Earnings Call Transcript - ENB Q4 2025

Marlon Samuel, Vice President of Investor Relations and Insurance

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. 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, President and CEO

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, EVP and Chief Financial Officer

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 at 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 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, President and CEO

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

Your first question comes from the line of Sam Burwell from Jefferies.

George Burwell, Analyst

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, President and CEO

Yes, I think it's fair. I think the 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, EVP and Chief Financial Officer

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 to understand that we've got a fair amount of capacity here as we move forward.

Gregory Ebel, President and CEO

As I mentioned, we are confident in the 5% growth. There are various dynamics to consider. Compared to a year ago, the situation in the Western Canadian Sedimentary Basin appears favorable, with increased production and a more positive outlook from the government regarding Canada's competitiveness. This growth could present opportunities, and we are already witnessing this with MLO1 and MLO2, along with the potential for an MLO3. Regarding gas transmission, you'll hear about more FIDs in the coming year and extending into 2027. In gas distribution, we previously estimated an 8% rate base growth through the end of the decade after acquiring the gas distribution assets in the U.S., but it now looks like it will be closer to 10%. Additionally, we might exceed our power CapEx forecast mentioned on the last Investor Day, as customer demand for electrons increases. It doesn’t matter what type of electron they’re seeking; they just need electrons. We have already announced deals with Meta and MAG 7 players. Despite the scale of our operations, which totals $20 billion and a few hundred billion dollars in enterprise value, I believe we are on the right path and are optimistic about achieving more than the 5%.

George Burwell, Analyst

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, President and CEO

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, Liquid Pipelines

Yes, I believe you're correct. Sam, your framework is generally accurate. There may eventually be a larger West Coast solution, but for now, in this uncertain environment, I think our traditional approach of gradually expanding the mainline is effective. It aligns well with customers' needs on both the supply and demand sides as we seek certainty. Additionally, MLO2 will address the egress bottleneck we expect to experience by 2028, which is beneficial since it will be operational by then. So, I think you've got the right idea. Just keep an eye on the Canadian supply growth and the Gantt chart related to dispositions that we are updating.

Operator, Operator

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

Robert Hope, Analyst

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, President and CEO

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 the 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, Analyst

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, President and CEO

I believe it's a combination of factors. An important aspect for MLO3 is the need for a policy change in Canada that aligns with the Prime Minister's goals of boosting oil and gas production. These changes are being discussed quite openly, and that has to be the priority: production growth comes first, followed by pipeline development. I see that as a significant component. Colin, while we don’t have many specifics on Line 3 or MLO3 yet, would you like to share any insights on that?

Colin Gruending, Liquid Pipelines

Yes. Let's refer to it as MLO3, although MLO126 would also be appropriate since we've made numerous expansions to the mainline. We've simplified the numbering for clarity for our current participants. We are working on various options for MLO3 that cater to different industry needs, such as small, medium, and large. Regarding Venezuela, it’s still early, and the long-term outlook is uncertain. We'll need to monitor how quickly Venezuela can increase its production and assess how much of that added supply will reach the U.S. Gulf Coast. Most of it will be transported on VLCCs, and some may remain at sea to supply global refineries as it has in the past, potentially at a higher price for Venezuela. That is one of their goals. Additionally, it's important to note that there is likely another 400,000 barrels per day of heavy refining capacity available on the U.S. Gulf Coast beyond current usage. We should also consider the inevitability of Canada re-exporting crude oil from the U.S. Gulf Coast on a significant scale over time. The U.S. Gulf Coast remains the premier heavy refining market, and Canadian crude is a fundamental part of its operations. Therefore, I believe it will continue to function effectively overall.

Gregory Ebel, President and CEO

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, Operator

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

Theresa Chen, Analyst

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, President and CEO

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, Liquid Pipelines

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, Analyst

Understood. In light of the many questions regarding the geopolitical situation, which is still developing, and considering your commercialization efforts on MLO2 and MLO3, how should we evaluate the discussions around the marginal all-in rates as the projects progress towards completion in the late decade and beyond? Additionally, how do these economics stack up against the current committed and spot rates on mainline as we prepare for the upcoming system renegotiation and the return on equity outlook over the next few years?

Colin Gruending, Liquid Pipelines

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

Theresa Chen, Analyst

I'm asking how the discussion about tariffs on the expansions under development has changed since we've seen incremental rerouting or expected rerouting of Venezuelan barrels to the Gulf Coast. I assume there will be no impact from MLO2 because that is directed towards the PADD II market, meaning those refineries will not experience a decline in Venezuelan crude. However, for MLO3, if that pathway is oriented towards the Gulf Coast, how does that alter your economic perspective?

