Enbridge Inc. Aktie

Good morning, and welcome to the Enbridge Inc. First Quarter 2026 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. [Operator Instructions].

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'll turn it over to Greg Ebel.

Thanks very much, Marlon, and good morning, everyone. We appreciate you joining us once again today. The first quarter was a strong start to the year, reflecting solid financial performance and continued execution across our businesses. We reaffirmed our '26 guidance and medium-term outlook and continue to operate in line with our 4.5 to 5x debt-to-EBITDA target.

From an operational standpoint, utilization was high across all businesses with record Q1 mainline volumes and numerous peak delivery days on our U.S. gas transmission and distribution systems. In April, we completed our seventh expansion of tank storage at Ingleside and have now increased storage capacity to approximately 20 million barrels, and we brought the 120,000 barrel per day Gray Oak expansion into service.

On the execution and growth front, we announced open seasons on the Flanagan South and Southern Access extension pipelines, which support mainline optimization Phase 2. We also completed a successful open season on the Spearhead pipeline. During the quarter, we sanctioned a number of exciting projects in gas transmission, including expansions to our Tres Palacios, natural gas storage and our 60% owned Vector pipeline. We also announced an expansion of unregulated natural gas storage at Enbridge Gas Ontario and the 300-megawatt Cone Power Project.

We'll dive in a little deeper into these projects in the business update slides. But first, let's take a look at how Enbridge continues to connect supply with rising energy demand. The importance of energy security has become even more evident since the start of the conflict with Iran and Enbridge is well positioned to deliver North America's abundant energy resources, both domestically and globally. LNG exports remain a critical component of energy security.

North American liquefaction capacity is expected to require over 30 Bcf per day of natural gas by 2030 and Enbridge is poised to support the global demand through serving 100% of the operating LNG facilities along the U.S. Gulf Coast. We continue to deepen our integration with LNG markets as well via storage expansions of Aitken Creek, Tres Palacios, Egan and Moss Bluff, new Permian gas egress projects and the advancement of Woodfibre LNG.

Natural gas demand in North America is expected to increase by 28 Bcf per day by 2030. And we have already begun capturing that growth through sanctioned projects with more new projects to come in the quarters ahead. Tennessee Ridgeline connecting to a power generation facility converting from coal to gas. Algonquin Gas Transmission expansion, providing additional capacity to the underserved U.S. Northeast and the Vector expansion serving utilities in the Midwest are just a few examples of infrastructure we're currently building to support local demand.

On the liquids side, we are in the midst of advancing 430,000 barrels per day of incremental mainline and express capacity by 2028, adding timely and efficient egress for our WCSB customers. Our Permian super system remains a cornerstone of the export story and it continues to grow. Projects like the Gray Oak expansion and the new storage tanks at Ingleside support the export facility, which delivers roughly 25% of all U.S. crude exports today.

We expect all this to lead to North America moving more than 5 million barrels per day of crude on an ongoing basis to key international markets, including Europe, Asia and Latin America. We all know energy markets have been disrupted since the conflict in Iran and Enbridge will be ready to play its part in providing reliable, secure and affordable energy to customers domestically and overseas.

Now let's take a look at how Enbridge's business model is designed to succeed regardless of the macro environment. Despite market volatility since the start of 2026, Enbridge continues to deliver consistent and growing shareholder returns. Our cash flows remain of the highest quality and predictability, diversified across more than 200 asset streams and are largely protected by regulated and long-term take-or-pay contractual frameworks.

We have unmatched market access serving more than 75% of North America refineries, moving roughly 20% of all natural gas consumed in North America and directly serving over 7 million gas utility customers. Our diversified platform allows us to provide end-to-end energy solutions across liquids, natural gas transmission, gas distribution and power. Long-standing relationships with customers and our continuously growing partnership with Meta remain a key competitive advantage and underpin our accretive project backlog.

We continue to grow through our $40 billion capital backlog which supports visible growth through the end of the decade and we can finance that growth using our $10 billion to $11 billion of equity self-funded annual investment capacity and the strong balance sheet.

Now let's dive into the business unit update, starting with Liquids Pipelines. Our Liquids Pipelines business continued to deliver strong performance as we advance efficient egress and storage expansions to meet rising demand. On the mainline, we achieved record first quarter volumes of 3.2 million barrels per day, reflecting strong utilization and the critical role of the system.

We're advancing mainline optimization Phase 2 or MLO2, which is expected to add 250,000 barrels per day of incremental WCSB egress capacity by the end of 2028. In support of MLO2, we launched a binding open season for 200,000 barrels per day of incremental FSP capacity and 50,000 barrels per day of incremental capacity on the Southern Access extension pipeline. Early construction activities, including clearing of the right-of-way have now begun on Line 5 relocation project in Wisconsin, supporting the continued flow of vital energy supply in the region.

We also completed a successful open season on the Spearhead pipeline, recontracting volumes into the next decade. And in April, we received a number of presidential permits for our liquids pipelines. These permits provide operational flexibility for day-to-day operations as well as future expansions. Along the Gulf Coast, our Ingleside storage expansion has entered service, increasing site capacity to approximately 20 million barrels. And finally, the Gray Oak expansion is now complete and the pipe operating capacity is now over 1 million barrels per day, further strengthening our export connectivity.

So now let's take a look into our gas transmission business. We continue to benefit from diversified demand drivers creating attractive and highly visible capital opportunities across our gas transmission footprint. In the U.S., we are executing well across our system to support rising demand from power generation, local gas utilities, LNG facilities and new data centers. And we are advancing over $10 billion of near-term growth opportunities with several projects reaching FID this quarter, with more to come this year and next.

Those projects include the Tres Palacios expansion, adding 25 Bcf of natural gas storage along the Gulf Coast. The project CapEx is expected to be $400 million and enter service in stages from 2028 to 2030. We have also sanctioned an expansion of the Vector pipeline for just over $100 million, adding 400 million cubic feet per day of westbound capacity to serve growing local utility demand and targeted for in-service in 2028.

We continue to evaluate additional expansion opportunities on Vector and recently closed a nonbinding open season in April for another 300 to 500 Mcf per day on that pipeline. This open season was highly successful with customer interest exceeding the offered capacity. Our East Tennessee pipeline reached a settlement in principle on the rate case filed last year, and we expect to file the agreement with the FERC in the second quarter.

In Canada, expansions to our gas transmission network are also advancing. Recently, we received all of our required approvals on the $4 billion Sunrise expansion, with construction expected to begin by early summer. At Woodfibre LNG, the delivery of the liquefaction module this quarter represents another important execution milestone. Altogether, we have approximately $10 billion of projects under construction in British Columbia to support both domestic energy needs and Canada's growing LNG export market.

Let's move over to gas distribution. In Ontario, we sanctioned approximately 8 Bcf of unregulated natural gas storage expansion at the Dawn Hub with an in-service date of 2029. This project strengthens the critical energy platform for Ontario and surrounding regions. At Enbridge Gas Ohio, we filed a new rate case on December 31, 2025 with rates expected to go into service effective in 2027. And as a reminder, Utah and North Carolina saw new rates go into effect on January 1, '26 and November 1, '25, respectively.

Our gas distribution and storage business continues to deliver steady regulated growth through disciplined rate base investment. The T15 project is progressing, supporting the Roxboro power plants conversion from coal to gas and expected to have a phased and in-service from 2027 to 2028. At the Moriah Energy Center, the $600 million U.S. LNG storage facility will strengthen system resiliency by adding 2 Bcf capacity in 2027. Collectively, we expect our utilities to grow rate base by 5% annually through 2029. And while Ontario's growth is slowing, our diversity of assets allows us to redirect capital to the U.S., which very likely will exceed their 8% growth CAGR through 2029.

Now I'll move on to the Renewables segment. Our renewable power business continues to progress with disciplined focus on high-quality projects anchored by blue-chip customers and the long-term contracted cash flows. At Sequoia we will have 815 megawatts of generation capacity, about half of which is already in service, and the remaining capacity is expected to come online later this year.

We are also happy to announce we are expanding our partnership with Meta once again by sanctioning Cone, an onshore wind project in Texas, which we expect to invest USD 700 million and have the project enter service by the end of 2027. Our partnership with Meta has grown to over 1 gigawatt of power generation between Clearfork, Easter and now Cone and we expect the partnership to grow further. Beyond our sanction projects, we have approximately 1.5 gigawatts of additional safe harbor renewable projects, providing meaningful capital optionality. With all that, I'll pass it on to Pat to go over our financial performance through the start of the year.

Thank you, Greg, and thanks to everyone for joining the call today. I'm happy to say we're off to another strong start in 2026. Compared to the first quarter of 2025, adjusted EBITDA remained consistent, DCF per share is up $0.03 and EPS is down about 5%. In liquids, as expected, the absence of a litigation settlement lower contributions from our market access pipelines and lower Line 9 tolls resulted in a decrease compared to Q1 2025.

In Gas Transmission, favorable contracting on our U.S. gas transmission assets and strong storage results drove the year-over-year increase in EBITDA. Gas Distribution increased year-over-year after the recent rate cases in Utah and North Carolina took effect, as Greg mentioned earlier, and from rate escalators in Ontario. In Renewables, results were lower compared to last year due to the absence of investment tax credits relating to the Fox Squirrel solar project, partially offset by strong international wind resources in the first quarter of 2026.

A $0.07 decrease in the average CAD to U.S. FX rates year-over-year impacted all 4 business units, resulting in lower EBITDA in 2026. This was, however, partially offset in eliminations and other, due to our realized hedge rate being higher and closer to the actual FX rate we saw in the quarter.

Cash distributions in excess of equity earnings was higher in 2026 due to the absence of a legal settlement recognized in Q1 2025 earnings but primarily received in cash in subsequent periods. Higher depreciation from assets placed into service and higher income taxes from the absence of investment tax credits in '26 drove the decrease in EPS.

I'm pleased to reaffirm the 2026 guidance that we showed last December. Our resilient business model supports strong and predictable performance across all market cycles and conditions, something that is evident in our results, given the volatile periods we've seen recently. We're on track to achieve the midpoint of our guidance ranges for both EBITDA and DCF per share and are also reaffirming our post-2026 growth outlook, a 5% average annual growth rate for EBITDA, DCF per share and EPS. As a reminder, Q1 and Q4 reflect our strongest quarters as a result of higher utility demand and higher volumes in our liquids pipelines and gas transmission systems during winter months.

Moving on to our capital allocation priorities. Our approach remains unchanged in 2026, supported by continued equity self-funding and the stability of our regulated and predictable cash flows. Returning capital through dividends remains core to our value proposition. We returned $38 billion to shareholders over the past 5 years and expect to return $40 billion to $45 billion over the next 5 years. Our $40 billion backlog extends through 2033, providing strong long-term growth visibility, as we prioritize accretive brownfield opportunities. And with that, I'll pass it back to Greg to close out the presentation.

Thanks, Pat. Enbridge remains a first choice investment opportunity with a value proposition designed to deliver superior shareholder returns across all markets, geopolitical and commodity cycles. At the core of this is stability reflected in our low-risk utility-like business model and a fundamentally diverse asset base.

Our strength comes from predictable, resilient cash flows that support a strong balance sheet, disciplined capital allocation and ongoing strategic investments. Consistency is a defining feature of our story, highlighted by 31 consecutive years of annual dividend increases as well as 20 years of achieving financial guidance.

Looking ahead, we expect approximately 5% annual average growth through the end of the decade, driven by our growing secured capital program and we maintain the ability to deploy capital across our 4 franchises, allowing us to respond quickly to the most compelling opportunities in front of us. As the long-term total return performance on this slide illustrates, our business model has continued to perform through events ranging from financial crisis to global pandemics and geopolitical shocks.

Enbridge's scale, diversification and stable business model positions us well to continue delivering durable growth and long-term value to our shareholders, making us that first choice investment opportunity. We are in a world with an amazing growth macro for energy infrastructure, the best growth opportunities I have seen in 10 to 15 years. This could be a real upside for investors. Should we see the EBITDA multiples of that period reemerge as the macro fundamentals seem to suggest they should. With that, I'd like to thank you all for listening in, and we'll now open the line for questions.

[Operator Instructions]. Your first question comes from the line of Aaron MacNeil from TD Cowen.

Last quarter, you had a slide in your deck that highlighted $10 billion to $20 billion of near-term growth opportunities. One of the more interesting items on that slide was export optionality at Ingleside in light of the continued closure of the Strait of Hormuz and the market's renewed focus on energy security and non-Middle East supply. So you noted the new storage in your remarks and announced the acquisition of the Flint Hills docks not too long ago.

I guess my question is, are you seeing a measurable increase in inbound inquiries for incremental export capacity at Ingleside and would you expect export growth to pull through additional pipeline debottlenecking upstream? Or is the sequencing the other way around?

Aaron, it's Colin and obviously, a timely question. And I think -- well, the short answer is yes, I can elaborate a little further. And we didn't see a lot of that come through in the Q1 period, right in March because of the trade cycle and things, but it showed up strongly in April, May and in June here, and everyone understands the dynamic there. We do expect a lot more business there. I think on a capital-efficient basis, right?

So as you mentioned, we purchased the neighboring docks a couple of years ago. We've got permitting headroom there. We just finished a 2.5 million storage expansion at Ingleside. So there should be some operating leverage here. So hopefully, it's capital efficient. But yes, on the dock and on the pipe as well over time, I mean there's an implicit comment there around the outlook for the Permian Basin, which we continue to believe is a winner, and the majors are there and I think you're seeing a lot of discipline at the outset here, a couple of producers adding some rigs. But I think the consensus view would be that the price of oil globally, it probably has a higher floor and we'll likely see rigs added through the fall budget cycle and into '27 as well.

Aaron, it's Greg. I just -- I would just add that everything Colin says bang on and exports now kind of pushing 6 million barrels just with the conflict. I think it will be really interesting to see is even when the conflict is solved, how much more reliance, and I think there will be on the U.S. Gulf Coast and Canada for that matter as well. And that should position well for those with the docks closest to Bluewater, which would be us.

But let's not lose track of how important it also is for the refining complexes, as people look for more secure product, you've seen refining capacity creep up. Obviously, that's important for inland pipelines as well as exports. And then as Colin said, let's -- I don't know exactly what the price will be, but if that oil was going to be 65% to 70%, I don't think you should be surprised that the new base is 75% to 80%, which is helpful for production, too. So it's actually lining up to be a super favorable environment for oil infrastructure in North America, both domestically and export wise.

Great. You mentioned the 1.5 gigawatts of safe harbor renewables projects in your prepared remarks. The wedge of renewables projects coming into service in 2027 is pretty significant. So I guess like -- do you think you could see another meaningful contribution in 2028? And when would you need to see announcements by in order to sort of lock that in?

Well, then, I'll let Allen to that. But one of the great things you pointed out is just have relatively quick cycle these are even though when we announced today, gets into '27, and that [indiscernible] in half is important. But Allen, do you want to speak to that?

Sure. Thanks, Aaron. So really have on the backlog, we could probably see some of those actually coming in, in probably '28, '29 time frame. That said these things tend to come in kind of chunky. I think you've seen quite a bit in the last few quarters where we've seen -- where we've had pretty much an announcement every quarter for quite some time. And you'll see probably a few more in the coming 2 to 3 quarters.

That may tail off for a little bit, and then you'll start to see more of them come back in as we're taking advantage of those safe harbor opportunities. And a lot of those opportunities that we have, not only are the safe harbor they have the permits, too. A lot of folks are concerned about the federal permits on land, and a lot of them have those federal permits as well. So a real opportunity for us.

I think you'll continue to see is the demand for renewables is really good right now. And I think that's evidenced by all the projects that we have to come in. So as you continue to see that demand be robust on the renewable side, I think we've taken advantage of it.

Yes, and it's not just renewables, it's power, right? So I think what you're seeing with the meta deals and the stuff that Allen talked about, and we've said this before, but I think it's bearing out, no one's talking about the color of electrons. The #1 thing that prevents AI from progressing further isn't GPU architecture, it's really access to energy, and that's the first time that's happened. So yes, game on for power, but that's why it's nice to have gas infrastructure and renewable infrastructure so we can serve those Mag 7 clients.

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

I have 2 comments -- or 2 questions on the crude oil business. First, how are you thinking about the competitive positioning of MLO 2? But I guess, more importantly, MLO 3 versus some of the competing options, which, I would say, are bubbling up to the surface being Prairie Connector as well as a larger expansion of the Trans Mountain system?

Sure, Rob, a few points of color around that. Listen, I think you've followed us for a while, and I realize our mainline path is resilient and advantaged, so has defensive and offensive strength. It's demonstrated time and time again. We're growing it. As a reminder, Southern Illinois Connector and MLO1 are in execution and trending well. And we're commercializing MLO2, as we've discussed.

MLO2 is well engineered, relatively advanced on scope, capital costs well understood. We're actively engaged with a number of customers. And in contrast to alternatives, I think a reminder that MLO2 has -- was always intended to be an inside the fence expansion, permit light, executable, no new pipe per se, which is novel using existing pipelines and in service quickly, which is important. And another point, which is often lost with modest take-or-pay efficiency requirements right, given that the mainline is generally walk-up.

So that's trending well. I think we've seen other competitors respond to the quite favorable outlook in the Canadian basin, which is not surprising. I won't comment exactly on each of the competitors. I think they're well covered. But if we do see shippers term contract on any of these. And I think I would view it as a positive sign and a vote of confidence in the basin and the outlook, which should float all oil infra. So that's a very -- as Greg was saying, I think it's a very positive macro. And certainly, the mainline expansion program will get its share. You mentioned MLO3.

We're developing that still and with 7 pipelines in the right-of-way and now with amended U.S. presidential permits modernized and harmonized with respect to product type and flexibility around capacity limits. We've got a plethora of flexibility here to tailor and design whatever is needed at the right time. And we've got a number of versions, I would say, of MLO3, if you want to think about it that way. So that's how we see it play out here. It's -- I zoom back out and just observe that it's a very favorable macro. And we're all trying to serve customers who are monetizing a world-class resource.

Appreciate that color. Maybe then moving over to Line 5. It looks like there's been a number of updates there. So can you maybe add a little bit more color on some of the legal challenges on the tunnel as well as the construction in Wisconsin?

Thanks, Rob. Yes, I'll try to bring it in my answer. This question tends to get long. But maybe, yes, we haven't talked about Line 5 in a while, which is kind of a good thing. But I'll give you a quick update. As you know, big picture, Line 5 seems to be pretty critical energy infra for Canada and the U.S., Great Lakes region, contributing to this all-important energy security. The line is closely scrutinized, including by PHMSA, U.S. pipeline safety regulator, and it will continue to operate safely for the foreseeable future.

And I think courts have increasingly recognized this U.S. federal jurisdiction in recent court findings. But as a reminder, nonetheless, we are permitting and pursuing relocating 2 sections of Line 5 at the request of local governments and tribes at industry's expense. In Wisconsin, we're advancing a 41-mile relocation to discontinue operation across the Bad River reservation. And in Michigan, we're moving the pipe from the lake bed to the tunnel. Timeline-wise, we expect to complete these in late '26 and the early '30s, respectively. In Wisconsin, we have state and federal permits. We have easements on the 41-mile relocation route and have been completing preconstruction activities, think tree clearing and prepping the right of way way. It's May now.

So spring road bans have recently ended, and we'll advance construction here through the summer and late fall. With the permits now contested and well known and in hand, we're now better able to accurately estimate the Wisconsin project cost, which is now approaching USD 900 million. Now this is more than you typically expect for this 41-mile distance, but consider that about a third of that $900 million value is related to 6 years of considerable permitting, legal and tribal engagement and has been incurred. So we've got about $600 million left. And you should expect to see this project added to our secured project listing in the second quarter, Rob.

