously, from where we were a year ago, the Western Canadian Sedimentary Basin situation looks positive, more production there, better attitude from governments about the competitiveness of Canada and seeing production grow there. So I guess that could create some opportunities. And you’re already seeing that in MLO1 and MLO2. And as we said, the possibility of an MLO3. Gas transmission, I think you just heard us talk today about you’ll see more FIDs here in the next year and into 2027 as well. Gas Distribution, you make a good point there. I think we bought those gas distribution assets in the U.S., we were looking at 8% type rate base growth through the end of the decade, and now it’s closer to 10% rate base growth.

And then I wouldn’t be surprised if we exceed our power CapEx estimate that we laid out at the last Investor Day, and you see that already as we — as customers are looking for electrons. I don’t really care what color the electron is. They’re looking for electrons, and you’ve seen us cut deals here announced today with Meta and MAG 7 players. So all that plays into it. We’re moving a big ship here, of course, at $20 billion and a couple of hundred billion dollars enterprise value. But I think you’re on the right track and actually pleased to see TheStreet looking for more on top of the 5% as to wondering how we’re going to get to the 5%.

George Burwell: Okay. Yes, that’s a big ship indeed. And I appreciate your comments earlier on Venezuela, but I just wanted to drill down a little bit more on that. I mean, is it fair to characterize the framework being all right, there’s growth in the WCSB. That growth will, in all likelihood, fill up TMX. And then after that, any growth that materializes and there should be growth that’s already baked into the cake as projects going to be sanctioned, that needs to clear via your full path to the Gulf Coast, and that’s what gives you confidence in advancing MLO2 and then mentioning MLO3 today.

Gregory Ebel: Well, I think I’ll let Colin chime in, but I think there are several aspects to it. A, there continues to be a need on the Gulf Coast for heavy crude even, and we don’t underestimate it, even if you see Venezuela barrels come in, and I think the smart consensus is called that maybe 400,000 or 500,000 barrels. There continues to see Canadian crude export it. But we’re continuing to see an increase of the utilization of the mainline. As you heard us say, all but 3 of the last 12 months, we saw apportionment and big start of apportionment, I think, going back to even before TMX started up in January and February. So I think producers want to go south first, Colin.

Colin Gruending: Yes. I think so. Sam, I think your framework is roughly right. And maybe there’s a West Coast solution in there in a bigger way someday. But in the meanwhile, and in this uncertain environment, I think our historic playbook of iteratively expanding the mainline is a winning formula and kind of fits the pistol of customers on both the supply push and demand pull end of things for — to try to find certainty. And MLO2 solves that 2028 egress bottleneck that’s going to emerge. So its advantages that it’s in service in ’28. But I think you got your framework roughly right. And just watch that Canadian supply growth and disposition Gantt chart that we’re filling in.

Operator: Your next question comes from the line of Rob Hope from Scotiabank.

Robert Hope: Given the project backlog, which could include $10 billion to $20 billion of projects sanctioned here over the next 2 years, how do you think about the potential to exceed the $10 billion to $11 billion of annual investment capacity and relying on other sources of funding to capture what is an increasingly growth-rich environment?

Gregory Ebel: Yes. I mean Pat can add in here, but I think we feel very good about it. Rob, even added those projects, they don’t all happen instantly, right? Even our $39 billion current backlog runs through 2033 kind of time frame. So fits very much in that. And remember, that capacity will also grow as EBITDA grows, right? So to put it in rough terms, every dollar we raise in EBITDA is going to create capacity of $4 to $5 in debt capacity. So I think we feel very good about that. Now that being said, we’re always looking at recycling capital. You saw us do that last year in a very smart way and one that I think helps our overall business, such as Dawn project where we sold 12.5% of the West Coast pipeline to some 35, 40 indigenous nations.

So there’s opportunities like that, that we look at. So I feel very good with where we are from a balance sheet perspective. But yes, I always look at recycling capital to help create that buffer and allow us to continue to add more to the backlog.

