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. 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. 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. 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. 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 conflicts, legislative changes, 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. 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 in 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 put us in a great position to deliver predictable returns to shareholders in these conditions. Our exposure to tariffs is negligible across our operations. 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 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 negatively impacted 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 actively seeking. 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. We're making investments related to growing power demand. Enbridge has already won and will continue to win power demand-related opportunities by deploying our all-of-the-above approach to energy 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 announce 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. We can now confirm that Texas Eastern Transmission will be interconnected to the Homer City Redevelopment generating facility in Pennsylvania. We're 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. 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 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. 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. 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 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. 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 nearly 10% ROE and increased equity thickness, which remains among the strongest returns within our utility franchise. 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. 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 designed to support data center needs. All generation is sold under a long-term offtake agreement with Meta Platforms. 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. 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. The recent U.S. legislative changes make our backlog of late-stage development projects even more valuable. 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. With that, I'll pass it back to Greg for some closing remarks.

Well, thanks very much, Pat. 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 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 and diligently ensure lasting returns to shareholders. And with that, I'd like to thank you all for listening. Operator, please open the line for questions.

Your first question comes from 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 the 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, I'll start and then Cynthia can add her thoughts, and possibly Matthew as well. It encompasses everything. In our GDS, GTM, and renewable businesses, I attended the technology and economic summit in Pennsylvania you mentioned. From that, there was a press release about a major player utilizing the Texas Eastern system to support Homer City in North Carolina, Mississippi, and Georgia. We also discussed Utah on this call, and we’re beginning to see various developments. I would highlight two main aspects: one is the utility segment, which accounts for most of the opportunities we’re identifying, as mentioned with Line 31 and SESH, both heavily utility-focused. However, there is also some interesting behind-the-meter activity, such as with Homer City. Let's not overlook the renewable side either. I know your focus is on gas, but it's evident across the entire system. There hasn't been much activity in Canada so far, but I believe opportunities will emerge there as well. Cynthia, would you like to elaborate on what we shared during Investor Day?

Yes. I'll just build on what you said, Greg. 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. We're located next to the natural gas generation. So 45% of all natural gas power generation is within 50 miles of our system. Within that area, too, that 50 miles, there are 29 new data centers. We still have opportunities for coal to gas conversions. There are 78 coal plants in that area. That's about 80 gigawatts of current power generation. What I would say is we're seeing opportunities across the system in the U.S. in particular. That's not to discount the opportunities we have on the natural gas side along the U.S. Gulf Coast to serve LNG. We continue to see a lot of opportunities there. In Canada, we've done lots of expansions. As was noted with the storage at Aitken Creek, that's going to serve more LNG opportunities. Last quarter, we had announced our Birch Grove expansion too. 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, Jeremy, we are not always pleased when we see more capital than we initially planned. However, with Woodfibre, our contract structure allows us to achieve a double-digit return on capital as we invest in the project. Through our agreements with various departments, we will set the toll on the higher capital amount closer to when the projects are in service. Our partner, who owns 70% of the project, takes on the capital cost risk while benefiting from selling the LNG commodity, creating a good balance of interests. While we focus heavily on deploying capital for our ongoing projects, we are also attentive to the contractual and regulatory structures surrounding that capital to protect our returns, especially if capital costs change on long-term projects. This combined focus is working well for us. Regarding capital cost increases, there are several contributing factors, including changes in building codes, permitting delays, and the addition of an extra flotilla to accommodate around 900 more employees during peak construction. All these elements have contributed to the overall increase. The key point is our ability to maintain 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. 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. That's the premium market, which we're able to deliver to both PADD II and PADD III, think the Gulf Coast. 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. 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. There's lots of discussion with governments on that. As you know, Robert, we have been a proponent of such a project in the past. In fact, we invested several hundred million dollars to get there. The issue isn't that there isn't 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. It's not clear they intend to, at least from our perspective, particularly with an emissions cap in place for our customers, which really stifles their ability to grow oil production. Secondly, the West Coast tanker ban remains in place, which makes building a pipeline to the West Coast a pipeline to nowhere. Nothing has been deemed in the national interest yet either. There is a lot 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 means the Gulf Coast. Meanwhile, as you're seeing south of the border, a lot of changes, accelerated permitting. We even started to see it in changes to the Army Corps of Engineers and a desire to build energy sovereignty and project power. Hopefully, that will translate up here as the government gets its footing. In the meantime, we'll continue to provide counsel and advice to folks like the premier of Alberta, who continues to work to advance not only the province's interest but actually I think Canada's energy interest and sovereignty via new energy infrastructure.