Quickly on Michigan, we don't have a refreshed estimate CapEx-wise for the tunnel at this time as we continue to await state and federal permits and conditions. And maybe the last point I'll just make here is a reminder that the investments in Line 5, infra, Wisconsin, Michigan, regular stuff are all covered as eligible rate base within our commercial arrangements and will be borne by our shippers through tolls over time. So I don't know if that catches you up, hopefully, Rob.

Your next question comes from the line of Spiro Dounis from Citi.

I want to start with opportunistic gains here and the results for the first quarter. Strong start to the year, but you're reaffirming the guidance. So I was curious if you could just walk us through how much of that 1Q performance exceeded internal expectations. And understanding that your assets are built for stability, it did seem like you were able to benefit from some of the volatility and weather out there. So to the extent that's accurate, how do you think about your ability to keep capturing some of that upside and volatility for the rest of the year?

Yes, I'll let Pat go at this. But I would say a reminder, and we rarely change our number in the first quarter no matter how good it may be, largely because we've got a strong first quarter and a strong fourth quarter. So -- and as you point out, with a highly contracted, very small commodity exposure. That's why we've structured the company that way. But Pat, do you want to speak a little bit to.

Yes. I mean there's probably 2 or 3 areas that we benefit from weather, as you're noting on the edges of the business model. First being in Ontario, where we've got weather impacts is about net year-over-year, only about $10 million because we had a colder Q1 last year as well. So there's about $10 million there. Aitken Creek, historically that we're currently expanding has the ability to take advantage, and there's probably $0.01 or so of overperformance there. And then a little bit on things like interruptible service on our gas pipes. So all in all, you can think of it as being a couple of pennies in the quarter.

And that just speaks to the business model that we have and the fact that we have like no commodity exposure. So I think more so than the weather, Colin's talked about the implication of a tailwind for things like Ingleside and Gray Oak, we'll monitor that in the second quarter and see how that goes and how long that lasts for and adjust as we go. But right now, we're still pretty comfortable with the range that we've given you.

That's great. Maybe switching gears to the Permian. Greg, you sound understandably pretty constructive on the basin. I think your reference was to the crude side, but of course, a lot of gas coming out of the ground with it. You're obviously pretty active there on the Permian gas egress side. You think over 10 Bcf a day of new pipelines coming will be enough to satisfy it, but already getting a lot of indication that, that might not be enough. So just curious how you're thinking about the need for more egress and Enbridge's potential involvement in more expansions there.

Yes. And let's not forget our position in Whitewater. And I think as you may see some information on that, I would agree with your bullishness in that regard. We are, too. We seem to fill up every pipeline industry-wide the minute they open up the valves in the Permian. So I think there's more opportunities there, and we're pursuing those. And Matthew, maybe you want to speak to some of that.

Yes, sure. A couple of areas of opportunity there. And as Greg mentioned and a reminder, our interest in the Whitewater assets, which is sort of our direct play on the pipes there, a couple of pipelines coming into service this year there. Still, we have Bayrunner coming into service later this year in Blackcomb. And then a whole bunch of other stuff going forward, we have a position, as you know, in Eiger. I think the other piece, though, for us that we see, and you saw this in our announcements is storage. And with all the activity coming out of the Permian a lot of that gas is obviously going to be going offshore and a lot of additional storage required just for additional demand and some of that for the LNG crowd. So we've got great exposure to that, expanding all of our storage assets in the Gulf. As you know, now we have almost 50 Bcf of expansion underway down there. So that's another way that we can profitably with low capital, high returns, play that theme.

The other nice thing about the storage is we always talk about our gas business growing at being able to build at 6 to 8x, but that project we talked with you and announced today is actually a little bit below that. So when you can get into the 5s when you're building brownfield storage and given some of the demands Matthew spoke to, those are super attractive for us.

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

Just to pick up on one of the comments you made, Greg, in your prepared remarks. You mentioned that this is the best growth -- set of growth opportunities you've seen in the last 10 to 15 years. Can you elaborate a little bit more on that, but also speak to how the returns compare today versus in the past? And what kind of risks that industry players like Enbridge are experiencing today versus the past?

Yes, absolutely. So I'm thinking about that period, the 2012, '16 period, which was a super positive element, and you saw dramatically higher EBITDA multiples. And where I was going is, as you see the increased need for energy, energy security, whether it's global security issues or technology, AI and power growth, which you're well aware of is a multiple of what we saw. I haven't seen that opportunity from an investment perspective fully be realized by the market, you know, say, look, you got the tech companies, you got the Caterpillars of the world, but it's not being fully realized, I don't think by investors yet on the midstream side. And you're seeing very solid returns. I just talked to things like storage, our LNG projects and renewables. You're seeing low mid-teen type returns for us that are super attractive. And then even on the utility side, where you don't see the same type of returns, just seeing really quite phenomenal growth in rate base, which I just think a couple of years ago, nobody saw.

So it's not just -- and we've been speaking a lot about the oil business. So it's not just one business. It's all of these businesses playing off the theme of everything from tech which drives power, LNG, which is about security, oil, which is the refining complex is an industrial side as well as on the export side, all the pieces that Enbridge has seem to have a really great macro backdrop. So where I was going is it seems to me that investors haven't yet realized how beneficial and long run that will be. I mean we're talking about through 2030 very comfortably in terms of the growth folks see, which would be longer than what we saw in that 2012 to '16 period. So that's where I was going with that. And I think it soon will be recognized.

That's great. And maybe my one follow-up to that is, as you looking backwards now, as you look forward beyond this 2030 horizon. As you think about how customer demand requests are changing, are your 4 core franchises sufficient? Or are there incremental value chain additions that you think is appropriate?

Yes, it's a good question. We're always looking at that, either whether it's adjacencies or actually going further back. So again, you look at the super system that Colin and his team have built back into the Permian, obviously, and then on the export side, same on the gas side that we've done in that neck of the woods. Obviously, our extension on the distribution side. And the real element I see is there's no longer the discussion of again, what color your molecule is or electron is, it's how quickly can you get me electrons and molecules or barrels. And I think if you look at our project list, we're very focused on that, the quick cycle stuff at the distribution company. Actually quite quick cycle relative to some other forms of power on the renewable side of things, which is super attractive.

And again, the footprint we see on the gas distribution -- on the gas transmission side and the liquid side allows us to get there quicker than most people. And so I think the greenfield risk that we saw in prior periods is less relevant to Enbridge today given our footprint that's already there. So that's a really game on for growth from an Enbridge perspective.

So I appreciate the question. I like us talking about more growth as opposed to less growth and the removal from terminal value and we're talking about are we really valuing these companies given what's happening above and other parts of the economy that should be there. So as you can tell, we're pretty excited about it and we'll continue to bring projects forward. I know, Matthew, in the next couple of quarters. And it seems like every business unit, we're able to bring on some stuff each quarter to build that backlog. And then it builds EBITDA, which builds capacity, which allows us to continue to use both the internally generated equity and the balance sheet to grow.

Definitely value to the incumbency. I agree with you.

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

I see it's more expansions on the gas storage side here. I just wanted to get a feeling, I guess, for how big the opportunity set is there. We haven't necessarily had a lot of storage development in recent years and the gas market has grown. Just wanted to see your thoughts on that. And then at the same time, I guess, as an extension, further interest in LNG assets.

Jeremy, it's Matthew. Yes, we're very excited about our gas storage assets and our expansion program. Just looking at the fundamentals over the last 10 years, just the ratio of storage to production and demand in the U.S. has been cut in half. And actually, that kind of understates the gap between supply and demand because things are getting a lot more peaky, which requires more storage. So we need to catch up on that and the value of storage is on the rise. So as we've announced now with this new Tres Palacios expansion, we've got almost 50 Bcf under construction in the Gulf Coast coming on over the next, call it, 5 years or so. And then also, just as a reminder, up in Canada, we've got 40 Bcf under construction at Aitken Creek. So that is a great pipeline of growth for us.

In addition to that, just capital expansion, we do see as we roll contracts, higher storage rates. And so when you combine that just given the fundamental trends I was talking about with the expansion, we're definitely seeing double-digit type growth on those. We've got this great program in front of us, over USD 1 billion of expansion in storage now, if you add it all up, which is great. We'll build that out. There's probably a little bit more we could do around the margins on that. But those are probably the big ones for now. And we like the organic type growth. Others have been we noticed acquiring stuff. We think our returns -- I mean, building stuff at book value is definitely a huge advantage for us relative to those going out and paying multiples of that in the market. So like our position, great pipeline, and we're very excited about this program.

Jeremy, you also mentioned the LNG opportunities. So I -- yes, we're open to that. We like our model, though, of doing it in such a way that is lower risk and more toll-based, if you will. But we see those opportunities, and we'll look at that. I think that's some of the adjacencies. But we don't want to take on a bunch of commodity exposure. That's not our style from that perspective. But as Matthew says, even if we don't find those, the -- given our position we currently serve 100% of the Gulf Coast LNG, obviously, involved with that in BC and billions of dollars being spent there, both on our -- on behalf of our customers on our pipelines and storage. And so yes, we'll look at those opportunities as well. That sure doesn't look like it's moving away. And that's another example of some of the difficulties in the Middle East, meaning North American -- North America, whether it's the Gulf Coast or it's the West Coast of Canada is a choice place for consumers to be able to get a hold of LNG without taking on the risks that I think have become much more illustrated [indiscernible] there. So yes, we'll look at those 2.

Got it. That's helpful. And then I just want to shift gears a little bit here. And as far as the power markets and as far as, I guess, with the ISOs and regulation there, we've seen, I guess, some proposed changes and it seems like changes overall. I'm just wondering if that has impacted, I guess, the nature of your conversations with new gas-fired generation or just any thoughts you could share there and where you see the greatest near-term opportunity as you talk about this $10 billion of near-term capital opportunities.

Jeremy, it's Matthew again. Yes. So I think you're on to an important point. I mean there's 2 kind of categories or maybe 3 things going on here. One is -- and this is really kind of a very current and present thing, which is just regulated utilities that have embedded power generation for utility load with pent-up demand, and we're seeing a lot of that across our entire system for power.

Then there's the data center stuff, which is playing out. We have great conversations there on the power side for potential extensions. And I know Michele has a lot of that in her business, too. And I think maybe the thing that's more directly on point to what you're talking about is can we start signing up some of these merchant power plants based on what's in the past been kind of perverse disincentives, frankly, for them to sign up for long-haul gas pipeline capacity and whether that could change based on some rules.

I think there's some good ideas floating around on that piece. It's early days, but certainly, there's going to be more potential for that. And a lot of these merchant guys are going to end up direct drive into data centers. And so as they sign up for longer-term contracts on the offtake, we think there's great potential for them to then go upstream on the gas pipeline side, and we're having those conversations. So I think you're on to an important theme that's definitely going to be driving growth across our business.

Yes, it seems like a multiyear capacity market could shake things up there.

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

I wondered if you could elaborate on the comments in the presentation about favorable contracting in gas transmission. Does this relate to rates, term or something else entirely? What end markets are really driving this? I'm thinking in terms of LNG, power, et cetera, and which geographies are most important to that trend?

On the contracting side, I'm not exactly sure which part you're referring to. But look, I mean, if you look at on the storage side to start with, right, what used to always be short-term contracts, we're seeing, and I think we've talked about this before, half the capacity at Aiken, for example, is 10 years, very long-term contracts similar to that for the new Tres Palacios 25Bs we talked about today, which I think just speaks to nobody wants to be caught out without actually having access to the product.

So I think it's just a general comment, Rob, with respect to whether it's storage, whether it's pipelines and also our risk appetite, too. We're not going to build pipelines with 5-year contracts and get a little shaky at 10-year contracts to be quite honest, as well, storage is different. It's always been shorter. And you see the same kind of thing happening in Colin's business as well as we've extended some of the contracts and the market-facing pipes out into 2030s, which is not something that I think you could have done a few years ago. So I think it's less about regulatory, more about on the customer side, not wanting to be caught short in this opportunistically rich environment. And obviously, the Enbridge traditional perspective on how much risk we're willing to take on.

Okay. Just for a point of clarification, I was referring to the gas transmission comment on Page 11. I'll move on to my other question, which has to do with your rate case strategy, particularly in Ohio. So obviously, you filed for a rate case there. And I wonder how you could describe how your regulatory strategy in Ohio has evolved since that last rate case outcome.

Sure, Robert. It's Michele here. And yes, that last rate case was filed late in 2023 by Dominion. And really, what we're doing here is the fact is that we filed a new rate case in December, and the fact is there have been some material changes that just simply needed to be reflected since things were in place back in late 2023. And based on the timing, we -- what we're doing is we're seeking to recover our revenues that are sufficient, of course, to pay for our current operating expenses. Importantly, to service our debt, that's one of the biggest things that has shifted is the interest rates that were applicable back in '23 versus now.

And then it's any investments and deferrals from the 2 big rider programs that you'd be familiar with we have in Ohio, the CEP or the capital expenditure program and the pipeline integrity program. So those will get wrapped in to the end of June. They're already being recovered on because of the short-cycle nature of them and the monthly riders, but we sweep all that in. So it's in the discovery stage now with the status report is expected in July, and we expect to enter into meaningful settlement negotiations, then, with the rates going into place in the first quarter of 2027. But we are really working hard to keep this one tight as simply an update on a lot of the numbers that have changed materially that we had to update and ensure that we're recovering on.

Robert, I'm sorry, I was not following what you were looking to. So I see what you were talking about. That's vis-a-vis the tailwinds that we see for the rest of the year. So we're seeing settlements on things like East Tennessee that are favorable. As you know, we've seen the same on Texas Eastern in the past. So that's what we were referring to that weren't there at the start of the year. And I mentioned that in my spoken comments, how that's being filed with the FERC.

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

You've reaffirmed the 5% growth rate beyond 2026. I'm wondering when do you plan to update the market on guidance specifically beyond '26. I'm also curious what do you think is the right duration time frame for guidance for a North American pipeline company?

Yes. Well, just for clarity, what we said was 5% growth '26 plus. So through '26 through the end of the decade, we feel very confident with that. So I think when we put that out was March of -- 14 months ago, March of 2025. And we remain confident in that, and I'm glad to hear the Street looking to move up those numbers to that 5% type growth rate. We haven't -- we look beyond 2030. We haven't set out any numbers beyond 2030. But I expect either in the fall or early spring, we'll end up having another Investor Day and update you at that time.

Just as a reminder, and I think sometimes it gets lost, just since that Investor Day, which again was about 14 months ago, we have added $17 billion to our sanctioned backlog. So if we continue to see that type of stuff and all that is growth through now through 2030 and even a bit into 2031 and '32, if you look at some of the activity. So yes, it's not just for '26, it's for '26 plus right through 2030. And look, in this environment, giving you guidance out to 3 years, I think, would be pretty good, but actually giving you something right through the end of the decade, I would think is very helpful to investors as well as analysts to come up with their views on the company.

Okay. Got it. I always thought it was more of a post 2026 guidance, but I wasn't -- I was a bit confused on the endpoint of that. So that's all the way through 2030 then. That's good. And then the $50 billion of unsanctioned opportunity, I know you mentioned very similar numbers in the past on that. And you've inserted the $10 billion to $20 billion last quarter, next 2 years, can you bridge that for us? I'm assuming that's always included in that $50 billion, but is there a mix then of some early-stage projects in there as well?

Yes. And we're always adding to, right? So you're right. I mean you make a good point. In March of '25, it was about $50 billion. We've sanctioned $17 billion, which just tells you how the hopper in that time has easily filled in there, right? And everything from higher rate base growth on most of our businesses to power opportunities, that backlog just gets bigger. And I think, again, as attitudes change around energy security and the power of North America for exports, I'll be surprised actually if that opportunity set doesn't even get bigger. So that's where we're drawing those sanctioned projects from, but it's filling up at least at the same rate by which we're sanctioning projects.

Yes. So maybe just to add to that, then like $50 billion is the environment that we're in, the opportunities that we have, as Greg said, $50 billion a year ago, it's still $50 billion, even though we've secured a bunch of projects. The $10 billion to $20 billion that we talked about kind of over the next 24 months, I guess, now 22 months is really what we plan to FID in that period of time to give you a sense of what you should see on a ratable basis from us from an FID perspective, pulling from that $50 billion opportunity set, if that helps to clarify it.

Your next question comes from the line of Patrick Kenny from National Bank.

Just back on the robust outlook for crude exports out of the Gulf Coast. I guess the longer this Middle East conflict lasts and the longer prices at the pump remain elevated in the U.S., the higher the risk of political intervention related to banning or at least capping export levels. So I was just wondering if you might be taking any steps over the near term to protect your franchise operationally? And also, if you could remind us of any commercial protections you might have financially within your contracts at Ingleside?

Yes. I'll let Colin speak to that. I would be very clear that at least twice the Secretary of Energy has said that is not something they're looking at even as we've seen this run-up. So I think that's a really important perspective. And then, of course, we've just successfully contracted on Gray Oak, which is an important protection as well, obviously. But Colin, do you want to speak further to that?

I don't think there's a lot to add. I agree with everything you're saying. We've -- we're in regular contact with the administration. We're well attuned to the alternatives in play here and support and subscribe to the notion that constraining global exports will hurt -- not help the situation here as a global commodity. So as Greg mentioned, we've got very robust contract provisions around the export facilities.

It's a really interesting dynamic, right, because the United States government, I think, has not been shy about projecting power off the Gulf Coast by being able to export crude. And remember, much of that Permian crude is what gets exported because the U.S. refineries like the heavier products, which is what we provide out of Canada, so importantly. And you're even starting to see some more exports of Canadian crude modestly off the Gulf Coast as well. So there's no doubt there's a consumer voter element here, but I just don't see this administration changing their view of being able to use energy frankly, as a geopolitical tool despite the current conflict over and above military power.

Okay. That's great. I appreciate your comments on that. And then just on the balance sheet, I guess, with debt to EBITDA sitting at the top end of your target range. Just wanted to confirm if you're still expecting to remain within the range through 2026? Or is there now potential given the sanctioning of more growth CapEx that you've outlined to see leverage perhaps hop over 5x temporarily? And if so, the timing of when you might expect to come back down to, say, closer to the midpoint of that 4.5 to 5x range?

Thanks, Pat. I think it's fair to say that we're still comfortable with the 4.5% to 5% range. We're at the top this quarter for a couple of reasons. One is FX plays a little bit of a role in that and that it was $1.37 on the quarter, but then popped right at the end of the quarter there to be $1.40. So that moved it a little bit. We also expect it to be a little bit higher at the front end this year given that the vast majority of our projects come in, in the back end of the year, the big projects, things like Tennessee Ridgeline, T-North, Aspen, some of the Sequoia Easter type projects. So I think we're still pretty comfortable with it.

For when is it going to come down closer to the midpoint, I think I said a couple of quarters ago that we'll probably be in that upper half for the next couple of years just because we've got this large build in front of us. But of course, the capital -- near the end of '27 here and then a pretty large capital coming in '28 that should really help to bring those ratios back to kind of that middle point of it. So we're still feeling very comfortable and the low-risk business model helps with that. All this growth we've been talking about lines up perfectly with that risk return that we have discipline that we've had as an organization. I like the fact that when we're talking about these capital opportunities, they are long-term contracts with gas transmission assets, long-term contracts of liquids pipelines. So not having to step outside of our risk/reward view to continue to grow the organization. So feeling very comfortable about where we are from a financing perspective.