Robert Hope: That’s great. I want to go back to Venezuela. So it doesn’t appear that Venezuela slowed down MLO2 at all. However, when we think about MLO3 and the timing for that project, could we need to see increased clarity on either increased exports out off to the Gulf Coast, what the Venezuela situation looks like? Or do you think in any case, Canadian crude will find a home in the Gulf Coast and that MLO3 has a good chance of moving forward?

Gregory Ebel: Well, I think it’s a bit of the all above. The only other addition I would add there with MLO3, what we really need to see is actually the change in policy in Canada that meets the desires that the Prime Minister has articulated by increasing oil and gas production. So those changes are spoken about pretty openly. And that’s what has to come first, right? Production growth first, pipeline second. So I think that’s a big element of it. But Colin, I know we haven’t got a lot of details out there on Line 3 yet — or MLO3, but do you want to speak to that?

Colin Gruending: Yes. So let’s call it MLO3, but you could probably call it MLO126 because we’ve expanded the mainline a lot of times. And we just simplified the numbering to keep it simple for current vintage of participants. But — and there’s — we’re developing multiple options for MLO3, small, medium, large, depending on what industry needs. I think on Venezuela, listen, it’s early days and certainly, the longer-term outcome there is uncertain. But we’ll see how quickly Venezuela grows its production, then we’ll also need to evaluate what portion of that increased supply growth comes to the U.S. Gulf Coast. It’s on VLCCs for the most part, and some of it may well stay on the water and feed the global refineries it has historically, but perhaps at a higher price for that country.

I think that’s one of the objectives. Also remember, Rob, that there is probably another 400,000 barrels a day of U.S. Gulf Coast heavy refining capability on top of what’s being utilized today. And also don’t forget about the inevitability of re-exports of Canadian crude off the U.S. Gulf Coast in meaningful scale over time. So listen, the U.S. Gulf Coast is the world’s best heavy refining market and Canadian crude is a meat and potato part of the diet there. So I think it’s still going to work pretty well all around.

Gregory Ebel: Yes. Rob, I’d say there’s multiple ways for us to win. So it’s a good question. I think Colin’s laid out some great ones here. And the Venezuela piece is a supplement to Canadian heavies, not a replacement. The other thing I think you should think about is if there is more of that kit on the Gulf Coast used with Canadian heavies, maybe that means less light Permian needed on the Gulf Coast, which would mean more of those light barrels would actually probably get exported. Guess where those get exported? From Ingleside. So I think it really underlines the Swiss Army knife as Colin likes to call it, of the super system we’ve created down there really to find ways for Enbridge liquids system to win in all scenarios.

Operator: Your next question comes from the line of Theresa Chen from Barclays.

Theresa Chen: Greg, on your last point about potential expansion capability or pushing further WTI volumes out of Ingleside should the Gulf Coast refining heavy up their crude feedstocks. Curious to hear what kind of expansion capability do you have there beyond what you sanctioned thus far? And to what extent would that necessitate expansion of your own pipeline feeding that facility versus barrels potentially going on competitor’s pipelines in that area?

Gregory Ebel: Yes. Remember, we have pieces of Cactus and Gray Oak. So those lines are seeing some expansion. In fact, some Gray Oak expansion continues to come on next year. Remember, we’ve added some storage capacity at Ingleside. And then, of course, last year, picked up some more dock space. So I think we’re in good shape. And in fact, optimizing the utilization of the VLCCs, Aframax, Suezmax on the right dock, if you will, so that you fully utilize via the bigger dock, the VLCC docks as well as the smaller docks. So Colin, any other pieces to add there?

Colin Gruending: Yes. No, astute question, Theresa. We have lots of headroom at Ingleside, right? We acquired neighboring docks from Flint Hills. We’ve got lots of permitted headroom on the docks. We’ve got lots of land. We’re still constructing right now tanks. We could do more of that, and we’re 3/4 of the way through the Gray Oak expansion and can do more there, too. So that’s a big long-term opportunity that we’ll continue to realize for many years as the Permian grows again.