That's a very helpful response. 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. We were disappointed in the Ohio rate case. It's turning on a couple of 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 among 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 the capital we've invested has gone into rate base. We continue to have the strong capital riders that we really like in Ohio. It's still a very strong and productive jurisdiction. We do have a couple of specific issues where we think errors were made by the PUC in Ohio, and we filed for a rehearing about a week ago on that. We're confident in the Ohio utility, and we're certainly confident in its growth. As mentioned in an earlier question, there are lots of data centers and lots of generation there. We're in rate cases in all 4 of our major utilities, as we mentioned. We're coming to the tail end in Ontario. We expect to see our results in Utah and North Carolina coming through in the fall. The big difference for Utah and North Carolina is their rate cases are a matter of routine. We go every 2 or 3 years. 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, which created a lot of complexity in the Ohio rate case. We're very confident with North Carolina and Utah: good relationships there, transparent work. Things are good.

Yes. If you think back to the acquisition, we haven't 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. I would say we've probably 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. Sometimes you get what you want, sometimes you don't. 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, can you speak to the Cowboy Solar and Seven Stars projects? I'm trying to get a sense of if your customers are encouraging you to get these types of projects across the line, given the changing tax credit landscape. As it relates to other solar projects in your mid-stage development bucket, are there any practical limitations that we should be considering in terms of your ability to get more across the line? Given the urgency, do you have the room in your annual investment capacity to get more projects like this done?

Yes. I'll let Matthew kind of jump in here in a second. But one thing I would point out is our customer needs mostly drive this 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. You see that in the Metas, AT&Ts, and Amazons. Yes, everybody wants to move forward on the sustainability front, but it's really that need for power. The late-stage stuff that we have continues to see an increase. Matthew, maybe you can speak to that in request for that power. The projects we have and that are in late stage can all be done within the new legislative changes in the U.S. After that, the next stage—calling it later in the decade or the end of the decade and beyond—without tax incentives, would they be attractive? That's to be determined. But it doesn't prevent the projects that we have in the backlog from moving forward. If tax incentives aren't an element of projects on a go-forward basis, they'll have to compete just like everything else with capital, and we'll see what happens macro-wise. You could make an argument that power prices will go up, which still allows you to make returns, but we'll see what happens at that time. Do you want to speak specifically to those 2 projects, Matthew?

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. We have strong customer demand from blue-chip customers like Meta, and we're pleased to add them to our roster. These are the types of customers that want to work with Enbridge, not just in our renewable business, but frankly, across our gas businesses. It's really a multi-platform strategy to satisfy rising electricity demand. We have good visibility to some more of these projects. The Seven Stars, as you mentioned, is a Canadian project. 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. Again, it will have to hit our low-risk commercial model, and that's still evolving. We'll keep developing those projects, but we'll be disciplined and low risk in our approach to FID.

Aaron, I think your last point was on the capital capacity. Yes. The projects that Matthew has spoken about and the opportunities we talked about for renewables at Investor Day have been 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 capacity. It's more investment quality and return relative to what we see as 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 the time line to FID, potential capital requirements, returns in service date, and any potential gating items?

Cynthia can chime in here. To be blunt, no. It's kind of far along from an announcement perspective, but there's a lot of work here. 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. This could be everything from a straight lateral to an expansion of Texas Eastern. Until the customer has determined exactly how it wants to deal with that, all I can tell you is we will get our fair share.