And your final question comes from the line of Manav Gupta from UBS.

I have 2 quick questions. First, can you talk about your growing partnership with Meta? Not many midstream companies are out there with 1 gigawatts of capacity with Meta. So if you could talk a little bit about that? And second, there were some news articles floating yesterday that [ Carney ] is looking to make easier for projects to proceed in Canada. Cenovus and CNQ have already talked about some of these things on their earnings calls. And basically, what they're saying is you can't hold back Canada in the current environment where the world needs crude and oil. And I was wondering if you have any views on any policy changes that could expedite projects in Canada to speed up the development of oil and gas projects over there.

Yes. Well, on the Google or on the Meta piece, I think you'll continue to see that relationship grow. Allen, do you want to speak to that? And then I'll come back on the oil front.

Yes. So thanks for the question, Manav. So on Meta, they've come out and said that they want to be net zero by 2030 and that 100% of our operations powered by renewables. So it really opens the door for folks with long-term relationships with them to do more with them. And so we do expect to see more with Meta. We really are excited about the relationship. And I'll just say that I think we've developed a really good trust relationship with them, and that's the foundation for future opportunities. So we feel really good there. And hopefully, we'll see more opportunities going forward.

Yes. And on the project front, look, I think there's been a lot of positive words in Canada and some concrete actions that have been taken. We got a very quick turnaround from the federal government on the final approval for Sunrise, which is critical to LNG. Obviously, there's a major project office there and projects in the national interest. So I think that's great news. And I'm hoping and expecting and taking the government at its word that we're even going to find ways to shrink down some of those time frames even for projects like Sunrise. But that being said, I'm perfectly aligned with our customers on the other issues that they raise.

Yes, Canada has an obligation, I think, to serve the world and has the ability to serve the world if it wants to be an energy superpower. And I think they're focused on the right P. We often focus on the pipeline P. But what has to come first is the production P, the permitting P and then you get the pipelines. So I think they're pointing out and making sure that all the policymakers are aware that without production growth, the infrastructure is kind of irrelevant.

And that concludes our question-and-answer session. I will now turn the call back over to Marlon Samuel for closing remarks.

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.

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

Good afternoon, ladies and gentlemen. My name is David Taniguchi, Vice President, Legal and Corporate Secretary of Enbridge. Thank you for joining us at our Annual General Meeting today. Real-time captioning for the hearing impaired is also available today. There will be 3 parts to today's meeting. First, the formal business portion will address the matters to be voted on today and will be conducted by our Chair, Mr. Steve Williams. Next, after the formal business of the meeting, Greg Ebel, our President and CEO, will deliver his remarks to our shareholders. Finally, we will have a general question-and-answer session.

Before we begin the formal business portion of the meeting, I will provide some comments on voting and questions at today's meeting. As a reminder, only registered shareholders and duly appointed proxy holders can vote or ask questions during the meeting through the virtual webcast voting platform.

In order to vote during the meeting, you must log into the webcast with your control number or username and your password, which is enbridge2026, all in lowercase. Once voting has opened, the voting tab will appear at the left or bottom of the webcast page and the voting choices will be displayed. A confirmation message will appear when your vote has been received.

The polls are now open. Voting can be completed at any time from now until the end of the formal business portion of the meeting. Thank you to those of you who have already voted. If you do not wish to change your vote, you do not need to vote again during the meeting. For those who have not yet voted, we encourage you to vote now.

Questions can be submitted throughout the meeting. If your question relates to a specific motion, you must ask your question during the formal business portion of the meeting. Please start your question by identifying the specific motion or item of business so that we can address your question at the appropriate time.

[Operator Instructions]

If you have any questions that do not identify a specific motion or item of business, we will respond to those questions during the general question-and-answer session following the formal business portion of the meeting and the CEO's remarks. If you have a question that is personal in nature, we will follow up with you individually after the meeting.

Shareholders were also provided the opportunity to submit questions in advance of the meeting. If you -- if we have a number of questions that are the same or very similar, we may group those questions together to avoid repetition. We will endeavor to answer all questions submitted through the platform. However, please note that due to time constraints, we may not be able to address all questions today.

Questions received during the meeting, together with the company's responses, will be posted to Enbridge's website following the meeting. If you have any questions, we encourage you to submit them now.

Finally, we would like to remind you that our answers to your questions and our CEO's remarks may contain forward-looking information. By its nature, this information involves a variety of assumptions and expectations about future outcomes, which are subject to the risks and uncertainties discussed more fully in our public disclosure filings. We may also refer to non-GAAP and other financial measures.

In the event of technical difficulties or other significant issues that may disrupt the meeting, the chair of the meeting may adjourn, recess or expedite the meeting or take such other action that the chair determines is appropriate in light of the circumstances.

With that, I now welcome Steve Williams, Chair of the Enbridge Board of Directors, to call the meeting to order.

Thank you, David. Good afternoon, ladies and gentlemen. My name is Steve Williams, and I'm Chair of the Enbridge Board. It's my pleasure to welcome you to Enbridge's 2026 Annual Meeting of Shareholders. As this is my first Annual General Meeting as Chair, I want to express my appreciation for the trust placed in me over the past year. I remain committed to strong governance, strategic oversight and delivering long-term value for our shareholders.

We are gathered today by technology from locations across North America where indigenous peoples have been and continue to be stewards of the land. I'd like to acknowledge and thank the people whose footsteps have marked these territories for centuries.

Before I call the meeting to order, I would like to call upon Jody Whitney to deliver a land acknowledgment message.

Hello. My name is Jody Whitney, and I'm from the Tsuut’ina Nation. Respectfully, we acknowledge that we are hosting this meeting today in Treaty 7 territory home to the Blackfoot Confederacy, which includes the Siksika, Kainai and Piikani nations, the Stoney-Nakoda nations of Bearspaw, Chiniki and Goodstoney, the Tsuut'ina Nation and Metis Nation of Alberta.

It is also important to acknowledge that our assets traverse many other treaty and traditional indigenous lands across North America, which is known to indigenous people as Turtle Island.

Thank you, Jody. I will now call the meeting to order. As Chair of the Enbridge Board and in accordance with our bylaws, I will act as Chair of today's meeting. David, Vice President, Legal and Corporate Secretary, will act as Secretary. Greg, our President and Chief Executive Officer, is also present at the meeting today. Our external auditors are also available to answer questions as appropriate.

In order to ensure that the business of today's meeting proceeds smoothly, David, who is a shareholder and duly appointed proxy holder, will move and the second the proposals relating to the items of business identified in the notice of meeting. As in past years, we have a general question-and-answer session after the formal business of the meeting is completed.

As previously noted, during the formal business portion of the meeting, we will also pause to address questions that are specific to the motions being presented. If you are a registered shareholder or duly appointed proxy holder with a question that you'd like to address during the formal business portion of the meeting, I ask that you submit your question now.

This afternoon, we will deal with the items of business outlined in the notice of meeting and management information circular. Shareholders will first be asked to consider the minutes of the last meeting of shareholders held on May 7, 2025. They will then attend to the regular business of receiving the annual financial statements together with the report of Enbridge's auditors. Shareholders will then be asked to vote on the election of directors and the appointment of the auditors for the next year as well as authorize the directors to fix the auditor's remuneration.

As has been the case in prior years, shareholders will then be asked to cast a nonbinding advisory vote to accept the corporation's approach to executive compensation, commonly referred to as say-on-pay. And then finally, this year, as we've done every 3 years, shareholders will be asked to ratify, confirm and approve the corporation's shareholders' rights plan.

All 12 incumbent directors are standing for reelection today. The number of directors to be elected today has been nominated by the Board to be 12. Mr. Stephen Bandola, a representative of the corporation's register and transfer agent, Computer (sic) [ Computershare ] Trust Company of Canada, is in attendance today, and I appoint him to act as scrutineer for the meeting. I will now ask David to confirm that proper notice of the meeting was given and that a quorum is present for the transaction of business.

Thank you, Steve. The notice of meeting and notice of availability of meeting materials were mailed on March 20, 2026, to shareholders of record at the close of business on March 9, 2026. Proof of mailing to registered shareholders will be filed with the records of this meeting. The scrutineer's report shows that 5,230 proxies have been received, representing a total of 1,424,254,891 shares, which is 65.26% of the shares outstanding as of March 9, 2026. Based on the scrutineer's report, I confirm that a quorum is present for the transaction of business at this meeting.

Thank you. I declare this meeting to be properly constituted for the transaction of business. David, may I please have a motion to approve the Minutes of the Annual Meeting of Shareholders held on May 7, 2025.

I move and second that the minutes of the Annual Meeting of Shareholders held on May 7, 2025, as now submitted to this meeting be taken as read and approved.

Thank you. Can you please advise if any questions specific to this motion were submitted?

No questions specific to this motion have been submitted.

Okay. Thank you. Unless we receive any objections otherwise, we will accept the minutes as approved.

The next item of business is to place before the shareholders the audited financial statements and auditor's report for the year ended December 31, 2025. The financial statements and auditor's report for the year ended December 31, 2025, are contained in the corporation's annual report. The financial statements have been approved by the Board of Directors and are available on the corporation's website.

The corporation's auditors, PwC, Alodie Brew of PwC will be available during the general question-and-answer session following Greg's remarks to answer any of your questions regarding the auditor's report.

The next item on the agenda is the election of directors for the next year. 12 directors are to be elected at this meeting. David, may I have a nomination for the election of 12 directors to serve on the Enbridge Board of Directors for the upcoming year.

Steve, I'm pleased to nominate each of the following individuals: M. M. (Mike) Ashar, Gaurdie E. Banister, Susan M. Cunningham, Gregory L. Ebel, Jason B. Few, Douglas L. Foshee, Theresa B. Y. Jang, Teresa S. Madden, Manjit Minhas, Stephen S. Poloz, S. Jane Rowe and Steven W. Williams for election as directors of the corporation to hold office until the close of the next Annual Meeting of Shareholders or until their respective successors have been duly elected.

Thank you. As no other nominations for director were received in accordance with the corporation's advanced notice bylaw, I hereby declare the nominations closed. I will now entertain a motion respecting the election of directors.

Steve, I move and second that the aforementioned 12 nominees be elected directors of the corporation to hold office until the close of the next Annual Meeting of Shareholders or until their respective successors have been elected.

Thank you. Can you please advise if any questions specific to this motion were submitted?

No questions specific to this motion have been submitted.

Thank you. We will now proceed with the vote. Please record your vote now, remembering that you've already voted in advance and do not wish to change your vote, no further action is required.

The next item of the business is the appointment of the corporation's auditors. PricewaterhouseCoopers have served as Enbridge's auditors for the past 32 years. The Board of Directors on advice from the Audit, Finance and Risk Committee of the Board recommends their appointment. David, may I have a motion?

I move and second that PricewaterhouseCoopers LLP be appointed auditors of the corporation to hold office until the close of the next Annual Meeting of Shareholders at such remuneration as shall be fixed by the Board of Directors.

Thank you. Can you please advise if any questions specific to this motion were submitted?

Steve, no questions specific to this motion have been submitted.

Thank you. We will now proceed with the vote. Please record your vote now, remembering that you've already voted in advance and do not wish to change your vote, no further action is required.

Thank you. We will now proceed with the vote. Please record your vote now remembering that if you've already voted in advance and do not wish to change your vote, no further action is required.

The next item of business today is a nonbinding advisory vote on the corporation's approach to executive compensation, commonly known as say-on-pay. Although this vote is optional or nonbinding, it gives shareholders an opportunity to provide important input to the Board of Directors. David, may I have a motion?

I move and second that the resolution to accept the corporation's approach to executive compensation, the text of which is set forth on Page 34 of the Management Information Circular be and is hereby approved.

Thank you. Can you please advise if any questions specific to this motion were submitted?

No questions specific to this motion have been submitted.

Thank you. We will now proceed with the vote. Please record your vote now, remembering that if you've already voted in advance and do not wish to change your vote, no further action is required.

The next business is a resolution to ratify, confirm and approve the shareholders' rights plan, which encourages the fair treatment of shareholders if there is a takeover bid for control of Enbridge. The shareholders' rights plan resolution must be passed for the shareholder rights plan to continue. Otherwise, it will terminate. Our shareholders' rights plan is confirmed by shareholders every 3 years, most recently in 2023. There are no substantive changes to the plan for 2026. The Board of Directors has determined that the continuation of the shareholders' rights plan as described in the Management Information Circular is in the best interest of the corporation and its shareholders and recommends that shareholders vote for this resolution. David, may I have a motion?

I move and second that the resolution to ratify, confirm and approve the shareholder rights plan, the text of which is set forth on Pages 34 and 35 of the Management Information Circular for this meeting be and is hereby approved.

Thank you. Can you please advise if any questions specific to this motion were submitted?

No questions specific to this motion have been submitted.

Okay. Thank you. We will now proceed with the vote. Please record your vote now, remembering that if you've already voted in advance and do not wish to change your vote, no further action is required.

[Voting]

Okay. The polls are now closed. Thank you again to all our shareholders who voted in advance of our meeting today. We will now pause for a moment for the scrutineer to tabulate the preliminary results of voting and provide those results to us. David, do you have the preliminary results of the voting?

Yes, Steve. I have received confirmation from the scrutineer that each of the 12 directors has been elected by at least 95.03% of the votes cast for the election of directors.

The motion to appoint PricewaterhouseCoopers as the corporation's auditors and have the directors fix their remuneration has been approved by at least 91.89% of the votes cast on that resolution.

The advisory vote on the corporation's approach to executive compensation has been approved by at least 95.58% of the votes cast on that resolution.

And finally, the motion to ratify, confirm and approve the shareholder rights plan has been approved by at least 95.82% of the votes cast on that resolution.

Thank you, David. Strong support there for the motions. I declare each of the resolutions considered at today's meeting in respect to those matters as carried. The exact number of votes cast in respect of each matter will be filled on EDGAR and SEDAR and made available on our website.

As all matters of business have been addressed, I now declare the meeting closed. I now call upon Greg, the corporation's President and Chief Executive Officer, to deliver the remarks and conduct the general question-and-answer session.

Good afternoon. My name is Greg Ebel, and it's my pleasure to lead Enbridge as your President and CEO. Today, I'm happy to speak with you and share what our company has delivered and our focus for the future. Enbridge is in a position of strength. We're resilient and well prepared for what's happening in the energy industry right now and for what's on the horizon. 2025 was a year of consequential change, including public policies, the speed and scale of energy demand and the focused attention on energy abundancy and affordability.

And that pace of change shows no sign of slowing down. Geopolitical uncertainty is creating challenges for billions of people around the world. At the center of this is the need for a secure supply of energy to meet growing demand. I'll share more shortly about how we're seeing the global energy environment, but let me first touch on our performance on your behalf in 2025. This past year, we demonstrated solid operational performance, a visible growth outlook and record financial results that continue to position us as the first choice energy provider in North America and beyond.

The changing geopolitical dynamics and increasing energy demand I mentioned validate Enbridge's all-of-the-above approach. This is reflected in our diversified asset footprint of gas, oil and renewable power to meet rising energy needs. Our financial discipline fuels our success and builds on our track record. We exceeded the midpoint of our '25 guidance for both EBITDA and distributable cash flow per share, marking the 20th consecutive year of meeting or exceeding our financial guidance.

In December, we sanctioned our 31st consecutive annual dividend increase with a 3% increase for 2026. We have maintained our leverage within our targeted debt-to-EBITDA range of 4.5 to 5x, preserving our strong investment-grade credit profile while growing our investment capacity. This financial discipline supports strategic investments that continue to strengthen Enbridge's leadership in connecting supply to key markets, sanctioning $14 billion of new projects and placing $5 billion of assets into service across our portfolio last year.

In our Gas Transmission and Midstream business, we capitalized on rising LNG, data center, power and industrial demand, announcing $4 billion in newly secured projects. The business also completed another indigenous partnership this time with 38 First Nations in BC for a 12.5% stake in our West Coast system valued at $715 million. This new partnership continues our strategy of partnering with indigenous communities and enabling them to benefit from the investment and play a greater role in shaping Canada's energy future.

On the liquids side, our mainline delivered record annual throughput. We sanctioned approximately $5 billion of new liquids pipelines to meet growing demand, deliver strong returns and support first choice customer service. Our gas utility business is the largest in North America, serving over 7 million customers in growing gas-friendly jurisdictions. This business is well positioned to benefit from increasing gas-fired power and data center growth with over 50 potential projects along with more opportunities to meet rising residential and commercial gas demand.

And in renewable power, we completed the Orange Grove solar facility and sanctioned Clear Fork Solar. These projects are backed by long-term agreements with blue-chip customers, including Meta and AT&T. Our low-risk business model and diversified mix of future projects enable continued leadership in supporting the energy needs of data centers, residential and industrial customers, but it's more than meeting demand.

Central to everything we do is our #1 value of safety for our people, our assets and the communities where we operate. In 2025, we made good progress integrating Enbridge safety standards in our new U.S. gas utilities and managing high energy hazards to protect people from very serious incidents. We performed well in process safety and safely transporting energy on our systems, and we believe that continuous improvement in safety practices supports effective execution of our growth plans across the business.

Building on the momentum from 2025, we are advancing a $39 billion project portfolio through the end of the decade. This represents investments across natural gas, liquids and renewable power to meet growing energy demand. It's a big lift, and the team is ready to do this safely, responsibly, on time and on budget.

Now let me share my perspectives on what's happening in our industry today and the outlook for our company. As we look ahead, one reality is clear. Geopolitics are shaping the energy system in real time. Conflict and instability in the Middle East and other parts of the world have created challenges for people globally. And we're seeing one of the most significant supply disruptions our industry has faced in decades.

At the recent CERAWeek conference in Houston, one speaker summed it up bluntly. When the world's most important oil corridor is compromised, the ripple effects hit everyone. That observation captures why reliability has become more than a competitive advantage. It's a necessity for economies, communities and customers. In this moment, North American reliability is a strength for global energy security.

We have the resources and the capability to meet domestic needs and in assisting the needs of global markets. Quite simply, we have the energy resources to keep moving forward and to help our partners do the same. The world needs more energy, more reliably delivered, more affordable and with continued progress on emissions reduction. From my perspective, I see 3 themes defining the path forward.

First, North American energy security and reliability are a real advantage. When global choke points are under pressure, customers and governments look to suppliers they can count on. North America's oil and natural gas supplies are abundant and dependable if we continue to invest and collaborate on infrastructure to deliver the energy where it needs to go, which leads to the second theme, building infrastructure has never been more relevant.

We need modern, efficient infrastructure to move energy to where it's needed, including global markets. Delivering this infrastructure depends on regulatory clarity and reform that supports investment and maintains strong safeguards. There have been positive moves on permitting reform in both Canada and the U.S. in the past year. That's very encouraging. But don't get me wrong, more needs to be done. We will continue to advocate for practical policies that support investment and competitiveness while maintaining our focus on safety and environmental sustainability.

And the lastly, energy demand is growing, and it's coming from everywhere. AI and data centers, electrification and developing economies are all pushing energy demand higher. The world needs more energy, and we believe that means more oil, more natural gas, more renewables, more of everything. This is not the moment to restrict where responsibly produced energy comes from. All electrons and molecules are needed to meet the demand.

So let me sum up with what this means for Enbridge. Our enviable asset position and all of the above energy approach has always been a strength, and that's even more true at this moment. Our liquid super system brings much needed Canadian oil to key refining markets in North America and for export from our Ingleside facility in Corpus Christi. Our gas system connects the most prolific basins in North America to the largest demand centers and LNG export markets.