Theresa Chen: Understood. And on the heels of so many questions about the geopolitical backdrop, understanding that the situation is still evolving. And with your commercialization efforts on MLO2 and 3, how should we think about how the discussion of the marginal all-in rates are coming to terms is — as the projects come to fruition late decade and beyond? And how do those economics compare versus the current committed and spot rates on mainline as we think about the upcoming renegotiation for the system, the ROE color over the next couple of years?

Colin Gruending: Are you asking about the competitiveness of our tariffs on the expansions basically?

Theresa Chen: I’m asking about like how the tariffs — the discussion of where those tariffs are on the expansions under development changed since we’ve had incremental rerouting or expected rerouting of Venezuelan barrels to the Gulf Coast. I imagine no from MLO2 because that is into the PADD II market. I mean, those refineries are not going to see a drop of Venezuelan crude. But from MLO3, if that is a Gulf Coast oriented pathway, how does that change your economic thinking on terms?

Colin Gruending: Yes, I got you now. So yes, no, I don’t think there’s much to talk about here. Our tolls are competitive. They need to be competitive. They’re often cost informed, right, especially as we socialize some of those tariffs to all mainline shippers. And remember that our expansions are optimizations. And so therefore, they’re inherently efficient. So those tariffs should be in the money and very competitive.

Gregory Ebel: And color, Theresa, just for clarity, like MLO2 is a full path. You’re getting all the way to the Gulf too. So yes, you’re getting demand pull and supply push into PADD II, but also all the way down to the Gulf too. And I think that’s some of the great thing about the MLOs, they’re modest incremental builds that allow producers to kind of witness the market as it develops and have that insurance egress, but also keep a keen eye on the geopolitical side of things. And that’s one of the great things about it as opposed to, say, committing to a big greenfield that’s probably post 2028.

Operator: Your next question comes from the line of Aaron MacNeil from TD Cowen.

Aaron MacNeil: I don’t want to understate the Venezuela risks, but maybe for fun, I’ll just take the other side of it. Not only have we seen apportionment on the mainline, but the level of apportionment has increased pretty meaningfully over the last few months. Has mainline demand surprised you to the upside? And have you observed sort of an increased sense of urgency from your customers given the high apportionment in February? And to the extent that you have a view, how are you thinking about Alberta storage levels going forward?

Colin Gruending: Aaron, I mean this has been going on for 30 or 40 years, right? My whole career, I think we’ve seen strong demand for the mainline for a whole bunch of reasons. I’m not going to list them out here. But I think in the last couple of years, I think Canadian supply has probably surprised the consensus view to the upside a little bit. There’s been a number of optimizations like we’re doing upstream by our customers, really high return, quick cycle, attractive economics just to get more out of their existing — they’re basically re-rating their kit. And so I think that has probably surprised the consensus view, maybe us a little bit, but I think we’ve had a lot of conviction in the thesis the whole time. And it’s in part why we designed the mainline tolling deal the way we did so that we could hustle for customers and participate in some of that upside.

But as this continues and as Greg said, hopefully, the Canadian political deal continues and accelerates in light of the potential of Venezuelan competitive threat, and we can see more of this.

Gregory Ebel: I think the other thing, Aaron, there’s a good lesson in here, and you made the strong point about Western Canada. We’ve always had strong conviction, as Colin says, but I think the other aspect out there on the macro side that the market seems to underestimate is the power of consolidation and those major producers coming together and their ability, therefore, to wring out better economics and actually production at an economic rate. And that lesson needs to be considered as we think about the Permian, where, as you know, we’ve seen big consolidation there by really the best players on the planet in terms of oil production. And I fully expect they’re going to find ways to grow that production at economic rates, which, again, I think is positive for Enbridge Systems, both north and south. So yes, good point.

Aaron MacNeil: Maybe switching gears to Gas Transmission. You mentioned the $10 billion of projects in the near-term opportunity bucket. Can you just speak to the growth rate of the segment currently. Obviously, it significantly exceeds the corporate average. And how sustainable do you see that sort of outsized growth rate for the segment specifically.