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. As Greg said, we'll definitely have the opportunity to participate. I would note that Texas Eastern has about 10 Bcf per day of underutilized receipt potential in that Marcellus supply region. We can do some very economical pipeline expansions to serve Pennsylvania and Ohio along our existing right of ways. We have lots of ongoing conversations with developers, power generators, and hyperscalers around that area of Pennsylvania and Ohio. More to come; we'll keep you posted.

Aaron, I think about this as winning by lots of singles and maybe doubles. A gigawatt plant takes about 150 a day gigawatt gas plant. That's not a massive pipeline, right? So with Line 31, with the SESH development, there are lots of incremental pieces built very economically that add up to a really nice investment. People looking for the big splash billion pipeline projects are probably going to see few and far between for individual data centers. You've got to keep watching these incremental pieces. As investors, I think you should advocate for $10 billion, $100 million expansions that happen quickly, are relatively permit-light, and probably will not cross state boundaries, even though it may involve interstate pipe, rather than a big greenfield new $1 billion pipe.

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

You've talked about a lot of power generation opportunity and things. But so far, the announcements on the gas pipeline side have been a bit slower compared to peers. You've talked about having excess capacity—maybe that's one of the reasons why your projects are smaller in size. Could you walk us through the differences here on Texas Eastern versus some of your other competitors? Are you waiting for the right returns? Are there dependencies tied to associated utilities? Just trying to get some more color there.

It's a bit of both. I'm not sure I'd agree with your view that others have made more announcements on the other side. I think there are people who talk about stuff, but let's go down the list. You've got a 1.5-gigawatt, $1 billion projects for TVA that we're perceived with that are 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. We're still pursuing some of those opportunities in Ontario, and then there’s what we just announced today. I think some people that's all they have. We've got opportunities across multiple businesses on that front. 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. It's an all-of-the-above opportunity for us. Much of this is going to be done with utilities on the power utilities. You will note that in neither the cases in Mississippi nor the SESH project did we announce which utilities those are. They're not really keen on actually indicating exactly what we're doing on the data center side. So I think you'll find lots of pieces that we're knocking off. We're ahead of what we said in terms of announcements from the Investor Day.

Yes. No, just to kind of clarify, I think you're definitely getting a lot of traction on the renewable side and on the utility side. It was more just on the gas pipeline side because you have a premier footprint there and you're 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. You mentioned OBBA and the bonus DD&A provisions could benefit near-term growth. 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. Generally, it's a very positive outcome from the various tax changes, as you said: the extension of bonus depreciation, which affects a big portion of our overall business. The way to think about it is this further helps to the fact that we can now grow per share in line with our EBITDA guidance. The last few years had a differential due to growing cash tax, but this will help to offset that and give us more confidence and clarity into that growth into the back part of the decade. 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 add commentary on how you're thinking about the contractual frameworks and protections regarding who the counterparty is and how you might alter it if at all if it's a utility customer or a behind-the-fence customer?

Yes. From a credit perspective, other than you see this on the renewable side, the Googles and Metas and AT&Ts, obviously, they're super credits. That's why we're seeing 75% of opportunities with utilities, who are customers today and amazing credits too. 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. Some of those folks would have to provide letters of credit, et cetera. The big players will be there because this isn't as easy as what people think: the commitment to sign up for a 10-, 15-, or 20-year pipeline contract or renewable contract says the big players will be there. In some smaller cases, they’d have to provide aids to construct, which is an element. I think we've got it covered from the big players and on the utility, while for 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. 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 on the recent wins. How are you thinking about the cadence of project announcements and layering further capital in the next couple of years? Or is the focus turning towards the beyond '27 time frame?