Our gas utility business is well placed in natural gas positive regions. One in every 12 natural gas utility customers in Canada and the United States is an Enbridge customer. And our renewable power business will have the capacity to generate over 7 gigawatts of power. I'm optimistic about what we can achieve, and I'm confident in Enbridge's ability to deliver the energy people need today and for decades to come.

Our customers need energy that's safe, sustainable, reliable and affordable, and Enbridge is focused on executing across that spectrum. So as we look forward, our focus is clear: keep our system safe and reliable, keep building and operating the infrastructure our customers need and want, keep earning the trust of communities and keep delivering the solid returns you expect as shareholders.

Thank you for your continued support and trust in us. I'd also like to thank our Board of Directors for their guidance and ongoing oversight. Finally, thank you to the more than 16,000 Enbridge team members. Every day, you show up with focused commitment to safely provide energy to millions of people who need it. I'm proud of this team, and it's an honor to work alongside you. As we say at Enbridge, tomorrow is on, and we're all ready for it.

Thank you very much, Greg. We will now proceed with the general question-and-answer session. Mr. Marlon Samuel, Enbridge's Vice President, Investor Relations and Insurance, will read out the questions that have been submitted for Greg to respond to and we'll note any request to ask questions verbally. We remind you that verbal questions should be limited to 1 minute in length. Marlon, do we have any questions?

Yes, David. We have received a question on the phone from Jason Alsop.

President Alsop, please proceed with your question.

Thank you. Hello. My name is Gaagwiis Jason Alsop, and I'm the President of the Haida Nation and Vice President of the Coastal First Nations Great Bear Initiative. And I've been formally appointed to address the AGM by a shareholder with over $1.6 billion in assets under management.

Our proposed crude oil pipeline through Northwestern Canada is making headlines. However, the federal government has repeatedly stated that no project would proceed without the support of affected First Nations or the province in which it's proposed. As the legally recognized rights and title holders under Canadian and international law, we do not support this proposed oil pipeline, which could see over 200 oil tankers in our waters. And we, along with the province of British Columbia have called on the federal government to uphold their Oil Tanker Moratorium Act in its entirety with no exceptions or carve-outs.

No offer of equity or ownership will change our position. In 2016, Enbridge reported costs of $656 million on a never-built Northwestern pipeline with total impairment of $373 million before tax adjustments. And on March 24, Mr. Ebel stated that the conditions still don't exist for that pipeline to be built, but did not speak on the status of First Nations consent.

So we want to proactively save Enbridge and your investors from past mistakes. Can the members of the Board please describe how oversight will be provided to ensure indigenous rights and title holder positions on the proposed pipeline and tanker moratorium are respected and when a related risk assessment would be disclosed to investors in your decision-making process. Thank you.

Thank you, President Alsop. It's Greg Ebel. I appreciate the question very much. Maybe the first thing to say is that Enbridge is not a proponent of this pipeline. And frankly, nobody is at this point in time as the conditions just don't exist to commercialize such a proposal. So I think that's an important point here.

That being said, Enbridge is also very sensitive to the risks that you mentioned in your question and to any project like that. And we currently and have for a long time, taking into account all stakeholders' rights and obligations and issues and very much so with First Nations. And I think in my opening comments, I even discussed about First Nations involvements in projects that we have.

So for any project, not just the one that you mentioned that, as I said, we're not the proponent of, any project, we take those issues very seriously. It would go through the entire Board and our committee structure, including the Sustainability Committee, the Audit, Finance and Risk Committee and then the entire Board to make sure that we've met all of our obligations, both internally and externally, we've considered the risks and only in that situation, will we move forward. So I appreciate the question, but we have a robust process around that, ensuring that we do meet our obligations.

Greg. No further questions have been submitted.

Okay. Well, thank you very much. Since there are no questions, I'll now turn it back to Steve to close today's proceedings. And just let me thank all of our shareholders for their continued support of the company and our activities.

Thank you, Greg, and thank you to everyone again for attending today's meeting. We truly value your time and commitment to our company. You may now disconnect from the broadcast. Thank you for your support once again.

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.

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.

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.

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 Instructions]

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

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.

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.

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.

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%.

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.

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.

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.

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

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?

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.

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?

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?

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.

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.

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

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?

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?

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.

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?

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

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?

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.

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.

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

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?

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.

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.

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.

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

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.

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.

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

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?

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.

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.

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?

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.

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.

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.

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

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?

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.

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.

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.

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.

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.

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

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?

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.

I agree with that.

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.

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.

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.

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.

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

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.

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.

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?

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.

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.

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.

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

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?

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.

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.

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

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.

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.

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.

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?

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.

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.

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

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.

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.

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

Good morning, and welcome to the Enbridge Inc. Third Quarter 2025 Financial Results Conference Call. My name is Rebecca Morley, and I'm the Vice President of Investor Relations and Insurance. Joining me this morning are Greg Ebel, President and CEO; Pat Murray, Executive Vice President and Chief Financial Officer; and the heads of each of our business units: Colin Gruending, Liquids Pipelines; Cynthia Hansen, Gas Transmission; Michele Harradence, Gas Distribution and Storage; and Matthew Akman, 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 on the phone 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'll 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'll be referring to forward-looking information in today's presentation and in the Q&A. By its nature, this information contains forecast assumptions and expectations about future outcomes, which are subject to risks and uncertainties outlined here and discussed more fully in our public disclosure filings. We'll also be referring to non-GAAP measures summarized below. And with that, I'll turn it over to Greg Ebel.

Well, thanks very much, Rebecca, and good morning, everyone. Thanks for joining us on the call today. Before we start, I'd like to take a moment to congratulate Cynthia, who announced plans to retire at the end of 2026. Her outstanding leadership and dedication to Enbridge over the past 25 years is inspiring, and I'm grateful that she'll be continuing to provide guidance to our executive team through the end of next year. I'd also like to congratulate Matthew, who will transition to President of our GTM business at the end of this year as well as Allen Capps, who has been appointed to succeed Matthew as the Head of our Corporate Strategy Group and President of our Power business. As we've said before, and it remains true today, our investment in people creates a deep bench of executive talent to ensure a smooth transition and strong leadership as we move forward.

Now moving on to our agenda for this morning. I'm excited to share another strong quarter and highlight the significant progress we've made throughout all segments of our business. It has been a busy quarter for us with new projects serving a wide range of customers across our core franchises. We're going to start today with an update on our financial performance, execution of our increasing number of secured growth projects and prospects. And I'll also highlight the strong returns and stability our business continues to demonstrate and provide an update on each of our four franchises. Pat will then walk through our financial results and capital allocation priorities. And lastly, I'll close the presentation with a few comments on our First Choice value proposition before we open the line for questions from the investment community.

We had another strong quarter of results, including record third quarter adjusted EBITDA. That growth was driven by incremental contributions from a full quarter of U.S. gas utilities and organic growth within our gas transmission business. This keeps us on track to finish the year in the upper half of our EBITDA guidance, and we expect to land around the midpoint of our DCF per share metric. Our debt-to-EBITDA is 4.8x for the quarter and remains within our leverage range of 4.5 to 5x. Our assets remained highly utilized during the quarter with the mainline transporting approximately 3.1 million barrels per day, a third quarter record, thanks to strong demand.

We reached positive settlements at both Enbridge Gas North Carolina and Enbridge Gas, Utah, which we expect to drive growth as rates begin to take effect. We're still on track to sanction Mainline optimization Phase 1 this quarter and Phase 2 next year, and we'll get into more details on those projects during the business update. Over the quarter, we added $3 billion of new growth capital to our secured capital program, showcasing continued execution on the commitments we laid out last Enbridge Day.

In liquids, we sanctioned the Southern Illinois Connector, adding incremental egress out of Western Canada and providing a new long-term contracted service to Nederland, Texas. In Gas Transmission, we sanctioned expansions of our Egan and Moss Bluff storage facilities to support the LNG build-out along the U.S. Gulf Coast. And in the deepwater Gulf, we're expanding our previously approved Canyon system to provide transportation services for bp's recently sanctioned Tiber Offshore development. And earlier in the quarter, we sanctioned the Algonquin Gas Transmission enhancement project in the U.S. Northeast as well as the Eiger Express gas pipeline out of the Permian. And finally, we have advanced a joint venture with Oxy to develop the Pelican CO2 hub in Louisiana. These projects demonstrate the competitive edge from our all-of-the-above approach and our ability to meet growing energy demand across all parts of our business.

Now let's look at our value proposition and recap our year-to-date execution before diving into the business updates. Enbridge's low-risk model continues to deliver superior risk-adjusted returns in all economic cycles. Our cash flows are diversified from over 200 high-quality asset streams and businesses that are underpinned by regulated or take-or-pay frameworks. Over 95% of our customers have investment-grade credit ratings. We have negligible commodity price exposure and the majority of our EBITDA has inflation protection.

All of this results in Enbridge's industry-leading total shareholder return while maintaining lower volatility compared to peers and broad index constituents. Looking ahead, Enbridge's utility-like business model remains well-positioned and policy support for new investment in critical projects is improving, creating a business environment that incents coordination, dialogue, and growth. And I'm very pleased with how the team continues to grow the business and excited by the opportunities ahead for Enbridge.

With that said, let's jump into the business unit updates, starting with Liquids segment. Mainline volumes had another strong quarter, delivering a record 3.1 million barrels per day on average for Q3. The system was a portion for the entire quarter, reflecting continued strong demand for Canadian crude and the need for reliable egress out of the Western Canadian Sedimentary Basin. Given the continued strong demand for the Mainline this year, we expect to reach the top of the performance color ahead of when we initially anticipated. This is a great sign for us and our shippers.

We're achieving the maximum allowable returns under the mainline tolling settlement, delivering competitive value to our shareholders and our alignment with customers incentivizes us to move the increased volumes and provide them with access to the best markets. This leads in well to mainline optimization projects that I'll discuss shortly here, in addition to the previously announced projects like Mainline capital investment.

In the U.S., we sanctioned the Southern Illinois Connector project, which is backed by long-term contracts for full path service from Western Canada to Nederland, Texas. Once complete, the new pathway will add 100,000 barrels per day of contracted full path capacity to the U.S. Gulf Coast via a 30,000 barrel increase per day on Express-Platte system, 56 miles of new pipeline between Wood River and Patoka, and utilization of 70,000 barrels per day of existing capacity on the Spearhead Pipeline.

Looking ahead at additional egress projects, we are continuing to advance approximately 400,000 barrels per day of incremental capacity to the best refining markets in North America via mainline optimization Phase 1 and 2. MLO1, which will add 150,000 barrels per day of incremental egress is entering the final stages of customer approvals. and we are still on track to make FID this quarter and place the project into service in 2027. MLO2 has made significant progress as well, and that project could now add another 250,000 barrels per day of additional capacity in 2028. This second phase of mainline optimization will utilize capacity on the Dakota Access Pipeline, and we're happy to announce that we're teaming up with Energy Transfer to make that happen. So stay tuned for more on MLO2, including an open season announcement early in the new year.

Relative to potential greenfield projects that would require significant energy policy change, these brownfield opportunities offer the quickest and most cost-effective way to adding close to 500,000 barrels a day of capacity to satisfy the near-term production increases forecasted out of the basin. Finally, for liquids, we added the Pelican sequestration hub to our backlog, a project in Louisiana, which will provide transportation and sequestration for 2.3 million tons per year of CO2 and is underpinned by 25-year take-or-pay offtake agreements. We will partner with Occidental Petroleum to advance the hub with Enbridge managing the pipeline infrastructure, while Oxy develops the sequestration facility.

Now let's turn to our gas transmission business. This quarter, we've sanctioned an additional capital-efficient connection to our Canyon pipeline system to support bp's Tiber development in the deepwater Gulf. Originally announced last October, the Canyon system will transport both crude oil and natural gas under long-term contracts with the Tiber system expected to cost USD 300 million, taking the total Canyon pipeline development to about USD 1 billion and entering service in 2029.

In the U.S. Northeast, the AGT Enhancement will increase capacity of the Algonquin pipeline, providing additional natural gas to the critically undersupplied U.S. Northeast, serving local utility demand and reducing winter price volatility. That project is expected to cost USD 300 million and enter into service in 2029. Switching over to the Permian. The Eiger Express Pipeline is a 2.5 Bcf a day Permian egress development running adjacent to the operating Matterhorn Express system and is now sanctioned and expected to enter into service in 2028.

Since our initial 2024 investment in the Whistler joint venture, which holds these pipelines, we have invested $2 billion in operating assets and sanctioned another $1 billion of capital expected to enter service through 2028. Also in the Gulf region, we've sanctioned two natural gas storage expansions to support the market, which continues to tighten due to increased LNG, Mexican exports, and regional power demand. Egan and Moss Bluff storage systems, both salt caverns with exceptional connectivity and withdrawal rates are being expanded to offer a combined 23 Bcf of incremental capacity.

We expect to invest approximately $500 million in these facilities at 5 to 6x EBITDA builds and come into service in phases through 2033. It's worth taking a moment to dive a little deeper into the growing North American storage market and how we are positioned to serve our customers. Between Moss Bluff and Egan as well as the expansion of Aitken Creek announced last quarter, Enbridge is now set to add over 60 Bcf of new natural gas storage directly adjacent to the major LNG centers in North America. These expansions will come in a timely manner as there is over 17 Bcf per day of additional LNG-related natural gas demand expected to enter service by 2030. This demand dramatically shifts supply economics and increases the importance of strategically located storage capacity.

We are connected to all operating U.S. Gulf Coast LNG terminals and continue to invest heavily in infrastructure to enable the future growth of North American LNG. To date, we have sanctioned over $10 billion in projects with direct adjacency to operating or planned export facilities. There is a growing storage deficit across the U.S. Gulf and British Columbia coasts and having existing assets with the opportunity to execute brownfield expansions is incredibly valuable to our customers and investors. Through acquisitions and expansions, we have positioned ourselves as an industry leader in the storage space. With more than 600 Bcf of storage across our North American businesses, we can strongly support our customers as they continue to build out North America's LNG capacity and navigate the overall power demand growth we are expecting in the future.

Now let's spend a few minutes recapping all the work we've done in Gas Transmission segment since Enbridge Day earlier this year. At our Investor Day in March, we shared Enbridge's $23 billion gas transmission opportunity set, noting the potential to FIT up to $5 billion in projects within 18 months. This opportunity set has grown since then. And today, a little over 6 months later, we've already announced over $3 billion of new projects across our footprint, serving all pillars of natural gas demand growth, including reshoring, LNG, coal-to-gas switching and data centers. With over 23 Bcf a day of new gas demand coming online by 2030, critical investment will be needed to ensure reliable service for customers. And with this list here, you can see we are doing our part, deploying capital to meet the significant increase in natural gas demand across North America regardless of the end-use market.

Now let's turn to our gas distribution business. The GDS segment is yet another way for us to capitalize on power demand theme. We've seen data center and power gen opportunities continue to be a tailwind for the segment with over 50 opportunities that could serve up to 5 Bcf a day of demand, including almost 1 Bcf per day of demand for already secured projects. During the quarter, we also reached positive rate settlements with two of our U.S. utility regulators, which are currently being reviewed for final approval.

In North Carolina, allowed return on equity increased to 9.65% on an equity thickness of 54%, resulting in a revenue requirement increase of some USD 34 million. The settlement also introduces additional rate riders that allows for quick cycle return of capital for our major projects in North Carolina. These rates came into effect on an interim basis on November 1. In Utah, we filed a settlement for a revenue requirement of USD 62 million, which supports continued investment at attractive returns. We are expecting a rate order before the end of the year with rates to come in effect on January 1, 2026. Both these rate cases showcase the importance of natural gas as a safe, reliable source of affordable energy.

Now I'll continue with the power demand theme with our Renewables segment. As you can see from this slide, renewable projects have been a great place to invest in the last few years, driven by strong PPA prices, decreasing supply costs, and the associated tax benefits. The four projects on this slide showcase over 2 gigawatts of power backed by agreements with some of the largest technology and data center players in the world, including Amazon and Meta. Fox Squirrel and Orange Grove are currently operational. Sequoia Solar will fully enter service in 2026 and Clear Fork will follow entering service in 2027. Looking ahead, we still have a number of projects in the queue that we're advancing. But as always, we'll remain opportunistic and continue to stand by our strict investment criteria.

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

Thanks, Greg, and good morning, everyone. It's been another strong quarter across all four business units, thanks to continued high utilization of our assets as well as recent acquisitions. Compared to the third quarter of 2024, adjusted EBITDA is up $66 million, DCF per share is relatively flat and EPS is down from $0.55 to $0.46 per share. The decrease in EPS is primarily due to the profile change associated with our gas utilities, where Q3 tends to be a softer quarter for EPS as EBITDA is seasonally lower, but items such as interest and depreciation remained flat quarter-over-quarter.

In Liquids, despite the strong mainline volumes, contributions from the Mid-Con and U.S. Gulf Coast segment are tracking lower due to tighter differentials and strong PADD II refining demand. In Gas Transmission, we experienced a strong third quarter with favorable contracting and rate case outcomes on our U.S. gas transmission assets and contributions from the Venice extension and the Permian joint ventures we added since last year. The Gas Distribution segment is up relative to last year, thanks to a full quarter contribution from Enbridge Gas North Carolina as well as benefit of the quick turn capital we experienced within our Ohio utility.

In Renewables, results were up from last year with higher contributions from our wind assets and from the Orange Grove solar facility recently placed into service. Higher financing and maintenance costs from the acquisition of the Enbridge Gas North Carolina assets kept DCF per share relatively flat year-over-year. I'm pleased to once again reaffirm our 2025 guidance and growth outlook across all metrics. Our resilient business model positions us to deliver strong and predictable results through all cycles. We remain confident we will achieve full year EBITDA in the upper half of our guidance range of $19.4 billion to $20 billion, but don't expect to exceed the top of the band.

As we mentioned on previous quarterly calls, due to higher interest rates, particularly in the U.S., we continue to expect DCF per share at the midpoint of our $5.50 to $5.90 per share guidance range. Mainline volumes, FX rates, and the acquisition of an interest in the Matterhorn Express Pipeline earlier in the year continue to be the tailwinds to the full year guide. This is partially offset by higher interest rates, along with tight differentials and strong PADD II refining levels, which are expected to continue into the fourth quarter and thus have been reflected as an additional headwind relative to our assumptions heading into the year.

Now let's quickly discuss our capital allocation priorities. We remain firmly committed to a thoughtful capital discipline process, remaining within our $9 billion to $10 billion per year annual growth investment capacity as we pursue the wide suite of opportunities ahead. Our highly contracted cash flows support a growing and ratable dividend within our 60% to 70% DCF payout target range, ensuring long-term shareholder returns. We've grown our dividend for 30 consecutive years, a real testament to the stability of our business and the fundamentals that underpin it. On the leverage front, our consolidated net debt to adjusted EBITDA remains comfortably within our target range of 4.5 to 5x. This quarter, we saw $3 billion of newly sanctioned capital advanced.

As I've mentioned in the past, I like the fact that we're generating opportunities in all of our businesses, supplementing the next few years with accretive projects while also adding visibility into the back part of the decade with opportunities like our gas storage expansions and our offshore gas transmission projects, which we've announced this quarter. Our capital allocation focus will remain with brownfield, highly strategic and economic projects supported by underlying energy fundamentals, and I'm excited to see this opportunity set materialize into the future.

With that, I'll pass it back to Greg to close the presentation.