Gregory Ebel: Well, Matthew is here and he’s looking at his chop. So I’ll let him go at it.

Matthew Akman: Yes. Thanks for the question. I think the big picture is everyone is starting to come on to the same page that the most important issues in energy these days for average people, which are affordability and reliability are going to be solved by natural gas. And so we see a long runway. There’s, I think, a huge pent-up undersupply of pipeline capacity across the country. And that’s the starting point. And then you layer on top of that the power demand and data centers that everyone is talking about. And of course, the export trends and looking to double exports out of the Gulf Coast. So we’re extremely well positioned on all of those fronts. We talked this morning about some of the expansions out of the Permian and the Eiger upsize and the Bay Runner extension.

But I think you can expect us also, as Greg alluded to, to be adding to our growth table in GTM on a few fronts in the near term. I don’t know if you saw, but we just finished an open season on Vector into Wisconsin, a lot more demand there for power and natural gas for utility distribution. Texas LNG1, which we’re very close to, has made great progress lately on both offtake and financing. You might have read about that. And storage demand appetite is voracious in the Gulf Coast. We have some more expansion opportunities there in the near term. So those are just some of the things I think you could expect us to be talking about pretty soon and adding to that near-term growth table. Longer term, when you look at all of our regions up and down the entire nation from the Northeast to the Southeast and pretty much all points in between, we see tons of opportunity in the Northeast, we have a relatively small expansion going on in Algonquin, but there’s appetite for large expansion there.

And you’re starting to see things thaw in terms of permitting and the realization that it just doesn’t make sense to have 40% of power generation come from oil — burning oil in a cold snap or $150 gas, and we’re the solution to that. And in the Southeast, just population growth and obviously, economic growth, and we have a couple of pipelines into there. We’ve been expanding SESH and we have Sabal Trail. So yes, we’re just seeing fantastic opportunities all the way up and down the country. And I think you can expect to see growth out of us there in the near term and for many years going forward.

Gregory Ebel: I think from a capital allocation perspective, it also allows Pat and I to make sure we get to pick the projects that actually provide the best returns and be very picky about the regions. And if they don’t meet the returns that are going to get our growth rate or accelerate our growth rate, we don’t have to allocate capital there. So it’s a pretty nice setup from an investor perspective, but also from a capital allocation perspective.

Operator: Your next question comes from the line of Maurice Choy from RBC Capital Markets.

Maurice Choy: Just want to pick up on that last question about returns. Slide 14, you’ve discussed the enhancing of asset returns with 2025 organic projects about 11% and 2026 just under 10%. When you think about your $10 billion to $20 billion of projects over the next 24 months, are we expecting these projects to have similar 10% to 11% levels? Or are the project mix so vastly different that might be outside of this range on a portfolio basis?

Patrick Murray: Yes, thanks for the question, Maurice. I think our view would be that given the amount of opportunities we have in front of us that they’re probably going to average up that as we go through time here, whether it’s our renewable projects that we’ve talked about being in those mid-teens, high-quality projects, strong returning in GTM. We haven’t had as many liquids projects entering service as we will over the next 3 or 4 years, and those are some of our strongest projects as we go through things and then balanced out, of course, by the utility. So I think we’re very confident that we can continue to improve returns and not only from the projects we’re sanctioning, but from optimizing the base assets that we have as an organization, whether that’s through things we’ve done on the mainline volumes, whether that’s through cost, technology. So I think it’s kind of a two-pronged approach, not just returns on new projects, but also on the base assets.

Gregory Ebel: I think the other thing we think about is risk-adjusted returns as well because obviously, the utility doesn’t earn those similar returns. But even there, we’ve seen in some recent rate cases to get slightly thicker equity and ROEs on that equity. So I think we try to balance both of those, which is one of the reasons why you can increase the dividend 30 years solid without being concerned about being whipsawed back and forth by whether geopolitical or economic cycles or politics.

