Enbridge Inc. (NYSE:ENB) Q2 2025 Earnings Call Transcript

Enbridge Inc. (NYSE:ENB) Q2 2025 Earnings Call Transcript August 1, 2025

Enbridge Inc. beats earnings expectations. Reported EPS is $0.47, expectations were $0.41.

Rebecca Morley: 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.

Gregory Lorne 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.

Patrick Robert Murray: 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.

Gregory Lorne Ebel: 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.

Q&A Session

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

Jeremy Bryan Tonet: 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?

Gregory Lorne Ebel: 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?

Cynthia Lynn Hansen: 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.

Jeremy Bryan Tonet: 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.

Matthew A. Akman: 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.

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

Robert Catellier: 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.

Gregory Lorne Ebel: 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.

Robert Catellier: 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.

Gregory Lorne Ebel: Yes, Michele is here. I’ll let her go at that. Obviously, regulatory expertise is something we’re very focused on.

Michele E. Harradence: 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.

Gregory Lorne Ebel: 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.

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

Aaron MacNeil: 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?

Gregory Lorne Ebel: 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?

Matthew A. Akman: 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.

Gregory Lorne Ebel: 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.

Aaron MacNeil: 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?

Gregory Lorne Ebel: 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.

Cynthia Lynn Hansen: 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.

Gregory Lorne Ebel: 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.

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

Praneeth Satish: 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.

Gregory Lorne Ebel: 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.

Praneeth Satish: 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?

Patrick Robert Murray: 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.

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

Robert Hope: 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?

Gregory Lorne Ebel: 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.

Robert Hope: 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?

Patrick Robert Murray: 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.

Gregory Lorne Ebel: 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?

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

Benjamin Pham: 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?

Gregory Lorne Ebel: 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.

Benjamin Pham: 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?

Gregory Lorne Ebel: Well, Cynthia, do you want to speak to that?

Cynthia Lynn Hansen: 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.

Gregory Lorne Ebel: 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.

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

Sam Burwell: 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?

Gregory Lorne Ebel: 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?

Cynthia Lynn Hansen: 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.

Gregory Lorne Ebel: 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.

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

Manav Gupta: 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?

Gregory Lorne Ebel: 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.

Unidentified Company Representative: 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.

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

Keith T. Stanley: 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?

Gregory Lorne Ebel: 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.

Keith T. Stanley: 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?

Cynthia Lynn Hansen: 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.

Gregory Lorne Ebel: And we could do something on our own, too.

Cynthia Lynn Hansen: We could.

Gregory Lorne Ebel: 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.

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

Maurice Choy: 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.

Gregory Lorne Ebel: 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?

Matthew A. Akman: 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.

Gregory Lorne Ebel: 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.

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

Theresa Chen: 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?

Michele E. Harradence: 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.

Patrick Robert Murray: 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.

Gregory Lorne Ebel: 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.

Michele E. Harradence: 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.

Theresa Chen: We look forward to the next chapters of this development.

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

Patrick Kenny: 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?

Colin Kenneth Gruending: 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.

Gregory Lorne Ebel: 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.

Patrick Kenny: 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.

Gregory Lorne Ebel: 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.

Unidentified Company Representative: 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.

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

Rebecca Morley: 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.

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