Thanks very much, Pat. It was indeed a busy quarter on the growth capital side, and I'm extremely pleased with the progress we've made since Enbridge Day in March. The North American energy landscape continues to evolve with energy demand driven by LNG development, power generation, data centers and baseload growth. Enbridge will continue to play a pivotal role in that growth within a disciplined framework that delivers consistent long-term shareholder value. Our low-risk utility-like business with predictable cash flows is underpinned by long-term agreements and regulatory mechanisms that has allowed us to increase our dividend for 30 consecutive years across a wide range of economic cycles and conditions.

Going forward, we expect to achieve 5% growth through the end of the decade, supported by our $35 billion in secured capital. Our scale offers optionality that few in our industry possess, and we'll continue to evaluate accretive investments across our footprint. Lastly, I'll just point out one housekeeping item. As has been typical, we intend to issue our '26 guidance for investors in early December. So please watch for that announcement on December 3. With that, I'll open the call to questions.

[Operator Instructions] Your first question today comes from the line of Spiro Dounis from Citi.

I wanted to start with gas distribution and storage. The release mentioned seeing an acceleration there in commercial activity and it sounds like demand from data centers and power being those initial expectations. So just a multipart question here, but curious what's suddenly driving that acceleration, if there's a particular region where you're seeing it? And how are you thinking about the time frame for when these could start to materialize?

Sure. So it's Michele Harradence here, Spiro, and happy to discuss that. And I would say we're seeing it across the board. I mean that's the real value of the diversity of the utilities we have. So -- when we look at about the projects that make up that 7 Bcf or so of data center opportunities that we're talking about, we divide that aspect into what I'd call our baseload demand, our data centers itself and the coal to gas. So it's a lot about power generation. It's the electrification tailwind that we've talked about.

So you could bucket that, I would say, the baseload demand is there in Ontario, it's there in Ohio, it's there in Utah, data center growth, lots of early-stage developments in Ohio and Utah in particular. I would say we're seeing up to 8 gigawatts between the two of them. And that's some of the early-stage developments we're seeing. And then the mid-stage stuff, we're estimated to be serving over 6 gigawatts in those two jurisdictions alone. And Ontario has a lot of growth as well.

And then finally, coal-to-gas conversion, again, to support power generation would be in North Carolina. But really, when we look across all the capital opportunities we have for GDS, that's maybe 20% of what we're looking at is the data center and power generation opportunity. I mean just the good standard core utility growth, leveraging our modernization program, still lots of opportunity there. We're seeing a lot of what I'd call major projects. We just put our Panhandle regional project into service. That's close to $360 million in Southwest Ontario. We have our Moriah Energy Center, the LNG plant in North Carolina. We have 215 Phase 1 and 2 in North Carolina. That's -- those two combined are USD 1.2 billion alone. We're doing a reinforcement project in Ontario up in Ottawa. That's another $200 million.

I mean, there's a lot of growth and opportunity going on in the utilities. And then our residential growth, although it softened in Ontario, continues to be strong in places like North Carolina and Utah, where there's a lot of folks coming. And finally, we're looking at our storage opportunities, and there's a good chunk of our capital that continues to go to storage for us. So a good suite of capital there, but hopefully, that answers your question.

Yes. Good upside, Spiro, from what we thought when we bought the assets 2 years ago. We didn't -- a lot of the folks hadn't seen the data center, particularly in places like Ohio, we knew Utah and North Carolina would grow nicely. But Ohio, the opportunity there that's happening on the industrial side and the power side and data center related is really great. I think people are kind of forgetting the fact it's not just about power right across the board, not only the secondary benefits, i.e., industrial growth, caterpillars, GEs, et cetera, having to build things and equipment, there's tertiary growth associated with DC and AI, which is really going to drive all these commodities, including oil, as you see, higher GDP, higher industrial growth. Who's building all this stuff? They're using gasoline, they're using diesel, they're using oil. And that -- so I see it right across the entire system.

Great. That's helpful color. Second question, maybe just going to Line 5. You all recently received a favorable decision from the Army Corps there. And it sounds like you expect state permits to be confirmed soon. So just curious how you're thinking about starting construction on that segment? And how do the outstanding item in Michigan play into next steps here?

Sure, Spiro. It's Colin here. So I'll try to abbreviate this answer, sometimes Line 5 questions get a little longer. But I would say that the permitting on both the Wisconsin reroute and the Michigan tunnel are regaining momentum, obviously, with the White House and energy security and just getting things done. So I would say that we are -- in Wisconsin here, we're awaiting the administrative law judges findings on the hearing that we've recently completed should have that soon. And we'd look to complete the Wisconsin reroute in 2027 and the tunnel is a few years behind that.

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

It's great to see the new disclosure around Mainline optimization Phase 2. Am I right to view this as an acceleration in terms of the cadence that you're planning to offer expanded egress to Canadian producers? And if so, what's driving that expedited timing? Is it customer demand? Is it sort of a race to be first to market? How should we think about it?

Well, maybe I'll start with a little context because I think you're right. This is maybe not one some people expected, although I'd say people have always underestimated what we can do with that super system. So remember, first of all, you got customers out there that are in particular Canadian customers looking at from an oil sands perspective, you don't have the type of depletion issues that are going on in some of the shale plays. You've got a strong U.S. dollar, which is critical, driving netbacks. So you got quite a different environment going on, obviously, in Canada and some other jurisdictions that analysts may focus from that perspective. But really the attitude of customers and what we can offer. But Colin, do you want to talk about that super system element of it?

Yes. I think -- I don't know that it's an acceleration here per se. I think it's being game on here for a while here. And I think the Canadian basin, as Greg was saying, is it turns out relatively advantaged compared to other basins. So maybe we have lost focus on it, but our customers haven't. And we've been all over the fundamentals, we see that 500,000, 600,000 a day of supply growth by the end of the decade. And I think our announcements here line up with what we talked about at Enbridge Day generally. I mean, the team is working hard on this, and I'm very proud of them, the engineering and commercialization of it is very creative and trying to seize the moment.

Yes, if there's bigger policy unlocks, there could be much more upside to monetize the trillions of dollars of value up in Northern Alberta. But even under the base case, the 600,000 a day is significant. We have, I think, consistently talked about our southbound playbook. And again, if there is an unlock much bigger, then the West solution can come into focus, kind of a companion to that unlock. But in the base case, South is where it's at. Our customers prefer that direction, integrated business models, lots of big efficient, long-lived refineries that are very competitive and of course, less competition now from Venezuela and Mexico, inbound heavy. So Canadian Oil will gain market share in that basin.

I think our solution set is unchanged. We're proud to sanction Southern Illinois Connector. Maybe in baseball terms, that's our leadoff hitter, and it's now on base. We've sanctioned this. This is a dual flow path, 30,000 new egress on Platte and the other 700 coming down our spearhead pipeline existing capacity, and we're going to move that on ETCOP with our -- which we partially own with our partner Energy Transfer. MLO1 is at the plate right now, and we expect to make commercializing announcement here in the next couple of months before year-end. Again, that's 150 a day. I think that's well chronicled. It's capital efficient. permit light using existing pipe in a right of way.

And recall, we've already successfully run an open season on the Flanagan South path through Seaway with our partner enterprise products. So that's well advanced. So MLO2, continue the analogy here, I'd say is in the batter's box. And as Pat and Greg mentioned, it's got a bigger bat than we thought we had before. We've upsized that from 150 to 250 a day. And again, similar to MLO1, existing pipe and right of way. And so again, using joint venture partners, this is all coming together nicely, not an acceleration, but I think continuing through here and hopefully get the basis loaded.

Yes. I hope -- and obviously, not lost on you, Aaron, but as Colin goes through that, you just tick off all those pipeline systems. And it's not just about the mainline. You got Express-Platte, you got ETCOP, you got DAPL, which we own all of our parts of right through the whole system. So there's multiple ways for us to serve our customers and multiple ways for our investors to win. And that's the pretty exciting part that I don't always feel gets fully valued in the market for sure.

That's a ton of great context. As a related follow-up, a significant portion of the $35 billion of secured capital comes into service in 2027. As we think about all these liquids projects that you just outlined, continued success in GTM, steady growth across the utilities. Do you see sort of a, I guess, what I'll call a high plateau in terms of capital entering into service towards the end of the decade? And do you see any timing or capital sequencing issues to maintain the spend between $9 billion and $10 billion?

Maybe Pat will want to add to this, but I don't think so. I mean, we're constantly adding to the back end. Look, I think that's not unusual for companies like ourselves. Just go through the stuff that Colin went through, right? You're talking '27, '28 and then '29, '30, you'll see additional pieces as well. The gas trend deep Gulf stuff is all '29. Storage piece comes in some late '29, '30. So I think it will stay up at that amount. That's what gives us the confidence on 5% growth. It's a bit of a flywheel that's going on right now, which is quite positive. But from a balance sheet perspective, we feel very good about that 9 to 10. Pat?

Yes, I think so at the end of the day, we've got a pretty fulsome '26 now. We've reserved some capacity for these MLO 1s and 2s. I mean, 1, we'll have some spend in '26; 2, probably not as large as it's a little later, but we'll reserve some capacity given how confident we now are in those moving forward. And then as Greg said, we're really happy to continue to build out the back part of the decade. And hopefully, that's adding a lot of clarity into the growth that the enterprise can have.

And I think it's pretty common in our infrastructure business where you got -- you have secured some capital for the next couple of years. It's kind of close to or just below your kind of capacity in any out years you're filling up. And I think the team has done a great job in the last 6 months of doing that. So we're very comfortable.

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

Just want to kind of maybe follow up a little bit on the last line of questions there with regards to growth over time and having talked about this 5% EBITDA growth potential over the medium term post '26. And I know you're not going to give us the December update today, but just wondering any foreshadowing you might be able to provide us here or thoughts into how we should be thinking about how that update could unfold?

Yes. I'm not sure we are going to give you much of that right now because as you say it's December. But look, I think -- look, you've heard what we've been able to do on the gas side today with announcements. The liquid side, Michele gave you a good tour to tab on that side as well. And despite what some people have looked at, we've even done a number of things on the renewable power side in the last year. So I think it's the benefit of the portfolio. And again, those secondary and tertiary benefits of everything from power demand, from policy changes, from GDP growth that actually give us that confidence, and we see growth right across the system.

So if your question is, do we see pullbacks in areas? No. In fact, we see acceleration even the renewable stuff that we have, a lot of that stuff is a long ways down the trail and anything we do sanction would have already been in a good spot from a policy perspective. So -- and as Pat just mentioned, we've got the balance sheet capacity, internally generated cash flow to be able to meet those demands. And obviously, every dollar of EBITDA we add adds another $4 or $5 of capacity. So we're very focused on that. So it's probably where I'd leave it today. I don't know, Pat, would you add anything further?

Yes. I mean I think our message, if you remember back 6 months ago at Enbridge Days was that the whole goal here was to add clarity into that back end of the decade growth rate. And I think it's fair to say that we're doing a substantial amount of projects that should help to clarify that. So we're confident in the growth rates that we've put forward, and we'll continue to add to this backlog. We know there's more to come in really every business, which is what I like the most about it. We've got a very diverse set of opportunities over what really turns out to be a 5- to 7-year time line now. So yes, we're feeling good about the growth rates.

Fair enough. I figure it's worth a try. Just wanted to dive in a little bit more into Western Canada and gas storage there. With LNG Canada ramping up. Just wondering if you could provide maybe a little bit more color on the tone of customer conversations there. It seems like the market is going to need a lot more logistics. You're expanding gas storage capacity there. Just wondering if you could elaborate any more on how you see this unfolding. It seems like these would be fundamental tailwinds to rates and economics overall, but just wondering what you guys are seeing.

Yes. Thanks, Jeremy. It's Cynthia Hansen. I would agree with you that we are having these tailwinds, particularly when it comes to storage. Of course, in the last quarter, we'd announced our expansion, a significant expansion of our Aitken Creek storage. We are the only storage in that BC area. So we currently have about 77 Bcf of storage there, and we announced another 40 Bcf. So that will -- we'll start construction of that in the first part of next year, and that will be in service in a couple of years following that. When we have the conversations, it was -- when we announced that opportunity, we had 50% of that storage signed up right away in a long-term contract. So -- our customers understand that there is that opportunity and they're willing to back that kind of expansion.

As we continue to look at other opportunities, the current discussions about LNG Canada Phase 2, all of that creates an opportunity, not just for our storage, but for the opportunities to expand our West Coast system. We've announced earlier this year the Birch Grove, which is an expansion of T-North that ties into that, too. So strong opportunities, but I would say that we'd like to continue to see that growth of those opportunities for LNG export. That will need the support of the BC and Canadian government as we go forward to make sure that we are positioning those projects to attract the capital they need in the long term to support that opportunity.

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

I'd like to go back to the Data Center and Power Generation opportunities. Obviously, that's a hot part of the market right now. And I think your own gas distribution business is advancing more than $4 billion of related projects. Can you provide some detail on how you're managing cost risk, in particular, in areas like that, that are hot and where there's a lot of competition, supply chain constraints and customer focus on time to market?

Yes. Obviously, several areas there. And as they relate to the gas distribution side, obviously, prudency kicks in. But recall, those are rate base type driven setups, right? So you're getting on a capital structure, call it, 10% return in the U.S. on about 50% equity. So as long as we're being prudent, I'm not feeling too concerned about that. Now that being said, given the size of the company, we are actively and we're out there doing that, making sure that we've got good alliance agreements with various contractors, giving us the best rates, actually going forward and even stockpiling, if you will, compressors and things like that.

And remember, on the inflationary side, I'd say about 30% most of these large projects would be CapEx related to equipment and things like that. So those relationships are really critical. And a lot of them, obviously, we're avoiding tariff structures through contract mechanisms as well. So far, so good. The biggest concern I have is on the people side of things and just getting the time and equipment in place. So we're pretty good at that.

I think we feel in terms of those long-term relationships with contractors and stuff like that. But Rob, it's something definitely we're watching closely. It's also why I love some of the projects that we announced today that are all relatively small, as Colin said, singles and doubles and quick cycle, relatively speaking, so that you don't have long drawn-out processes. And then the last piece is, as you know, a better attitude with policy around permitting and acceptance of these critical projects. And that takes a risk off the table from a CapEx perspective as well.

Okay. That's very helpful. And then a bit of a regulatory question here for Colin, and maybe we'll have to take this offline. But I'm curious about the Mainline optimization too and the interplay with the Dakota Access Pipeline, given there's still some lingering permitting issues there. So maybe, Colin, you could walk us through whatever relevant regulatory updates on DAPL that relate to the Mainline optimization too.

Yes. Sure, Robert. And it's a good question and one we've thought through. So we don't need a new presidential permit across the border. And we're confident that the DAPL EIS will come through in the spirit of energy security and energy dominance. So we're confident in that line of thinking.

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

You've mentioned a couple of times that the policy environment is getting better for energy infrastructure. In Canada, how are you interfacing with the Canadian major projects office? Enbridge has over, we'll call it, $8 billion of projects in development in BC. You could do more on the liquid side there as well. Is there a way to get incremental support to further derisk these projects?

Yes. At this point in time, we haven't put projects through the office. It's great that it's set up. Hopefully, that will be helpful for those national interest projects. But most of the things or all the things we're talking about are short cycle, relatively permit light. And so we haven't seen the need to go down that route. But that being said, we've had several conversations with them. Obviously, Don is well known in the industry and respected and has been very good to don't hesitate if you need some help around permits, et cetera, and working through the lab of the Canadian government. So we won't hesitate.

But to date, and I don't see that actually on any of the projects that we have. As you know, we have several billion dollars of projects being done in BC, things Colin's talked about today. But a lot of them are relatively permit light and even not giant CapEx as individual chunks. So I just don't see us using the major project office at this point in time.

Appreciate that color. And then maybe just going back to the Mainline. I appreciate all the details on further expansions, Colin. But maybe to dive in a little deeper, and I know it's early days, but what would an MLO3 look like? And how much more incremental capacity do you think you can get out of the basin without, we'll call it, a good amount of large diameter pipe?

Robert, you're reading my mind. So we've got some hitters warming up in the dug out. MLO3 and 4 are stretching. Our engineers are looking at that as well because there is a scenario here, right, where Canada and the U.S. do a bigger trade deal and energy is part of it. And the imperative may accelerate further. So we do have some, again, in-corridor in fence line solutions for that. But it's premature for us to probably talk about those.

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

We are actually seeing a lot of resurgence in solar stocks in the U.S., and you actually have a very strong solar portfolio. But because you have everything else, which is also so good, sometimes it's underlooked. So can you talk a little bit about your renewables portfolio and solar in particular and more deals like Clear Fork with Meta, if you could talk on those points, please?

Sure. Manav, it's Matthew here. Yes, you're quite right. I mean I think investment discipline is the order of the day in renewables, given some of the cross currents in the policy landscape, but we have to keep our eye also on the opportunity here because the customer demand for this remains very, very strong. We are still in the window where we've got interconnection-ready projects that are in fantastic locations with strong local support and great resource while the production tax credit window remains open. And so there's definitely a lot of interest from customers on the data center side around that, in particular, on our solar portfolio.

We've talked about Project Cowboy out in Wyoming. We are building a lot of stuff, as you know, you mentioned Clear Fork with Meta and ERCOT. But that Wyoming project has a tremendous amount of interest. and is potentially a very big one and is well advanced. And so again, we're going to be navigating carefully, but there should be win-wins here because customers know that there's this window. And there aren't that many projects that can actually get in into their windows and they need the electrons, and they want it, if possible, lower zero emissions. So I think we're really well positioned. But again, we'll be navigating this and with a very close eye on our risk profile and making sure that we are consistent with our low-risk business model across everything we do.

Perfect. My quick follow-up is your partner, Energy Transfer, talked about the Southern Illinois connector, exactly the kind of crude that U.S. refiners need. Can you also highlight some of the benefits of this project? And can you confirm if this is probably 2028 start-up, if you could talk a little bit about that?

Yes. Thanks, Manav. Yes, I agree with your thesis. And what else can I tell you here? This is a new market off our mainline system to Nederland, Texas. And yes, you can imagine we've got a map of all the refineries, and we're trying to feed all of them. We've got about 75% of U.S. refineries connected to our Mainline system. So this isn't a new market for us. technically not super complex using existing capacity on spearhead, just longer hauling that capacity. It used to go to the Patoka area, now that 100 -- of the 200 on Spearhead will go down in Nederland, Texas, and we're expanding the Platte system, I think pretty simple scope there, pump refurbishment. So high confidence execution. And so yes, the time line should work.

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

Some of this has been touched on already, but just a quick one on Southern Illinois and the whole path. So I mean the Mainline optimization seem like they're on the right track and Mainline volumes were 3Q record. But downstream of that, low volumes in 3Q, and it seems like it's going to be a headwind in 4Q as well. So just curious if you have a view on when that could improve? And then is there anything to read into the 100,000 barrels a day capacity on Southern Illinois because I think the open season figure was higher than that, like 200. So just curious on your thoughts on full pass volumes improving over time.

Sure. I can take that. So I think it's a temporary anomaly here. That path on our liquid system south of Chicago down to the Gulf has been pretty robustly used for a long time. It's been recently weaker, still pretty good, but a little bit weaker as you saw in our disclosures, Pat talked about it. That is due really not the weakness the South per se, but more so that, that demand, that upper PADD II demand has been unusually strong in the last quarter or 2. So higher absorption of that high Mainline throughput, just a bit further North. And so double-click on that, why is that? A couple of reasons. One, our product levels were lower given fuel demand. And so those refiners were running pretty hard, so higher utilizations to replenish those inventories. And secondly, they had I would say, higher than average just uptime. And so the combination of those two factors kept a lot of that mainline oil at home, so to speak, in the upper PADD II market.