Maurice Choy: That makes sense. If I could take one step further in all our discussions about Canadian politics, given the Davos speech, geopolitical events, even the upcoming USMCA negotiations, have there been any signs in your regular engagement with the Canadian or Alberta governments on how they may support major energy infra projects, including perhaps backstopping cost overruns or financing?

Gregory Ebel: Well, I have not heard that on the latter. But obviously, there’s been lots of signs and signals. I think what we’re looking for is actually concrete actions. So the MOU between the Government of Alberta and the Government of Canada was very encouraging. That’s several months ago now, and the world keeps changing, right? So I think it’s not so much about the signals and the speeches. It’s more about the actions and the results that I think is what our customers are looking for, what our investors are looking for and what we’re looking for. So yes, very positive on the signals very positive on the Prime Minister’s comments about growing oil and natural gas. In terms of backstopping, that’s an interesting one. I guess you could say there’s things like loan guarantees that happen for certain stakeholders.

I don’t see that happening for the — for private sector players. But some of these projects that are really big, you’re going to need some type of commitment of stable policy and maybe backstopping until it’s built, if you will. But we do that in the Northeast, too. Our Northeast utility customers, Northeast United States, given some of the starts and stops we’ve seen there on the policy-wise, we’re not going to take the financial risk on development of projects. We’re quite happy once we get the go-ahead to take the risk on building them. But we’re not going to take the risk of them being stopped before they go into service or frankly, even FID because some of these projects, you’re spending hundreds of millions of dollars before you even get regulatory approval.

Maurice Choy: Understood. Just to clarify there, you’re comfortable with the project development and your ability to deliver, but the policy protection and durability there that’s the biggest crux of this.

Gregory Ebel: Yes, that’s exactly right. So many projects and the larger the project you want to go, you’re talking many years, right, which you can get changes in policy and politics. I don’t think investors or the infrastructure companies should be taking on all that risk of the development in jurisdictions that have historically created a challenge. Like again, I look at the Northeast United States, we’ve had projects where we would have spent several hundred million dollars and with the stroke of a pen project doesn’t move forward. You saw that in Northern Gateway. We spent $600 million, combo of shareholder money and customer money and the rug was pulled out from underneath. So that’s not the type of risk that we’re looking to take on at this time. We don’t need to with all the other opportunities.

Operator: Your next question comes from the line of Jeremy Tonet from JPMorgan.

Elias Jossen: This is Eli on for Jeremy. Just wanted to dive a bit deeper on the power demand opportunity set. Obviously, you’ve talked about the focus is on best returns. But we’ve seen some of your peers go for chunkier power solutions, including some behind-the-meter opportunities. Just in the context of this growing investment capacity, how should we think about whether you’d consider these larger power-focused projects and then what those returns might look like?

Gregory Ebel: Yes. I think we’re quite comfortable with finding the opportunities associated with power at GTM and GDS. I think as you look at GTM, sometimes I think it gets overlooked. But whether it’s Line 31 in Louisiana or this AGT built or SESH or the TVA project, those are all chunky ways to play the power game. GDS, as you saw this morning, we’re talking about 5 Bcf of gas infrastructure potential for power demand growth. And that’s on top of the things like over 1 gigawatt of power infrastructure we put in place for Duke. You’ve seen us do things like that in Ohio, Novva Data Center in Utah. So I think there’s ways to play there. And then importantly, of course, the renewable side. And I’ll go back to — I don’t think most of our customers are that focused on the color of the electron these days.

I think they’re focused on the electron and some 3 gigawatts in the last couple of years that we’ve signed up for. We’ve been thinking about this a long time. In 2022, we bought Tri Global with a great background of large renewable projects that you can see us bringing into service. And you can’t ask for better customers than Meta, than Amazon and Google, all of which we’re playing. So don’t see us going into the IPP, the gas IPP business. I mean maybe there’s some bespoke opportunities here and there, but we like the long-term contracts that we’re able to get with renewables, 15-, 20-year contracts, which are different than contracts often that you see in the IPP world of say, a decade or so. So the risk profile fits us better in the way we’re going at this.

And Allen is here, he may want to add to it as well.