Yes, I can take that, Rob. I think it's fair to say that in '25 and '26 we filled up the opportunity set pretty well over the last 6 to 12 months. That should give everyone more clarity into that '27, '28 growth rate. It's also fair to say that you look at the projects announced today with service dates around '28, '29 that we're now starting to fill in that back piece. We still have a little bit of capacity for smaller bite-sized things, quick-turn capital as we go here. Your comment is probably right that we've added a lot of great projects that add that clarity for the second half of the decade. Our job is to continue to provide high return projects into the back part. From a capacity perspective, as I said in my remarks, I like the way it's spread across our businesses and across the rest of the decade here.

Our business development team is very much focused on the back half of the decade and has been. That's about extending our growth, which we've got a lot of confidence in that post '26 period. Most of what we talked about today will have little capital in the next 12 months. The stuff that does have capital, like on the GDS side, in some cases, you'll start to earn on it before it even goes into service. Otherwise, it will generate EBITDA within, say, 12 months, which, of course, creates capacity.

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

Just want to go to your backlog and returns. As I look at some of the 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 the new projects you’re announcing today with much better returns, is the trend for Enbridge capital allocation increasingly shifting towards higher return projects? As we look at the next 12 months, will that average return start moving higher in that secured backlog?

Yes, absolutely. You put a finger on the great tension inside the company: lots of opportunities, but only projects in jurisdictions that provide better returns, i.e., lower build multiples, will get serviced. We want to keep our builds in that 6 to 8x. Colin has tons of stuff that is even on the bottom end, if not below that 6 to 8x. It's very competitive. Michele has higher multiples, but quicker cycle. Yes, you should see a steady increase in return on capital employed as we move up the chain in value-added investments. This is our focus, and it’s a really nice environment as capital allocators to pick and choose the best returns to keep those steady and stable and growing earnings that you expect from us.

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

The 40 Bcf at Aitken Creek is the most accessible. There would be other opportunities; however, it would not be 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 for other opportunities on the Gulf Coast, we continue to look at that. We had some open seasons for storage expansions in May and received really good interest. We're looking at developing our salt caverns on the U.S. Gulf Coast. We also expanded Tres Cavern 4 that just got into service at the beginning of the year. We're 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 are a lot of opportunities there, and the continued expansions and LNG growth provide some great opportunities that we're excited about.

Sometimes I think it's underappreciated; we've got 600 Bcf of storage across North America. Don't forget, Cynthia has got great elements here. The contracting has moved out, a little longer and higher. More 3- to 5-year type contracts, but at higher rates than what we've seen for the last 5 years, that's changed in the last 18 months. At GDS, we have about 100 Bcf of storage that is unregulated. As all the needs come in on the power projects we're talking about, LNG—not so much on data centers, but LNG, et cetera—makes that storage all the more valuable. It's a good time for storage on the Gulf Coast, the Great Lakes regions, and 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 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 larger pipes on the crude side?

I'll let Cynthia speak to it, but I think there's no doubt that gas pipelines in Western Canada seem to have an easier road than Liquids lines. We’ve set ourselves up to do that. The West Coast system is fabulous. Indigenous participation in the West Coast system is a fabulous setup. No guarantee that gets you consent, but it's 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, and there are future opportunities there. We'll continue to maintain that. It's fully certified. It would require a new large-scale LNG facility in the region to proceed. However, we are very supportive and continue to look at opportunities. It would need to fit into our overall capital allocation.

Any greenfield pipe in Canada will have to have better returns than the West Coast system because the West Coast system is great and has been there. It's a cost-of-service type structure, but you're not taking on the risk you would with a greenfield project. That will be the determining factor. 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. I think it's not appreciated enough, but you probably indicated that you're coming in towards the top end of the guidance. Given your track record, we actually think you might beat it, but we'll keep our estimates within that range. My question is a little bit on the Southern Illinois Connector open season. It looks like a very exciting project. Can you talk a little bit more about this project and what the path forward is?