I think Q4 should be maybe a little better than Pat suggested. We've seen some early quarter improvements here. And then moreover, I think just longer term, we've got a lot of confidence in that path. In fact, we just have successfully run two open seasons for that path, both have been oversubscribed to expand it. So I'd say it's a temporary effect. You also asked about 200 versus 100, yes, pardon me. So yes, we we're pretty happy with the 100 with our partner there. We actually had oversubscription for the 100, but we end up settling it at 100. It's just the most efficient kind of sweet spot on that project for economics overall.

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

I wanted to touch base first on the Woodside LNG project. Could you remind us going forward how the mechanism works on the contract as you close on the in-service dates?

Yes, I think you mean Woodfibre. Cynthia can take that, right? You mean...

Woodfibre, sorry.

Yes. Yes. Thank you. Yes. So the way our contract works is that we will be setting that final toll closer to the in-service date. So with our contract terms, we will get our return based on that toll structure that's finalized at that date. So we continue to benefit from the delay in that term as the cost increase and that will allow us to actually have limited exposure to some of these cost overruns that we're starting to see on that project. Now -- we are really excited, though, that we're 50% complete overall on the construction, and we believe that there's a really strong path to getting us to the 2027 in-service date.

Now the other thing, we'll have to see how it plays out, but the Canadian budget did have some accelerated bonus depreciation for LNG projects that have low emissions. And I think as we've talked about before, this will be amongst, if not the lowest emission LNG project globally given how it's getting its power. So we'll watch for that, which should be helpful from a return perspective as well.

Got it. And I have to chuck when I said Woodside because I do have a follow-up question on that partnership more specifically. Just think about your investments in on the BC Coast. And I'm curious just with LNG additions ahead and some of the strategic partnership you've seen with Williams in particular, is there appetite for Enbridge, may not something specifically like that, but maybe just appetite for LNG beyond what we have right now.

Yes. Ben, we're not opportunity light. We are opportunity rich. So us taking on -- I can't see us taking on an LNG facility with commodity exposure, which is what some other folks that you mentioned have done. We'll get done the Woodside opportunity here, and then we'll see. Obviously, there's a lot of water still to go under the bridge about getting things built in off the BC Coast. So let's continue with our Woodfibre project. Sorry, I said Woodside. Now you got me saying it. The Woodfibre project before we look at other ones.

And Look, you saw us announce today those storage projects are serving LNG on the Gulf Coast. Aitken is going to serve LNG in BC. A lot of the projects that Cynthia mentioned, the pipeline project, that's the stuff we know and know very well and earn solid regulated rates of return on. I think in this environment, that's probably a better setup for us. So we'll always look. We get an opportunity to take a look at everything, but I don't think our investor proposition is open to taking on a bunch of commodity exposure. We don't want to.

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

First question is about your crude oil production growth projections. I remember back in Enbridge Day, you've made a forecast that you may see more than 1 million barrels a day of growth through to 2035. Assuming that projection was made based on the landscape at that point in time, how would you view this growth now given what appears to be a supportive regulatory and political landscape in Canada?

This is Colin. Yes, great question. And I think our -- I think both of those projections are, I think, internally consistent, and I think our view of that is stable. There is an upside scenario here that if Canadian federal policy comes through on this vision of a global energy superpower, which we believe in strongly. We have a unique perch on that. I think there is upside -- there's for sure upside in that scenario. But it's an if at this point. So we've calibrated our business plan to the base case and are -- to a question a few minutes ago, are generating further solutions if the upside comes to be.

You're going to get a good insight on that, I think, as well, Maurice, right? Because if the policy conditions form in Canada that ensure that as a producing nation, it's actually competitive. The first sign of that is going to be our producers and then being more optimistic about production, and then we'll be able to react as capital forms. So -- but at this point in time, we wouldn't change the million by 2035. And the MLOs and the Southern Illinois Connector and our Mainline investment capital is all consistent with how we see that rolling out between now and the end of the decade, all other things being equal.

That makes sense. If I could finish off with a question on the Pelican CO2 hub. Oftentimes, these types of projects are perceived to have a lower return than the 4 to 6x build multiple that you can deliver within liquids pipeline outside the Mainline. Recognizing that you do have an internal competition for capital among your various businesses, I wonder if you could comment on the returns here or just more broadly about lower carbon opportunities, how do they compete for capital internally?

Yes. Look, I think both ourselves and Oxy are pretty darn careful on this front. If this project didn't earn at least the returns that we get from other Liquids projects, as you say, outside the Mainline, it wouldn't have got sanctioned. So obviously, I would even argue there's always some policy risk, so you want to make sure you get this right. So this is very much in that wheelhouse, if not a bit better.

And obviously, the tax incentive structures, we've got a lot more clarity on that out of the OBBB bill that came out so that we know exactly what our tax incentives are on that. And it's got a long-term 20-, 25-year contract with offtake player. So I would say returns are at least, if not a little bit better than what we're seeing in this world. Policy support is there where it may not be for some of the other unconventional investments. And we love our partner on this front who has very similar return type parameters.

I might just add on that.

I was just going to layer on that it's a very selective investment. We're going to take a crawl, walk, run approach to developing low-carbon infrastructure. I think the pace of it generally is a lot slower than most observed a few years ago. So we're going to take a very careful and disciplined approach here, as Greg mentioned.

It's great to hear. My -- I guess, all the best to Cynthia on your retirement, and congrats to Matthew in your new role.

Thank you.

Thank you.

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

I would also like to congratulate Cynthia on her retirement. Thank you for all your insights over the years, and I'd like to congratulate Matthew as well on his new role. Going back to the discussion around the Mainline expansion. So when it comes to resourceful solutions for moving incremental WCS barrels to the U.S. Gulf Coast, leveraging your JV system with Energy Transfer is certainly a capital-efficient approach. And as the downstream southbound capacity fills up over time, have you or would you also consider partnering with other pipelines such as topline, which also runs from the upper Mid-Continent to the Gulf Coast and currently has available capacity?

Yes, Theresa. And I think joint ventures are a big part of Enbridge's playbook. Cynthia has got a bunch, Matthew's got a bunch. We've got a bunch in our portfolio, and we're proud to partner with basically everyone in the industry. And I think that's going to be a part of everybody's playbook going forward. We also partner with enterprise products on Seaway. We've gone from 0 barrels a day through that system to what's going to be not far from now, 1 million barrels a day. So I think we've utilized joint ventures extensively. We've got a whole bunch of others across the system as well. So we're open to that. I think teamwork makes the dream work here in an exciting environment.

Got it. And looking at your medium-term outlook, not asking you to front run the guidance update to come, but just looking at what's already out there, how do you plan to align DCF per share growth with EBITDA growth over time, that 5% -- given that DCF per share has recently trailed EBITDA growth, what are the key drivers in bridging the two over time?

Yes, it's Pat. Thanks for the question. Yes, I think we have been pretty clear that the reason they kind of disconnected over the last couple of years was primarily related to cash taxes, and we see that plateauing. We've seen some pretty positive tax decisions made in the U.S. There's lots of conversations about things that could happen in Canada. But generally, we just see that the cash taxes are returning to be more in line with -- not having the growth that it had over the last number of years. So that's why those two primarily converge as you move later into the decade.

Your next question comes from the line of Praneeth Satish from Wells Fargo.

On the Egan and Moss Bluff gas storage expansions, can you break down how much of the 23 Bcf of capacity is already committed under long-term contracts versus any shorter-term contracts or merchant capacity? And then given that you're moving forward with the expansion, I assume pricing is favorable, much higher than historical levels. But can you provide some color on the contract durations? Is it kind of in the typical 3- to 5-year range? Or are you able to get something longer in this environment?

And then I guess as a follow-up to that, like how do you think about the trade-off between locking in longer storage term contracts versus keeping them shorter so you could potentially benefit from higher recontracting rates in the future?

Thanks, Praneeth. It's Cynthia. I would say that where we are right now, we have Egan, the first cavern that we're developing there is about 50% contracted and we'll, over a period of time, lag into that. We're managing these assets. It's an existing portfolio. So we're going to manage those contract terms consistently with how we've operated those assets. When we look at the overall contract terms, it is a speed from that 2- to 5-year kind of average overall. We always look for those longer terms as to be part of that portfolio. But as you noted, just with the opportunities right now as we continue to see the demand for storage increase, and we've seen some strong pricing associated with that, that's really supporting this ongoing development that we're doing. We want to try and manage the portfolio to really optimize that structure as we go forward.

Yes. And that 3 to 5 years, 2 to 5 years is pretty typical the way that we've done it historically. And look, I think we've got a super high level of confidence in the LNG coming in on the Gulf Coast. So that probably lets us leg into the contracts and we want to. But it depends on the location, right? Like, for example, the Aitken Creek contract, I think we took about half of that and have it under a 10-year contract. So it just depends on the situation, and it's worked extraordinarily well.

I'm glad you raised the storage question because we got 600 Bs or so across North America, all with great optionality outside the regulated piece. But we're adding just the announcements in the last 12 months, 10% to that number. So it's a big uptick for us at the right time in the market, and I feel very good, as Cynthia says, the way we'll leg into this.

And then I'm sure you saw that Plains recently announced the acquisition of the remaining interest in the EPIC Crude pipeline. They've talked about potentially expanding the pipeline, may or may not do it. But if they do, it seems like it could be a positive for your Ingleside assets. So just curious if you have any thoughts on that deal or just the overall landscape now at Corpus and the puts and takes for your Ingleside and Gray Oak assets.

Yes, it's Colin here. Yes, and we've observed that, obviously. And we're partners with Plains on Cactus II already. I'm sure there's more work we can do together to the spirit of the question a couple of minutes ago on teaming up. Our franchise is remains a work in progress, but it's still really a good one. Ingleside is the #1 export terminal on the continent. It's poised to grow all the advantages it has, Gray Oak. It's great. So we're pretty confident with our system there and hopefully can do even more with Plains going forward.

And that concludes our question-and-answer session. I will now turn the call back over to Rebecca Morley for closing remarks.

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, thanks so much, and have a great day.

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

Good morning, and welcome to the Enbridge Inc. Second Quarter 2025 Financial Results Conference Call.

My name is Rebecca Morley, and I'm the Vice President of Investor Relations and Insurance. Joining me this morning are Greg Ebel, President and CEO; Pat Murray, Executive Vice President and Chief Financial Officer; and the heads of each of our business units: Colin Gruending, Liquids Pipelines; Cynthia Hansen, Gas Transmission; Michele Harradence, Gas Distribution and Storage; and Matthew Akman, Renewable Power.

[Operator Instructions] Please note, this conference is being recorded. As per usual, this call is being webcast, and I encourage those listening on the phone to follow along with the supporting slides. We'll 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'll 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'll also be referring to non-GAAP measures summarized below.

And with that, I'll turn it over to Greg Ebel.

Well, thanks very much, Rebecca, and good morning, and thank you all for joining us on the call today. I'm excited to share another strong quarter and highlight the progress we've made across all segments of our business.

Last quarter, I spoke about the importance of continued dialogue with policymakers and regulators to ensure North American energy independence and security. I'm optimistic about our ongoing conversations and the alignment we're seeing today on both sides of the border to advance projects and legislation that serve growing energy demand. And Enbridge continues to be in a great position to serve this growing demand with its large incumbent footprint across all 4 business units.

We're going to start today with a midyear check-in on financial performance, execution and an update on our growth projects. I'll walk through how Enbridge is effectively navigating trade conflict, legislative change and geopolitical volatility. I'll then touch on how Enbridge is capitalizing on rising power demand in North America before providing an update on each of our 4 core franchises. Pat will then review our financial results and reiterate our capital allocation priorities. And lastly, I'll close the presentation with a few comments on our First Choice value proposition before we open the call for your questions.

We've made significant progress on the commitments we laid out for you at the start of the year, and I'm proud of the work the team has done to execute our financial, operational and growth priorities. We set another record for second quarter EBITDA, driven primarily by contributions from the acquired U.S. gas utilities and successful rate settlements in our Gas Transmission business. Our strong first half of 2025 gives us confidence that we'll finish the year in the upper end of our EBITDA guidance range, and we are well on track to meet our DCF per share midpoint.

The balance sheet is also in great shape. As of June 30, we're at 4.7x debt to EBITDA, primarily due to realizing another full quarter of earnings from the U.S. gas utility acquisitions that closed throughout 2024. Our assets remained highly utilized during the quarter and the Mainline transported 3 million barrels per day. That system has now been an apportionment for 6 of the first 8 months of the year, including July and August. We closed an investment on our West Coast system by a consortium of 38 indigenous groups backed by a loan guarantee provided by the Canadian government.

This partnership provides sustained economic benefits to First Nations and is aligned with Enbridge's continuous goal of recycling capital at attractive valuations for shareholders. We also closed the previously announced acquisition of a 10% interest in the Matterhorn Express pipeline in the Permian and upsized the Traverse Pipeline project from 1.75 Bcf per day to 2.5 Bcf per day, driven by strong customer demand. As a reminder, the Traverse Pipeline is part of the Whistler JV and is designed to transport natural gas between Agua Dulce and the Katy area in Texas.

Work on our planned Liquids Mainline Optimizations is ongoing, and we're pleased to announce that our recent 100,000 barrel per day open season on Flanagan South Pipeline was oversubscribed. We expect to reach FID on the first phase of the Mainline Optimization later this year.

On the growth front, we sanctioned the $900 million Clear Fork project in Texas, located just outside San Antonio. The project is fully contracted under a long-term offtake agreement with Meta and will support its data center operations. Meta represents a new addition to our growing list of AI and data center-related customers.

In Gas Transmission, we sanctioned expansions of Texas Eastern and Aitken Creek gas storage to serve growing industrial power and LNG demand across North America. Together, these renewable and gas projects highlight the competitive advantage of our all-of-the-above approach and our ability to serve increasing natural gas and power demand through multiple business units, services and geographies.

Now let's touch on the stability Enbridge continues to offer investors despite the ongoing volatility we are seeing today. The markets have been turbulent thus far in 2025, but the volatility has really showcased Enbridge's stable business model and the value of our low-risk commercial frameworks. Our size, diversity and disciplined capital allocation puts us in a great position to deliver predictable returns to shareholders in these conditions. Our exposure to tariffs is negligible across our operations. And importantly, Canadian oil and gas delivered to the U.S. via our systems has not attracted tariffs. Roughly 80% of our EBITDA is generated by assets with revenue inflators or regulatory mechanisms for recovering rising costs, which helps to backstop our ratable and growing dividend and earnings.

On the tax policy front, the extension of bonus depreciation provides benefits to Enbridge's near-term growth and our sanctioned or late-stage renewable projects are not expected to be impacted negatively by the One Big Beautiful Bill Act. The second quarter saw continued price volatility across commodity markets, driven by geopolitical instability, but Enbridge's low-risk business model protected us from those dynamics with virtually no exposure to commodity prices and over 98% of EBITDA generated by assets with regulated returns or long-term take-or-pay contracts.

Lastly, our footprint puts us in an ideal position to capitalize on growing energy demand in North America and beyond. We are connected to 100% of Gulf Coast's operating LNG export capacity, and our natural gas systems are located within 50 miles of 29 new data centers, 78 coal plants and 45% of all North American natural gas power generation. Our Gas Distribution franchise is the largest natural gas utility business in North America, and we deliver reliable natural gas to over 7 million customers every day in geographies with growing gas demand.

In the crude market, our incumbency positions us as the leading operator to provide new and expanded egress options for customers, something both producers and policymakers are, in fact, seeking. And our renewable power business is opportunistically providing power to some of the largest AI and data center players in the world as the demand for energy across North America continues to grow.

And let's take a couple of minutes to spotlight some of the investments we're making related to growing power demand. As you can see from this slide, Enbridge has already won and will continue to win power demand-related opportunities by deploying our all-of-the-above approach to energy in order to serve blue-chip customers across various sectors.

During our Investor Day in March, we shared $4 billion to $5 billion of near-term power generation opportunities across our gas and renewable businesses that we expected to begin announcing within 6 months. I'm pleased to say that we're ahead of schedule with over $1 billion of recently sanctioned projects between Clear Fork Solar in Texas and the Line 31 expansion in Mississippi. In addition, we can now confirm that Texas Eastern Transmission will be interconnected to the Homer City Redevelopment generating facility in Pennsylvania. We are working to commercialize opportunities to support data centers and hyperscalers in the states, further adding to our growth backlog. We've recently completed milestone projects for solar power backed by PPAs with Amazon and AT&T and continue to advance over $5 billion of power demand projects serving a combined 6 gigawatts of new generation.

With that being said, we can't forget about the progress we're making across various exciting opportunities in our Liquids business, which I'll get into now. Mainline volumes were strong again this quarter, delivering 3 million barrels per day on average for the quarter and 3.1 million barrels per day for the first half of 2025. At Investor Day, we announced up to $2 billion of investment in the Mainline through 2028 to support continued high utilization of the system, while also extending asset life and reliability. That investment is now underway, and we will earn attractive returns within the MTS Agreement collar of 11% to 14.5%.

We also continue to advance Mainline Optimization Phase 1. Our full path FSP open season was oversubscribed, and the team is now working towards FID-ing the 150,000 barrel per day Mainline Expansion later this year. Additionally, we launched an open season for the Southern Illinois Connector, which will leverage our existing footprint and our interest in the ETCOP pipeline to provide full path optionality for our customers serving additional U.S. Gulf Coast demand. Mainline investments of this nature are permit-like, provide attractive economics and will be sanctioned to meet our customers' increasing egress requirements. And lastly, down in the Gulf Coast, our 120,000 barrel per day Gray Oak expansion has partially entered service with full COD expected in mid-2026.

Now let's turn to Gas Transmission. We've got a number of exciting announcements this quarter spread out across our footprint. In Mississippi, we sanctioned the Line 31 expansion of Texas Eastern to serve rising industrial and power demand, all secured under 20-year take-or-pay agreements with a well-known investment-grade customer. This project was among the opportunities highlighted at Investor Day to serve growing gas demand. On the Gulf Coast, we've progressed optimization projects, including a $50 million expansion of SESH to serve the growing power generation needs of a major electric utility that's there serving data centers as well as an upgrade to the Tres Palacios storage facility in Texas. This storage upgrade is being done to increase injection and withdrawal rates and is part of a larger expansion opportunity we expect to realize later in the decade.

In Canadian Gas Transmission, I'm pleased to announce a 40 Bcf expansion of the Aitken Creek storage facility that will support the growing Canadian LNG market. That project will also optimize our other expansions underway on the West Coast system, providing customers with critical flexibility in a rapidly developing region, particularly on the LNG front.

Lastly, we are updating our capital investment for Woodfibre. As a reminder, Enbridge has a contract structure that provides us the ability to earn a low double-digit return, and we will now set that rate closer to the in-service date. We remain excited about the growing LNG market in Western Canada as all of these projects are expected to enter service in the 2027 to '29 time period, extending and adding visibility to our long-term growth outlook.

Now let's move on to our Gas Distribution business. We remain excited about the long-term growth outlook for our utility business and the foundational growth that helps to support the dividend. In Ontario, the Phase 2 rebasing process was completed, setting rates through 2028. And in Ohio, we received a decision on the rate case filed in 2023. While we didn't get all that we asked for, I'm encouraged by the almost 10% ROE and increased equity thickness, which remains among the strongest returns within our utility franchise. Of note, existing capital riders are a great and continuing feature, ensuring quick cycle capital returns, which was part of what attracted us to the investment back in 2023. Lastly, we filed for new rates in North Carolina and Utah this quarter and expect we'll have new rates in those jurisdictions by next year.