Allen Capps: I’ll just mention one thing, too, that with the tax credit situation in the U.S., we’ve got over 2 gigs of safe harbored opportunities in the renewable space that should keep us busy for the next 3 years. So we have a really strong opportunity set on the solar, the wind and also the battery side as well. So we’re excited about that, and I think we’ll focus on that from a power perspective.

Elias Jossen: Awesome. Appreciate the color. And then maybe pivoting to the kind of B.C. storage opportunity landscape. Can you just talk a little bit about some of the storage economics out there and what you’re hearing from customers? I think sometimes the storage opportunity gets overlooked, but I imagine it could be pretty sizable for you guys. So just any messaging there.

Matthew Akman: Sure. It’s Matthew. So I think storage not just in BC, but across our entire footprint is a major theme. And the demand growth continues from obviously, LNG and then the power side. So we have in storage a significant expansion going on up in B.C. right now at Aitken, 40 Bcf. The market there is very attractive. And in Canada, a lot of that is going to be based on the factors that have driven storage in B.C., which is the appetite for LNG that’s picked up the market there. And we’re looking for, obviously, strong stakeholder and government support for further LNG exports out of Canada. There’s been talk of expansion of LNG Canada, maybe a second phase and other projects. So we see strong organic growth on the rates we’re getting and then obviously, just the expansion.

And when you combine those, we’re expanding by 20% to 30% across our storage footprint. And then when you combine that with just steadily increasing storage rates from these fundamental trends that you asked about, we’re seeing great organic growth out of our storage business for the next few years.

Gregory Ebel: The other thing, Eli, and Matthew, I think you’d agree is that we’re seeing really interesting contracting where we still — look, contracts for storage tend to be in the kind of 2- to 5-year range typically, but we’re seeing big chunks of our storage being contracted for the long term as well, in some cases, up to a decade. So it’s fitting the risk profile, sort of fitting the return profile. And as you point out, I think Aitken Creek does get overlooked. I mean it’s the only major gas storage play that you’ve got in British Columbia at a time when, as you’ve seen on the Gulf Coast, as LNG projects come in, it’s a pretty exciting opportunity for us. So I appreciate the question.

Operator: Your next question comes from the line of Robert Catellier from CIBC.

Robert Catellier: I just wanted to see if you could follow up on your answers to Maurice’s question and provide some updated views on the progress that you’re seeing in the Alberta, Canada MOU and setting the right investment conditions for a pipeline to the West Coast?

Gregory Ebel: Yes, Rob, thanks for your question. I think what we’re looking for, there’s 2 important milestones that have been out there for a while that are coming up close. The April time frame where the Government of Alberta and Canada, I think, are trying to come to a solution on industrial carbon charge, stringency, et cetera, on those matters. That’s going to be super important for our customers, producers to get a feel for whether or not Canada is competitive enough for them to continue to see the kind of growth that we’ve been seeing. So that’s the key one. We continue to provide them advice along with others in the industry, SOBO, TMX, et cetera, on pipeline opportunity in the — to the West Coast. But again, that’s just on an advisory perspective.

So I think there’s — I think there’s a fair number of things still to come. But April is what I would look at to see if there’s actually a solution, a competitive solution to the carbon issue for Canadian producers.

Robert Catellier: I agree with that.

Colin Gruending: Robert, sorry, I was just going to layer in. I think there’s a lot of kind of media headlines around the West Coast pipe being kind of one of the Ps and then pathways being a second P. But grossly undercovered is the third P, which is, I think Greg — getting production up to fill a West Coast pipe. And I think those are the signals that are dear to the equation that we should all be watching for.

Gregory Ebel: And again, Rob, the nice thing is I think in the meantime, while we wait, I think we’ve got great solutions for our customers in MLO1 and 2. And if they get this right, obviously, 3, and we know somewhere down the road, perhaps additional pipelines in other directions. But again, I think the insurance egress we’re offering there is an important one for our customers until the skies are a little clearer, if you will, on that P for production that Colin mentioned.