Colin Gruending, Liquid Pipelines

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, President and CEO

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, Operator

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

Aaron MacNeil, Analyst

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, Liquid Pipelines

Aaron, this demand has been present for 30 or 40 years throughout my career. We've consistently observed a strong demand for the mainline for various reasons, which I won't detail here. However, in the past couple of years, Canadian supply appears to have exceeded expectations. Our customers are implementing several optimizations upstream that yield high returns and quick cycles, allowing them to maximize output from their existing equipment. This development may have surprised consensus views, perhaps even us to some extent, but we've maintained strong belief in our thesis all along. This conviction is part of the reason we structured the mainline tolling deal as we did, allowing us to serve customers better and benefit from that upside. Looking ahead, as Greg mentioned, we hope the political situation in Canada will evolve positively, especially given the competitive threat from Venezuela, leading to even more opportunities.

Gregory Ebel, President and CEO

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, Analyst

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, President and CEO

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

Matthew Akman, Gas Transmission

Yes, thanks for the question. The key takeaway is that there is a growing consensus that the main challenges in energy today for everyday people—affordability and reliability—will be addressed by natural gas. We foresee a substantial opportunity ahead with a significant undersupply of pipeline capacity nationwide. This is just the starting point. Additionally, there is an increasing demand for power and data centers, as well as trends in exports aiming to double from the Gulf Coast. We are well-prepared for all these aspects. Earlier, we discussed expansions from the Permian, including the Eiger upsize and the Bay Runner extension. As Greg mentioned, you can also expect us to enhance our growth strategies in Gas Transmission Management soon. Recently, we completed an open season for Vector into Wisconsin, where there is a growing demand for power and natural gas for utilities. Texas LNG1 has made excellent progress in terms of offtake and financing, which you might have seen. Furthermore, there is a strong demand for storage in the Gulf Coast, with additional expansion opportunities on the horizon. These are just a few developments we expect to discuss shortly as we add to our growth plans. In the long term, across all our regions from the Northeast to the Southeast and other areas in between, we see abundant opportunities. We have a minor expansion in Algonquin, but there is a significant appetite for larger projects there. Permitting is becoming more favorable, and it's becoming clear that relying on oil for 40% of power generation during cold snaps or when gas prices skyrocket doesn't make sense—we offer a solution to that. In the Southeast, population and economic growth is driving our expansion, particularly with our pipelines like SESH and Sabal Trail. Overall, we are witnessing excellent opportunities nationwide, and you can anticipate growth from us in the near term and for many years to come.

Gregory Ebel, President and CEO

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, Operator

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

Maurice Choy, Analyst

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, EVP and Chief Financial Officer

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, President and CEO

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, Analyst

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, President and CEO

I haven’t heard anything definitive on that. However, there have definitely been many indications. What we're really looking for is concrete actions. The Memorandum of Understanding between the Government of Alberta and the Government of Canada was quite encouraging, but that was several months ago, and circumstances keep evolving. It’s not just about the indications and speeches; it’s more about the actions and outcomes that our customers and investors seek, as well as what we want. I remain very optimistic about the indications and the Prime Minister’s remarks regarding the expansion of oil and natural gas. Regarding backstopping, that's an interesting aspect. There are instances, like loan guarantees, that occur for specific stakeholders, but I don’t foresee that applying to private sector players. For some of the larger projects, a stable policy commitment and possibly some backstopping until completion might be necessary. We see similar situations in the Northeast; our utility customers there, due to the policy fluctuations we've experienced, won't risk financing project development. We're ready to take on the construction risks once we receive the green light, but we won't gamble on projects being halted before they become operational or even before reaching Final Investment Decision, especially since some of these initiatives require hundreds of millions of dollars even before obtaining regulatory approval.

Maurice Choy, Analyst

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, President and CEO

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, a 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, Operator

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

Elias Jossen, Analyst

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, President and CEO

Yes, I believe we are quite confident in identifying opportunities in power at GTM and GDS. GTM can sometimes be underestimated, but projects like Line 31 in Louisiana, AGT, SESH, and the TVA project offer significant potential in the power sector. GDS, as mentioned earlier, presents about 5 Bcf of gas infrastructure potential to meet growing power demand, alongside over 1 gigawatt of power infrastructure established for Duke. We have undertaken similar initiatives in Ohio and at the Novva Data Center in Utah. Additionally, we see substantial potential in renewables; our customers are more focused on the energy itself rather than its source. We have secured approximately 3 gigawatts in recent years, and our acquisition of Tri Global in 2022 has bolstered our capacity for large renewable projects. Our clients, including Meta, Amazon, and Google, are exceptional partners for these projects. We are not looking to enter the gas IPP business extensively, although there may be unique opportunities. However, we prefer the long-term contracts available with renewables, often spanning 15 to 20 years, compared to the shorter contracts typical in the IPP sector. This aligns well with our risk profile and approach. Allen is present and may want to add further insights.