And now I'll turn to the renewable power sector. Enbridge continues to advance its world-class renewable portfolio using our financial strength, supply chain reach and construction expertise under a low-risk commercial model that delivers competitive returns. In July, we announced the Clear Fork Solar project near San Antonio, Texas, a 600-megawatt facility that will support data center needs. All generation is sold under a long-term offtake agreement with Meta Platforms. And importantly, the project is expected to meet all the requirements to fully qualify for renewable tax credits under new U.S. legislation.

Also in Texas, we are progressing the 815-megawatt Sequoia Solar development. The project is on track to partially enter service in 2025 with full production coming online in 2026. Also of importance, the One Big Beautiful Bill Act is not expected to impact any of our sanctioned projects, but we'll continue to monitor future developments in this fast-moving policy environment. It's our view that the recent U.S. legislative changes makes our backlog of late-stage development projects even more valuable.

But now I'll pass it off to Pat to go over our financial performance.

Thanks, Greg, and welcome, everyone. Strong utilization across our asset base has led to another solid quarter. We're posting record second quarter EBITDA despite continued trade uncertainty and geopolitical events. Compared to the second quarter of 2024, adjusted EBITDA is up 7%, earnings per share up 12%, while DCF per share is comparable. In our Liquids segment, we saw strong volumes with the Mainline transporting 3 million barrels per day, although weaker results at FSP and Spearhead resulted in a slight decrease compared to 2024.

In Gas Transmission, strong operational performance across our pipes and storage assets in addition to revised rates on U.S. GT assets added to the segment year-over-year. Our Whistler JV and DBRS system acquisitions in addition to Venice Extension entering service at the end of 2024 provided additional contributions. Gas Distribution is up relative to last year with the acquisitions of the U.S. gas utilities being the main driver. Higher rates, customers and storage revenues at Enbridge Gas Ontario, in addition to the colder weather, also contributed to the strong results within the segment.

In renewables, we saw lower contributions at our European offshore assets, which were partially offset by stronger wind resources in North America. For DCF per share and EPS, higher financing costs, current taxes and maintenance capital, primarily driven by the U.S. gas utilities acquisition, partially offset the higher EBITDA contributions. The per share metrics are, of course, impacted by the at-the-market issuances that were completed in the second quarter of 2024 to prefund the U.S. utility. I'm pleased to reaffirm our 2025 guidance and growth outlook across all metrics. With our strong performance through the first half of 2025, we're in a great position to finish the year in the upper end of our guidance range for EBITDA.

The resilience of our business model is really on display as we continue to deliver predictable returns through market volatility. The acquisition of a 10% interest in the Matterhorn Express, strong Mainline volumes and the strength of the U.S. CAD exchange rate are all tailwinds to our full year guidance, but are partially offset by higher-than-expected U.S. interest rates. We remain confident in our ability to achieve our near-term and medium-term growth outlooks.

Now let's touch base on our capital allocation priorities. As you would expect, we continue to be focused on disciplined capital allocation. Our balance sheet provides us with financial strength and flexibility, and our debt-to-EBITDA has decreased to below the midpoint of our target range over the past few quarters as expected following the close of the U.S. gas utility acquisitions. We also extended our track record of recycling capital at attractive valuations. The investment by our First Nation partners and a 12.5% stake in the West Coast system, which closed in July, generated cash proceeds of $0.7 billion and demonstrated our ongoing commitment to economic reconciliation and partnership with indigenous communities.

One of the keys to our value proposition is to sustainably return capital to shareholders, and we prioritize being in the 60% to 70% range of DCF payout. Our dividend is underpinned by high-quality, low-risk cash flow growth and continues to support our dividend aristocrat status. As a reminder, we've increased our dividend to shareholders for 30 consecutive years, and we expect to return approximately $40 billion to $45 billion over the next 5 years.

In terms of further growth, we will continue to make disciplined investment decisions and prioritize low multiple brownfield and utility-like projects with our $9 billion to $10 billion of annual investment capacity. What I especially like about this quarter is that we've announced or made significant progress on opportunities in each of our 4 business units, and those opportunities are spread throughout the end of the decade, adding even more clarity to our growth plans.

And with that, I'll pass it back to Greg for some closing remarks.

Well, thanks very much, Pat. And as you've just heard, it's been another strong showing from all the teams this quarter. Enbridge is ideally positioned to deliver predictable results through virtually all economic conditions and cycles. Our low-risk business continues to prove its value to shareholders, evidenced by the consistency of our cash flows and earnings growth. This year marks our 30th consecutive annual dividend increase, supported by our business model. We've also secured high-quality and sustainable growth via our now $32 billion secured capital program, adding visibility to our expected 5% growth through the end of the decade. We will continue to evaluate accretive tuck-ins and tax-efficient investment opportunities that fit within our wheelhouse to diligently ensure lasting returns to shareholders.

And with that, I'd like to thank you all for listening. And operator, please open the line for questions.

[Operator Instructions] Your first question comes from the line of Jeremy Tonet from JPMorgan.

Just wondering if you might be able to frame a little bit more, I guess, opportunities you're seeing across your footprint as it relates to natural gas, expansion to serve incremental power demand and possibly data center demand growth as well. We've seen news coming out of Pennsylvania Energy and Innovation Summit, a lot going on in Ohio as well. I think the slides reference other opportunities across your footprint such as in the West. So I was just wondering if you could frame a bit more the opportunity set, where you see it most across the portfolio? And I guess, time line to new projects materializing. Do you see this kind of a near term or just kind of steady cadence over time?

Well, Jeremy, maybe I'll start and then Cynthia can chime in, too, and maybe even -- I know not on the gas side, but maybe Matthew, too. So it's really all of the above. Like we -- in the GDS business and the GTM business and our renewable business, I was at that technology and economic summit you were talking about in Pennsylvania. And obviously, out of that came a press release of a big player using the Texas Eastern system to support Homer City in North Carolina and Mississippi and Georgia, we talked about on this call, Utah, all of those we're really starting to see things come in.

I guess the point I would make, there is 2 elements here. There's one the utility element, which I would say is most of where we're picking up the opportunities, and you heard us talk about Line 31 just a few minutes ago as well as SESH, very much utility-based. But there's a nice smattering of behind-the-meter type stuff, which is what Homer City would look like. And then let's not forget about the renewable side. I know you're asking about gas. So it's right across the system. Haven't seen that much in Canada yet, but I think that's actually an opportunity that will come, too.

Cynthia, do you want to add more from what we had laid out back at the Investor Day?

Yes. I'll just build on what you said, Greg. So if we look at what we said at Investor Day, we have just on the Gas Transmission side, 35-plus opportunities to 11 Bcf of gas, about $4 billion, $1 billion to $2 billion of that in that late-stage development. Right now, we have 10-plus specific data center opportunities in that late stage. Of course, we're located next to the natural gas generation. So 45% of all natural gas power generation is within 50 miles of our system. And within that area, too, that 50 miles, there's 29 new data centers. And then, of course, we still have the opportunities for coal to gas conversions. There's 78 coal plants in that area. That's about 80 gigawatts of current power generation.

So what I would say is we're seeing opportunities across the system in the U.S. in particular. And that's not to discount the opportunities we have on the natural gas side with -- along the U.S. Gulf Coast to serve LNG. So we still see lots of opportunities there. In Canada, we've done lots of expansions. And as was noted with the storage at Aitken Creek, that's going to serve more LNG opportunities. And last quarter, we had announced our Birch Grove expansion, too. So we continue to see a lot of opportunities, Jeremy.

Got it. That's helpful. And just want to pivot to Woodfibre, if you could. If you could provide a little bit more detail on some of the drivers in the higher cost expectations there and as well as maybe just any more detail to share. It seems like you still have the ability to earn a low double-digit return, but any color incremental on those 2 points would be helpful.

Yes, for sure, Jeremy. I am -- and we are never that pleased when we see more capital than we originally planned. However, with Woodfibre, as you mentioned, our contract structure does allow us to earn that double-digit return on capital as we agree to invest in the project. Fortunately, and through the agreements with departments, we're now going to set that toll on the higher capital amount nearer to the projects in service. Our partner, which owns 70% of the project, as you probably recall, they do take capital cost risk, but they get the benefit of selling the LNG commodity. So I think it's a really good balance of interest there.

And I guess my point being, while we're always really focused on the capital being deployed to the couple of dozen projects we've got in execution right across the portfolio, we're equally focused on the contractual and regulatory structures around that capital to ensure to the extent possible that we can make sure we get the return protected, should capital costs change, particularly on multiyear projects. And I really think that combined focus is serving us well on this project.

Now with respect to capital cost increases, I wouldn't -- it's not really one thing, right? We've had some changes in building codes permitting delays, not a new issue for most jurisdictions. We're adding additional flotilla. So that's where we house our employees. So that will create room for another 900 approximately folks as we get into the heavy builds and then some site conditions. So all those have really added up to this slide. Again, the key is, as you pointed out, our ability to continue to earn that low double-digit return.

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

I was hoping, Greg, you could discuss how you're seeing energy policy evolving in Canada. And if you could compare the prospects of a new pipeline to tidewater compared to some of the various incremental expansion opportunities that are available in the industry on the Liquids pipeline side.

Yes. Well, I think as you saw us announce today, and you've really seen us been going hard at this since January and last fall, our customers at this point in time, really want to go south, right? That's the premium market, which we're able to deliver to both PADD II and PADD III, think the Gulf Coast. And so Colin and his team have really put forward a number of really great incremental projects, and you can see those in the presentation. That's the first move. It's the most valuable market. It's the smartest way to do this. And then when that's done and as our customer production grows, that's when an opportunity could be created to go to the West Coast.

And there's lots of discussion with governments on that. And as you know, Robert, we have been a proponent of such a project in the past. And in fact, invested several hundred million dollars to get there. So the issue isn't not one of there being a proponent. The issue is one of government policy setting the conditions for that investment to occur. Let's be honest, the government has not done that yet. And it's not clear they intend to, at least from our perspective, in particular, still an emissions cap in place for our customers, which really stifles their ability to grow oil production.

And then secondly, the West Coast tanker ban remains in place that, frankly, as long as that's there, it would make building a pipeline to the West Coast being a pipeline to nowhere. So -- and nothing has been deemed in the national interest yet either. So lots of us to watch from an industry perspective. We're very active on that front. But we're continuing to find ways to serve our customers' needs by adding that incremental egress that they really want, which really means the Gulf Coast.

So TBD. Meanwhile, as you're seeing south of the border, a lot of changes, accelerated permitting, we even start to see it in changes to the Army Corps of Engineers and a desire to actually build energy sovereignty and project power. And so hopefully, that will translate up here as the government gets its footing. And in the meantime, we'll continue to provide counsel and advice to folks like the premier of Alberta, who she continues to work to advance not only the province's interest, but I actually think Canada's energy interest and sovereignty via new energy infrastructure.

That's a very helpful response. And I was just curious how the Ohio rate case order impacts your strategy on rate cases in general on the U.S. franchises and obviously, Ohio in particular.

Yes, Michele is here. I'll let her go at that. Obviously, regulatory expertise is something we're very focused on.

Sure. So obviously, we were disappointed in the Ohio rate case. But really, it's turning on a couple of, I'd call it, legal and regulatory issues. As Greg mentioned in his opening remarks, at the end of the day, the fact is we still have really strong ROE amongst the best that you can have. We saw an increase in our equity thickness. We didn't have any material denials into what we submitted as appropriate O&M. All of the capital that we've invested has gone into rate base. We continue to have the strong capital riders that we really like in Ohio.

So it's still a very strong and productive jurisdiction. But we do have a couple of specific issues that we think there were errors made by the PUC in Ohio, and we filed a rehearing about a week ago, a week ago today on that. So we're confident in the Ohio utility, and we're certainly confident in its growth, as was mentioned in an earlier question, lots of data centers, lots of generation there. So it's a good utility. But we are in rate cases in all 4 of our major utilities, as we mentioned, we're coming to the tail end in Ontario. And then we would expect to see our results in Utah and North Carolina coming through in the fall.

I think the big difference though for Utah and North Carolina is their rate cases are a matter of routine. We go every 2 or 3 years. So it's really just a question of updating things, having a discussion about what's the most appropriate levels of return without the 15-year lag that we had in Ohio. That really created a lot of complexity in the Ohio rate case. So we're very confident with North Carolina and Utah, good relationships there, transparent work. So things are good.

Yes. So obviously, if you think back to the acquisition, which we haven't even had all these closed for a year yet. That will come up in September, very consistent results and expectations. As you know, Rob, we're quite conservative in the way we look at things. And I would say we've probably been underestimated the growth opportunity there right across all the utilities and the regulatory filings and rate cases, that's standard what we do across all our businesses. And sometimes you get what you want, sometimes you don't. But it -- the business continues to drive forward.

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

Greg, you mentioned in your prepared remarks, but can you speak to the Cowboy Solar and Seven Stars projects? I guess I'm just trying to get a sense of if your customers are encouraging you to get these types of projects across the line, just given the changing tax credit landscape. And as it relates to other solar projects in your mid-stage development bucket, are there any practical limitations that we should be thinking about in terms of your ability to get more across the line? And then I guess, finally, just given the urgency, do you have the room in your annual investment capacity to get more projects like this done?

Yes. So we -- I'll let Matthew kind of jump in here in a second. But one thing I would point out is our customer need is driven not just on the renewables side, historically, maybe more focused from an ESG perspective. Today, the issue is the need for power, all types of power, right? So -- and you definitely see that in like the Metas and the AT&Ts and Amazons. Yes, sure, everybody wants to kind of move forward on the sustainability front, but it's really that need for power. So the late-stage stuff that we have continue to see, if anything, an increase. Matthew, maybe you can speak to that in request for that power.

I think your question, Aaron, if I'm hearing it correctly, really, post the projects we have and that are in late stage, all of which can be done within the new legislative changes in the U.S. It's really after that, the next stage called later in the decade or the end of the decade and beyond. Without the tax incentives, would they be attractive? I think that's a TBD, but it doesn't prevent the projects that we have in the backlog from moving forward. That's for sure. And if tax incentives aren't an element of projects on a go-forward basis, they're going to have to compete just like everything else with capital, and we'll see what happens macro-wise. You could make an argument, what you'll see is power prices go up, which still allows you to make your returns, but we'll see what happens at that time.

But do you want to speak specifically to those 2 projects, Matthew?

Yes, sure. Thanks. Just to add to what Greg said, we do have some projects in addition to the ones we've announced that are late stage and with a very high probability will continue to qualify for the credits. And we do see very strong customer demand from these blue-chip type customers like Meta, and we're very pleased to add them to our roster. And these are the types of customers that want to work with Enbridge, not just in our renewable business, but frankly, across our gas businesses, as Greg talked about, it's really a multi-platform strategy to satisfy demand for electricity rising rapidly.

We do -- so I think we have visibility to some more of these projects. You mentioned a couple that should qualify. But the key is to be very disciplined in this environment. It's very fluid. There's still some moving parts. The bill was relatively favorable on the tax credit front, but there are still some administrative actions that could occur. So we'll be conservative and we'll be opportunistic. But we'll stick to our very strong capital discipline in renewable, as Greg said.

I think one thing to note on the Seven Stars that you mentioned, that is actually a Canadian project. So I think the policy in Canada is much more stable and predictable right now. That's a wind project in Saskatchewan. On Cowboy, we'll see. It's a late-stage project, solar project in Wyoming. And again, on that one, it will have to hit our low-risk commercial model, and that's still evolving, frankly. So we'll keep developing those projects, but we'll be disciplined and low risk in our approach to FID.

And Aaron, I think your last point was on the capital capacity. Yes, I mean, the projects that Matthew has spoken about and the opportunities that we talked about for renewables at Investor Day, very much taken into account in our financial plans, and they would -- even with those projects coming forward, remember, we always have a couple of billion dollars of incremental capacity we could invest. So it's really not -- it's not capacity. It's more investment quality and return relative to what is a plethora of opportunities across the entire business.

That's a lot of great detail. Maybe just as my follow-up, one point of clarification. You mentioned Homer City a couple of times today. It looks like this project is pretty far along. Can you just give us a sense of time line to FID, potential capital requirements, returns in service date and any potential gating items?

Yes. Cynthia can chime in here. But to be blunt, no. Like I think it is -- it's kind of far along from an announcement perspective, but there's a lot of work here, right? That's a 4-gigawatt plus project towards the end of the decade. They're working through getting their gas supply agreements in principle. There's a lot of pieces in there. So it could be everything from a straight lateral to an expansion of Texas Eastern. But until the customer actually has determined exactly how it wants to deal with that, all I can tell you is we will get our fair share.

Yes. Thanks for that, Greg. I would just add that we are in those discussions. These discussions have started months ago. It will take a little while until we get through that final design and the commitments. But as Greg said, we will definitely have opportunity to participate. I would note that Texas Eastern has about 10 Bcf per day of underutilized receipt potential in that Marcellus supply region. And so we can do some very economical pipeline expansions to serve Pennsylvania and Ohio along our existing right of ways. So it's great, and we have lots of ongoing conversations with developers, power generators, hyperscalers around that area of Pennsylvania and Ohio. So more to come, and we'll keep you posted.

Yes. Aaron, I think about this as winning by a lot of singles and maybe the double. I think as you would well understand, say, a gigawatt plant takes, say, 150 a day gigawatt gas plant. That's not a massive pipeline, right? So you can see that with Line 31, you can see that with the SESH development. So it's a lot of incremental pieces built very economically that add up to a really nice investment. So sometimes I think people looking for the big splash billion pipeline projects. I think those are going to be few and far between for individual data centers.

So I think you got to keep watching these incremental pieces. And frankly, as investors, I think you should [indiscernible]. So I'll do 10, $100 million expansions that happen quickly, relatively permit light, probably not cross state, even though it may involve interstate pipe, all day long versus a big, say, greenfield new $1 billion pipe.

Your next question comes from the line of Praneeth Satish from Wells Fargo.

Maybe I'll just piggyback off of that question. So you've talked about obviously a lot of power generation opportunity and things. But so far, the announcements on the gas pipeline side, the pace of announcements has been a bit slower compared to peers. I mean you talked about having excess capacity. So maybe that's one of the reasons why your projects are maybe smaller in size than some of the larger builds that -- or CapEx projects that we're seeing. But maybe you could just kind of walk us through the differences here on Texas Eastern versus some of your other competitors? And is it because you have excess capacity? Are you waiting for the right returns? Are there dependencies tied to associated utilities? Just trying to get some more color there.

Well, I think it's a bit of both. I'm not sure I'd agree with your view that people have actually made more announcements on the other side. I think there's people talk about stuff, but let's go down the list, right? You got a 1.5 gigawatt, $1 billion projects for TVA that we're perceived with that's going ahead. In North Carolina in GDS, there's a 1.4 gigawatts, $600 million plus for a Duke facility in Utah, a couple of hundred megawatts plus. In Ontario, we're still pursuing some of those opportunities. And then the stuff that we just announced today. So I'm not sure I'd be on the same page there. I think some people that's maybe all they have. And as you know, we've got opportunities across multiple businesses on that front. And I mean, I don't know, perhaps you could -- you have that, but I'm not aware of anybody else having signed up Amazon having signed up Meta, having signed up AT&T on the renewable side.