Robert Catellier: Okay. That’s helpful. I guess we’ll have to wait and see how it evolves. My second question was, I wondered if we could have a progress update on wood fiber and how costs are tracking there versus expectations.

Matthew Akman: Sure. Rob, it’s Matthew. No major updates there. We remain on track for late ’27 in service. We’ve made good progress on construction recently. We’re about 60% complete on the project. 12 of the 14 modules are now on site. So we just have a couple left there, put in a new flotel in December. So everything tracking to plan and no updates on cost or in service.

Operator: Your next question comes from the line of Manav Gupta from UBS.

Manav Gupta: Congrats on the dividend hike. Investors always appreciate it. My question here is there’s a lot of focus on Canadian heavy sour volume growth, but what is also growing out of Canada is light sweet crude, particularly if you look at some of the projections that CNQ is making. And one project which I find very interesting, which you kind of have been working on is trying to get like 250,000 barrels more to DAPL. I think you probably have to reverse the line that is going over there and then you probably work with it [ Ity ] to get more crude to DAPL. Can you talk a little bit about this particular project that gets more probably sweet crude from Canada into the U.S. refining system.

Colin Gruending: Sure, Manav. And good observation, right? A lot of talk on heavy and less on light. So MLO2 is kind of a 2 for that way. It deals with the light, right, as you’ve talked about the path and then heavy on the mainline. And you’re exactly right. That is the path we would move lights down the mainline and then reverse a cross-border pipeline that currently flows south to north to be north to south and connect it with Dakota Access Pipeline, which has some headroom and then that this Canadian crude would not displace Bakken producer headroom. So it fits nicely into that DAPL underutilized asset, of which we own a portion of and then moves that light crude down into Patoka and then back up to Chicago and to feed those PADD II refining markets and probably more markets than it does today. So there’s a few embedded win-wins here, Manav.

Manav Gupta: Perfect. My quick follow-up is and just — you talked a little bit about it, but generally, what we are seeing is a lot of these behind-the-meter solutions come up and pipes are being — laterals are being built, but we do believe not enough storage in terms of gas storage is being built, particularly around data — where the data centers are coming up. So can you talk a little bit about gas storage opportunities in key target markets around the data centers. So if you could talk a little bit about that and how Enbridge could benefit from it?

Matthew Akman: It’s Matthew. I think you’re on point there. If you look at how peaky some of the power prices have been in certain of the regions pretty much across the country. That’s just going to continue to get worse unless we have more storage, obviously, and pipeline capacity. So those are some of the big opportunities. I think the storage itself is going to kind of be where the geology is. And we’re really bullish on that, and that’s why we’re expanding. We’re going to be up to 120 Bcf of storage in both the Gulf Coast and in B.C. over the next 2 years. Those are great positions and further expansion potential, as I alluded to. We’re seeing storage rates that are very supportive of strong economics and returns. I think the contract duration is also extending, which is nice.

And also the customer base is further diversifying. And so that is coming right further and further into our wheelhouse in the way we like to do things at Enbridge, longer contracts, strong double-digit returns and low or no commodity exposure. So we got a good position where we are, and you’ll look forward to more expansions on those.

Gregory Ebel: I think Michele, you might want to add. Sometimes it’s forgotten, we have a nice unregulated storage position in our Gas Distribution business in the Great Lakes as well. And obviously, that’s an area where you see both industrial growth, data center growth as well, too.

Michele Harradence: Yes, that’s right. I mean we have about 300 Bcf of storage in the Great Lakes region just in Ontario, and we have another 50 or so. So I think it’s 290 of which we have about 110 unregulated at Dawn and 180 that’s regulated. Then we have another 60 Bcf in Ontario. And of course, we have Wexpro, which is an important asset in Utah, all of which is really helping on the affordability front to Matthew’s point about volatility, I mean, Dawn saw very stable prices in the last few weeks when we saw things escalating elsewhere. But in terms of expansion capability, we’re looking across all of the GDS systems for more storage. We think it’s incredibly important for our customers. And then on the unregulated side, we just keep chipping away.