Allen Capps, Head of Corporate Strategy and President of Power

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, Analyst

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, Gas Transmission

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, President and CEO

Eli and Matthew, I believe you would agree that we are observing some interesting contracting trends. Typically, storage contracts last around 2 to 5 years, but we are also seeing significant portions of our storage being contracted for longer terms, in some cases for up to a decade. This aligns well with our risk and return profiles. Additionally, Aitken Creek is often overlooked; it is the only major gas storage option in British Columbia at a time when the Gulf Coast is experiencing exciting developments due to incoming LNG projects. Thank you for your question.

Operator, Operator

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

Robert Catellier, Analyst

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, President and CEO

Yes, Rob, thank you for your question. There are two important milestones approaching that we have been monitoring for some time. One is in April, when the Government of Alberta and Canada are expected to reach a solution regarding the industrial carbon charge and its stringency. This is crucial for our customers and producers to determine if Canada remains competitive enough for them to maintain their growth. We are providing them with advice, alongside others in the industry, about pipeline opportunities to the West Coast. However, this is purely in an advisory capacity. There are several developments on the horizon, but I would focus on April to see if we can attain a competitive solution to the carbon issue for Canadian producers.

Colin Gruending, Liquid Pipelines

Robert, I was going to add that there are many media headlines focusing on the West Coast pipeline as one key aspect and pathways as another. However, the third important factor, which is often overlooked, is increasing production to supply the West Coast pipeline. These are critical signals that we should all pay attention to.

Gregory Ebel, President and CEO

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.

Matthew Akman, Gas Transmission

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, Operator

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

Manav Gupta, Analyst

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 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, Liquid Pipelines

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, Analyst

Perfect. My quick follow-up is regarding the behind-the-meter solutions we are seeing. While laterals are being constructed, it appears that not enough gas storage facilities are being developed, especially in areas where data centers are emerging. Could you elaborate on the gas storage opportunities in key markets around the data centers and how Enbridge might benefit from them?

Matthew Akman, Gas Transmission

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, President and CEO

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, Gas Distribution and Storage

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, Operator

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

Benjamin Pham, Analyst

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, Head of Corporate Strategy and President of Power

Yes, thanks, Ben. Currently, our total gross generation, including growth, stands at about 7.4 gigawatts. This figure is gross because we have some joint ventures that slightly dilute it. However, on a net basis, we have around 4.3 gigawatts when accounting for all the growth in our existing portfolio and what is currently operational. The key point is that despite the challenges surrounding tax credits, particularly with what we might face by July 4, we have a diversified portfolio of projects that presents over 2 gigawatts of opportunity. We believe these projects are robust and have a strong chance of progressing to final investment decision and ultimately becoming operational, ensuring our capacity remains full for the next three years.

Gregory Ebel, President and CEO

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, Analyst

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

Allen Capps, Head of Corporate Strategy and President of Power

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, Analyst

Okay. I'm curious about how many gigawatts of sites some of these renewable companies are developing, as they have 10, 20, or even 30 gigawatts, and I noticed you don’t have lease agreements and land like that.

Allen Capps, Head of Corporate Strategy and President of Power

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, Analyst

I understand. Perhaps there's a remaining question about Ontario. In the past, you focused on electric transmission, and now it seems like you might be considering competitive bidding projects. Is Enbridge likely to be interested in re-entering that area?

Allen Capps, Head of Corporate Strategy and President of Power

We are currently considering the Gichi-gami project, which is a wind project. We have submitted a bid to the ISO and are awaiting their response regarding its success. This is a key focus for us in Ontario. It's important to note that the Canadian market is quite competitive, and sometimes other companies are willing to accept lower returns than we are. Therefore, we must concentrate on capital allocation. Our business unit competes healthily with other units here, so we need to ensure we pursue projects that offer good returns. While this can be challenging, we believe the Gichi-gami project has strong potential if we are awarded the bid.

Gregory Ebel, President and CEO

Regarding electric transmission, I don't anticipate us returning to that sector. We were involved for a brief period and it worked out fine with the sale. However, electric transmission carries a distinctly different risk profile, and I currently do not see any opportunities for Enbridge in that area.

Operator, 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, Vice President of Investor Relations and Insurance

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, Operator

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