So I think it's an all of the above opportunity for us. And I'm a big believer that much of this is actually going to be done with utilities on the power utilities. And you will note that in neither the case in Mississippi or the SESH project did we announce which utilities, those are 2. And that's because they're not really keen on actually indicating exactly what we're doing on the data center side. So I think you'll find -- I think if you crawl through it and maybe we can do a better job of communicating that to you that there's lots of pieces that we're knocking off. And I think we're actually ahead of what we said in terms of announcements from the Investor Day when we talked about the 18-month look forward, of which we're now, what, 4 months since that time frame and more to come.

Yes. No, I mean, just to kind of clarify, I think you're definitely getting a lot of traction, certainly on the renewable side and on the utility side. So I'm not saying there is an exposure to the theme, but it was more just on the gas pipeline side because you have a premier footprint there and you're kind of in the heart of this, especially with Homer City Building, I would have thought there would be more. But like you mentioned, maybe it's TBD and we'll definitely stay tuned.

Maybe just switching gears to my other question. I mean you mentioned OBBA and the bonus DD&A provisions there that could benefit near-term growth. I guess just from a tax perspective, does that lower your cash tax burden in the near term? When do you now expect to be a meaningful cash taxpayer?

Yes. Thanks for the question. Yes, I think generally, it's a very positive outcome from the various tax changes, as you said, extension of bonus depreciation, which affects a big portion of our overall business. I think the way to think about it is this further adds -- helps to the fact that we'll now be able to grow per share kind of in line with our EBITDA guidance. The last few years, there's been a bit of a differential because of the growing cash tax, but this will help to offset that and give us more and more confidence and clarity into that growth into the back part of the decade. So yes, we're excited about it, and we think it can help to grow our cash flows for our shareholders.

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

On the data center theme, can you maybe add a little bit of commentary on how you're thinking about the contractual frameworks and contractual protections regarding who the counterparty is and how you would potentially alter it, if at all, if it's a utility customer or a behind-the-fence customer?

Yes. Obviously, from a credit perspective, other than -- and you see this on the renewable side, the Googles and Metas and AT&Ts, they're obviously super credits. And that's why we're actually on balance seeing 75% of the opportunities with utilities, who are existing customers today, they're amazing credits, too. So -- and they like to sign up for long-term 10-, 15-, 20-year contracts take-or-pay. If it is with a small data center hyperscaler player, we look at that really carefully. And some of those folks would have to probably provide LCs, et cetera. But that's why, as I said, I think as this continues to move forward rapidly, I'm a strong believer you're going to continue to see those utility players there because this isn't as easy as what people think and the commitment to sign up for a 10- or 15- or 20-year pipeline contract or renewable contract says the big players will be there.

So from an analytical perspective with all the data center opportunities out there, the winners here, just like on the pipeline side will be the big players with scale, and that's the customers that will largely serve. And when I think about it, where the smaller players may have a better opportunity is, frankly, from our gas utilities, where there's a much larger scope of customers we have a requirement to serve. But even in some of those cases, depending on what happens, they'd have to provide aids to construct, which, as you know, is an element. So I think we've got it covered from the big players and on the utility, relatively small behind-the-meter stuff, you'd see that as a typical cost of service structure inside a utility, super safe for the investor and very fair for the customer.

Yes, exactly. And then switching gears here. Just regarding the $9 billion to $10 billion of investment capacity per year, it is looking like you're getting towards that range for '26 and '27 based off of the recent wins. How are you thinking about the cadence of when new -- or the cadence of project announcements and layering further capital in the next couple of years? Or is now the focus turning towards the kind of, we'll call it, beyond '27 time frame?

Yes, I can take that, Rob. I think it's fair to say that in '25 and '26, we've been filling up the opportunity set pretty well over the last 6 to 12 months, and I think that should give people more and more clarity into that kind of '27, '28 growth rate. And I think it's also fair to say that you look at the projects that we announced today within service dates around '28, '29 that we're now starting to fill in that back piece. We still probably have a little bit of capacity to take some of the smaller bite-sized things, quick turn capital as we go here.

But I think your comment is probably right in that I think we've added a lot of great projects that add that clarity, call it, to the middle of the next half of the decade. And our job is to continue to provide high return projects into the back part. So from a capacity perspective, as I think I said in my remarks, I like the way it's spread out across our businesses, but also spread out across the rest of the decade here. So feeling very good as we get more transparency into that.

Yes. I'd say our business development team is very much focused on the back half of the decade and have been, right? So that's about extending the growth, which we've got a lot of confidence in that post '26 period. And then as Pat says, most of what we talked about today will be very little capital in the next 12 months. And the stuff that does have capital like on the GDS side of things, in some cases, you'll start to earn on it before it even goes into service. But otherwise, it will actually generate EBITDA within, say, the 12 months, which, of course, then creates capacity, right?

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

Just want to go to your backlog and returns. And as I look at some of these projects you sanctioned in the last couple of years, you mentioned Woodfibre, low double-digit returns, T-North, T-South 10% returns. When I look at that and I look at the new projects you're announcing today, much better returns. Is the trend then for Enbridge cap allocation increasingly shifting more these higher return projects that you talked about the singles high returns that as we look at the next 12 months, that average return is going to start moving higher in that secured backlog?

Yes, absolutely. I think you put a finger on the great tension inside the company, lots of opportunities, but only those projects in those jurisdictions that provide better returns, i.e., lower build multiples are going to get serviced, right? So I would tell you right now, that's a challenge to do more in a place like British Columbia or even Ontario relative to Ohio or, say, Texas. So we want to keep our builds in that 6 to 8x. And then Colin has tons of stuff that is even on the bottom end, if not below that 6 to 8x. So very competitive.

And then, of course, Michele has higher multiples, but quicker cycle. And so yes, it's -- you should see, and this is very much our focus, a steady, and it's a big boat to move or a big denominator to move, increase in return on capital employed as we move up the chain in value-added investments. You hit it right on. It's actually a really nice environment as capital allocators to be able to pick and choose the best returns so we can keep those steady and stable and growing earnings that you all expect from us.

Okay. Got it. Maybe switching to the storage side, the Aitken expansion. Can you confirm, is there more white space beyond the 40 Bcf a day? And then -- and what's the strategy on the U.S. storage assets? Is it more recontracting? Or is there opportunity to expand as well?

Well, Cynthia, do you want to speak to that?

Sure. So this 40 Bcf at Aitken Creek is the most accessible. There would be other opportunities, but it would be not as accessible as this 40 Bcf. This was part of what we knew in the acquisition that it would be an easier stage step to get through. As it comes to other opportunities on the Gulf Coast, we continue to look at that. We had some open seasons for storage expansions that we launched in May, and we've gotten some really good interest.

So we're looking at developing our salt caverns there along the U.S. Gulf Coast. Of course, we expanded Tres Cavern 4 that just got into service at the beginning of the year. We also, as Greg noted, are continuing to optimize the structure there, but we're looking at whether with the open season interest, we'll be expanding more at Tres, Egan and Moss. There's a lot of, obviously, opportunities in that area and the continued expansions and LNG growth just provides some really good opportunities that we're excited about right now.

Yes. Sometimes I think it's under -- we've got 600 Bcf of storage across North America. Don't forget, Cynthia has got great elements here and the contracting has moved out a little longer and higher. That sort of more 3- to 5-year type contracts, but at higher rates than what we've seen for, say, the last 5 years that's kind of changed in the last 18 months. And don't forget at GDS, we have 100 or so Bcf of storage that is unregulated. And as all the needs that come in on the power projects we're talking about, LNG, not so much on data center, but LNG, et cetera, that makes that storage all the more valuable, right? So it's a good time for storage on the Gulf Coast and the Great Lakes regions and obviously, in Western Canada, where Aitken really is the only player in BC as LNG comes on.

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

This has been hit on a little bit from some other angles, but I just wanted to ask, what's your appetite for greenfield gas pipeline in Canada? There's a pending LNG project that needs a pipe and likely someone to develop it. So would that be of any interest to you if you got assurances similar to what you said you would need to underwrite a larger pipe on the crude side?

Well, I'll let Cynthia speak to it, but I think there's no doubt it seems like gas pipelines in Western Canada across Canada seem to have a -- not easy, but an easier road than, say, Liquids lines. And as you know, I think we've set ourselves up to do that. The West Coast system is fabulous. Indigenous participation in the West Coast system is fabulous setup. No guarantee that, that gets you consent, but very helpful in aligning interest.

But Cynthia?

Yes. We still have the Pacific Trails Pipeline project. Our [ TDP ] project would serve on to the West Coast. So there's future opportunities there. We'll continue to maintain that. It's fully certified. Of course, that would require a new large-scale LNG facility in the region to proceed. But we are obviously very supportive and continue to look at opportunities. It would, as Greg noted, have to hunt in our overall capital allocation, but it is something, of course, with our West Coast system and that knowledge and experience. And now with our recent move to improve our indigenous relationships in BC, I think we're well positioned to support that.

Yes. I think the situation is it's going to -- any greenfield pipe in Canada is going to have to have better returns than the West Coast system because the West Coast system is great and been there. It's a cost of service type structure, but you're not taking on the risk you would with a greenfield project. So that would be the determining factor. And as we've talked about throughout the call, we're not exactly opportunity poor.

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

Congrats on a very strong quarter, and I think it's not appreciated enough, but you probably indicated that you're coming in towards the top end of the guidance. So given your track record, we actually think you might beat it, but we'll keep our estimates within that range. My question to you is a little bit on the Southern Illinois Connector open season. Looks like a very exciting project. Can you talk a little bit more about this project and how -- what the path forward for this project is?

I think the guy that runs the liquids business is here. He usually gets the first question. So I'm glad he gets probably the last one.

Manav, we're excited about building out the plumbing in North America here to serve some long-term pretty sticky demand. And so maybe unlike MLO1, Southern Illinois Connector is more of a recontracting play. So it's kind of it's not new egress over the Canadian U.S. border, but think of it as long-hauling existing barrels on the system even further to serve some Louisiana refineries, adding to that 75% of refineries served on the continent.

So just adds another market to the network and in an efficient way, right, using existing pipes and in this case, partnering with the existing JV partner. So process on that one is the open season will go into August, and we'll look to roll some contracts on the Spearhead pipeline and add further long-term sticky paths to the Mainline. So that's -- it's exciting, and we're looking for more of those type of projects here to complement the low multiple build-out and egress adds for our customers.

Your next question comes from the line of Keith Stanley from Wolfe Research.

Curious what the remaining gating items are on the Mainline Expansion from this point? And are you expecting based on discussions that returns on this are going to be carved out separately from the CTS?

Yes. So as I mentioned in the prepared remarks, we're looking at and tracking for an FID later this year. The primary gating item has been achieved, which is the open season on the southern part of the path, Flanagan South, and that was oversubscribed. So lots of interest in long-term demand to the U.S. Gulf Coast. The other gating item is working with the traditional counterparties within CAP, if you like, or industry on basically kind of rolling in the Mainline capital into the rate base. And there's many precedents for that historically. We've expanded the Mainline countless times over the years, and we're confident we'll come to agreement with the industry on that.

And so it would fit within CTS or in rate -- MTS and rate base. And when we roll a subsequent tranche of Mainline agreement beyond its expiry in 2028, that capital would be duly considered in the rate base of the mainline going forward. So we'd earn of and on the capital in the Mainline as well. So 2 parts to that project, kind of the Mainline and then finding itself and seaway to the Gulf. And we've got many precedents for doing this historically. So there's some -- a little bit of gating there, but a well-treaded path historically to do such.

Okay. Second question, there's a few different project proposals now to bring Permian gas to other markets away from the Gulf Coast. So I'm curious what you see as the next steps for your JV with WhiteWater. Can you extend the value chain into Louisiana? Do you look more at storage? What other opportunities do you see in that JV with WhiteWater the next few years?

Yes. Thanks, Keith. We're really pleased with how our investment and our joint venture with WhiteWater has gone. There has been obviously some upside since the original one. We continue to have expansion projects. With Traverse, we just upsized that. We still see a lot of gas that would flow or want to flow to serve the LNG markets. And so we think that there's further expansion opportunities there. I know WhiteWater just announced with a similar project yesterday that they've upsized Pelican. So we're still seeing a lot of interest in that area.

The Traverse Pipeline, as was noted, provides more interconnectivity to allow that bidirectional flow between Agua Dulce and Katy hub. So that does create that tie. It does tie -- what we loved about those assets is it does tie to our existing footprint, that header system that we have with TETCO and of course, Tres Palacios storage. So yes, we would look at all opportunities to expand to move those volumes, and we continue to see a lot of opportunities on a go-forward basis.

And we could do something on our own, too.

We could.

So it's not just WhiteWater. It's obviously, it will be customer-driven. And do we think we have a better mousetrap than maybe the JV, -- although as Cynthia says, we've been really pleased with the way that's operated together. So yes, anything is on the table there. And as you know, as GORs go up in the region, the demand for that gas continues to rise. And as Cynthia just said, I think it's, you witnessed that going from a B in 3 quarters to 2 in a quarter on the Traverse Pipeline. So the opportunity is there, and we'll either use the JV, or we'll figure out something on our own.

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

I'll just stick with one question, but it's more of a wholesome question about relationships of customers rather than delivering individual assets. As you continue to hear more record spending on AI, how broad of a cooperation discussion did you have with Meta in terms of supporting their needs beyond Clear Fork and maybe even AT&T and Amazon since you touched on them earlier, recognizing that Enbridge certainly has the assets expertise and relationships across all energy forms.

Maybe I'll start, and Matthew can chime in here. That's actually a really great question because I would say early days, you're almost dealing with supply chain people, where they see it as a source of something they need, i.e., power or the case of gas to run their operation. I think as time goes up, we're moving up the chain in who we're dealing with at these corporations because of the real strategic nature of energy, which we all know, but it's not -- that's not something maybe the tech world or data centers we're kind of thinking through in the same way that we have. So making sure we understand their long-term interest, what they're trying to do, the scalability has caused it to move up as opposed to just be a supply chain issue.

Matthew?

Yes, I totally agree, Maurice. Thanks for the question. That's exactly how we think of it. And we're in the early innings of a major trend in energy that we can capitalize on across several of our business units. Renewable can be a little bit of a nexus for that initially. And if you saw the quote from Meta in our Clear Fork announcement was that they were thrilled to be working with Enbridge, and we're very pleased to be working with them. And it just goes to show that they're signaling they want to definitely do more, and there's lots of conversations with these types of customers that are ongoing. And so we see those being more the types of customers we can do business with across all of our platforms.

Yes. And size matters, right? The old Russian accent that quantity has a quality all of its own. People want to work with big players. So Meta doesn't want to work with a small-cap energy provider. They want to work with a major player and someone who's in 40-plus states and multiple countries and all the provinces, if you will, if you think in the North American context. So that is really mattering in a big way. And I think as you see further projects FID-ed in Matthews World and both on GDS and GTM, you'll see these players come to the fore, either through a utility, but they want to know how are they ultimately getting that infrastructure served and can they rely on the energy. And that's what we provide.

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

I just had a follow-up on the Ohio utility. Related to the impairment of this asset, can you talk about what led to this considering that it was only recently acquired? And when we take this into account as well as the rate case decision that's currently being appealed, longer term, does this change your view on the trajectory of growth or on the margin change the amount of CapEx you would allocate between the utilities?

I'll get things started and Pat can add if he wants to, Theresa. But the impairment -- the primary impairment associated with the Ohio utility, it was to do with the treatment of the pension asset, which is quite a significant asset that was in there. And they were determined -- those pension assets are determined to be excluded from the calculation of rate base. The position we had actually put forward was to have them excluded from rate base. So that's not inconsistent with what we were looking for. We're just asking for a rehearing with regard to how they treated the accumulated deferred income tax on that pension where they put that in for the purposes of calculating revenue reduction.

So it's something we expected was going to happen. And that's the majority of the write-off of the regulatory asset that we recorded. And then there's a smaller amount associated with the annual incentive plan. And in that case, again, we're applying for a rehearing on that point and primarily with regard to the -- what we believe is retroactive rate making where they've gone and disallowed it from anything that was put in attributable to that piece previously.

But Pat, I don't know if there's anything else you'd like to add.

I think you covered the kind of the genesis of the write-off well. I think your second question on the just change our capital allocation. No, I mean, I think Greg hit it quite clearly that there's still a very good return, almost 10%. We actually got a higher equity thickness coming through that. We have the maintenance of the capital riders, which are important in this asset. And so I think it's still a very positive framework to work with from a regulatory perspective. So I think you could see us go back for hearings a little more often than they would have done historically. As you know, there was this first hearing in like 15 years. So I think you'll see some of that from a rate strategy perspective. But at the end of the day, not at all unexpected as a result of the rate case.

Yes. And I wouldn't -- I don't think it has anything to do with the fundamentals of the business, your comment about a write-off so soon after the acquisition, like frankly, we think they've erred in long. In fact, they maybe where they're going violates actually some federal pension laws. But we'll take that up with them. And if we're right, you're going to see this reverse down the road. So that's the way we kind of think about it.

Yes. The only other thing I'd pass on is a lot of those pension assets actually went with Dominion. So remember, this is a rate case that was filed by Dominion in 2023. Dominion continues to carry the obligation with regard to the pensions for all the retired employees. And because it had been 15 years, that had really grown to quite a large piece. That's with Dominion. We've just got the current employees going forward. So all of that needs to be updated with the regulator. And our plan is to file for another rate case here likely by the end of this year just to bring all those numbers. These are these numbers date back to '23, they date back to pre-acquisition. So there's a lot that needs to be updated with the regulator, too.

We look forward to the next chapters of this development.

Your final question comes from the line of Patrick Kenny from National Bank Financial.

Just back on the preference here of customers continuing to push more and more barrels to the Gulf Coast. Just wondering if we can get a quick update on Ingleside, how throughput has been trending on a year-over-year basis and where things are at with respect to potentially sanctioning some of the optimization and dock expansion opportunities?

Pat, it's Colin. Up into the right, I think, is the summation to your answer. So we steadily are growing volumes through the terminal. As we've talked to you about, it's advantaged. We've got more storage coming online. I would also, yes, point to just some longer-term kind of bigger upsides in adding docks and stuff. We've done all the dredging, as you know, historically and continue to add barrels to it. We're adding a fungible service, which is incremental to the historic business model, which has been just dedicated term storage. So that's incremental as well.

So I think all of the whole menu of services and a variety of smaller optimizations and tweaks and then later on as the Permian Basin grows, we can add docks. I can confirm that we have connected the adjacent Flint Dock over and are able to load there to and optimize windows to get the smaller vessels there and the bigger vessels, VLCCs at the legacy dock. So plan is on track and more to come.

It's interesting that we often focus on domestic demand and things like that, but global oil demand is really, really strong. And obviously, that's a great setup for Ingleside on a go-forward basis as well, regardless if you see some Permian weakness later in the year.

And maybe as a quick follow-up there on your point, Greg. I know you've been previously looking at NGL export opportunities as well at Ingleside. But I guess, in light of Asian buyers perhaps looking to diversify their petrochemical supply. Curious if you might be looking to pivot opportunistically at other sites across North America, including Canada's West Coast here, especially as LNG exports continue to ramp up over time.

Yes. I'd say the strategy still is to kind of copy, paste all the advantages from crude export at that terminal to other commodities at that terminal. So still NGL and potentially clean ammonia over time as well here. So that remains the playbook. We've got lots of land.

Yes, you better move as opposed to doing it in Canada. I think if we copy, paste to a different location, you'd probably somewhere else along the Gulf Coast, and you've heard us ruminate about that from time to time. And yes, that will come to fruition over time a little further out though.

And that concludes our question-and-answer session. I will now turn the call back over to Rebecca Morley for some final closing remarks.

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, thanks, and have a great day.

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