We added a BCF last year. We’ve got 4 Bcf we’re adding to Dawn this year. We’ve got a number of projects in the pipeline. We see a lot of potential to keep adding to that and the same sort of dynamics that Matthew discussed about longer-term contracts, good contracts, exactly what we like.

Operator: Your next question comes from the line of Ben Pham from BMO.

Benjamin Pham: I had a couple of follow-up questions on the renewal power sleeve of your business. You mentioned the 1 gig you’re working on the 2 gig safe harbor. Can you add context on the total development portfolio that you have in gigawatts? And what are your plans in terms of do you want to replenish it or not going forward?

Allen Capps: Yes. Thanks, Ben. So right now, I mean, the total gross generation that we have when you include the growth is about 7.4 gigawatts. That’s on a gross basis. I say that just because we do have some JVs that would dilute that a bit. But I think on a net basis, we’re like 4.3 gigs if you include all of the growth that we have in the portfolio right now in the existing and what we have actually in service and up and running. But the point I was trying to make is that in a time where tax credits are a bit challenged with some of the — with what’s facing us probably in July 4, we’ve got a portfolio of diversified projects that meet well over 2 gigs of opportunity that we think all of which are — have a lot of veracity and we think have a good shot at going into FID and ultimately into service, and that will keep us full for the next 3 years.

Gregory Ebel: Ben, if your question is around would we pick up additional assets. I mean, I guess we could look, but that’s not something we’re looking at right now. We’ve got a nice backlog of stuff, as Allen said. And then post ’28, we’ll see where we are on whether power prices move up and/or there’s change in policy and stuff, but a good setup right now for the coming years and through the decade.

Benjamin Pham: Yes. I just want to clarify some of those numbers. So that 4.3 gigawatts, that’s in service at this operation?

Allen Capps: Yes. If you take what’s in service, that’s our net basis. So basically, some of our stuff is in JV. So on a net basis, our interest. If you take what’s in service today plus what we’ve FID-ed and what we have under construction, you get to 4.3 gigs.

Benjamin Pham: Okay. And then — so then beyond that, you don’t have lease agreements and land that — some of these renewable companies have 10, 20, 30 gigawatts of sites that they’re developing. I was more curious about that number.

Allen Capps: Yes. Ours is more like about a little over 2. And if you think about it, when you think about the $1 billion to $1.5 billion of capital that we’re targeting to spend on an annual basis, that’s right in the sweet spot for us, like I said, over the next 3 or 4 years.

Benjamin Pham: I got you. Maybe there’s a left question on this on Ontario. You’ve — in the past, you’ve all electric transmission, you got out, looks like the promise may be looking at competitive bidding projects. Is that something Enbridge will be potentially interested in going back in?

Allen Capps: Well, you know we have the Gichi-gami project that we’re looking at right now and which is a wind project. And we’re bidding into the — we bid into the ISO. They’re waiting to hear back whether or not our bid was successful. That’s something we’re focused on in Ontario. Again, I’ll just say this, one of the things on the Canadian side is it’s a very competitive market and that sometimes people are willing to take returns that are lower than what we would. So we always have to focus on capital allocation. Our business unit competes against the other business units here on a healthy basis. So we have to make sure that we have good return projects. And sometimes it can be a bit challenged, but we think the Gichi-gami project could be a real good one if it does land.

Gregory Ebel: But specific to electric transmission, I don’t see us getting back into — we were only there for a brief period of time, worked out okay on the sale. But electric transmission is a very different risk profile, and I would not hunt currently in Enbridge’s opportunities.

Benjamin Pham: Okay. Got you. I was specifically referring to that subsea transmission project that the government is looking at.

Operator: And we have reached the end of our question-and-answer session. I will now turn the call back over to Marlon Samuel for closing remarks.

Marlon Samuel: Great. Thank you, and we appreciate your ongoing interest in Enbridge. As always, our Investor Relations team is available following the call for any additional questions that you may have. Once again, thank you, and have a great day.

Operator: This concludes today’s conference call. Thank you for your participation. You may now disconnect.