I think the guy running the liquids business is here. He usually gets the first question; 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. Unlike MLO1, Southern Illinois Connector is more of a recontracting play, not new egress over the Canadian U.S. border. Think of it as long-hauling existing barrels on the system even further to serve some Louisiana refineries, adding to the 75% of refineries served on the continent. It’s another market to the network in an efficient way, using existing pipes and partnering with an existing JV partner. The process here is the open season will go into August, and we will look to roll some contracts on the Spearhead pipeline and add further long-term sticky paths to the Mainline. It’s exciting, and we’re looking for more of those project types to complement the low multiple build-out and egress options 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? Are you expecting returns on this to be carved out separately from the CTS?

As I mentioned in the prepared remarks, we're 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. Lots of interest in long-term demand to the U.S. Gulf Coast. The other gating item involves working with traditional counterparties within CAP, if you like, on rolling in Mainline capital into the rate base. There are many precedents for that historically. We've expanded the Mainline countless times, and we're confident we'll agree with the industry on that. It would fit within CTS or in rate—MTS and rate base. When we roll a subsequent tranche of the Mainline agreement beyond its expiry in 2028, the capital would be duly considered in the rate base of the mainline going forward. There are some gating items, but there's a well-treaded path historically to do such.

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

We're pleased with how our investment and our joint venture with WhiteWater has gone. There has been 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. We think there are further expansion opportunities there. I know WhiteWater just announced with a similar project yesterday that they've upsized Pelican. We're still seeing a lot of interest in that area. The Traverse Pipeline provides more interconnectivity to allow that bidirectional flow between Agua Dulce and Katy hub. It creates that tie. We loved those assets because it ties to our existing footprint with TETCO and Tres Palacios storage. Yes, we would look at all opportunities to expand to move those volumes and continue to see a lot of opportunities on a go-forward basis.

We could do something on our own, too.

We could.

It's customer-driven. Do we think we have a better mousetrap than maybe the JV? As Cynthia says, we've been pleased with the way that's operated. Anything is on the table here. As GORs go up in the region, the demand for that gas continues to rise, as you just witnessed that going from a B in 3 quarters to 2 in a quarter on the Traverse Pipeline. 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 about relationships with 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.

That’s a great question because 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. 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. That’s not something maybe the tech world or data centers were considering in the same way we have.

That's exactly how we think of it. 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. If you saw the quote from Meta in our Clear Fork announcement, they expressed their excitement to work with Enbridge. There are lots of conversations with these types of customers ongoing. We see those being more the types of customers we can do business with across all of our platforms.

Size matters. The old Russian saying that quantity has a quality all its own. People want to work with big players. Meta doesn't want to work with a small-cap energy provider. They want to work with a major player who's in 40-plus states and multiple countries and all the provinces in North America. That matters in a big way. As you see further projects FID-ed in Matthews World, both on GDS and GTM, you'll see these players come to the fore, either through a utility. They want to know how they're getting infrastructure served and if they can rely on the energy, and that’s what we provide.

Your final 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? When we take this into account, along with the rate case decision that's currently being appealed, 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?

The primary impairment associated with the Ohio utility was due to the treatment of the pension asset. That was a significant asset in there, and they were 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. This isn't inconsistent with what we were looking for. We expected this to happen. That's the majority of the write-off of the regulatory asset that we recorded. There's a smaller amount associated with the annual incentive plan. Again, we believe there's been retroactive rate making in that case. We're applying for a rehearing on that point, primarily regarding how they treated the accumulated deferred income tax on that pension. However, we still have a really strong ROE, among the best returns around. We've seen increases in our equity thickness. We have no material denials on what we submitted as appropriate O&M. Capital has gone into rate base. We're confident in the Ohio utility and its growth. There are lots of data centers and lots of generation there. We are in rate cases in all 4 of our major utilities. We expect to see our results in Utah and North Carolina coming through in the fall. The difference for Utah and North Carolina is their rate cases are a matter of routine. We go every 2 or 3 years. That creates a much simpler discussion about the most appropriate levels of return without the 15-year lag we had in Ohio. There’s complexity in the Ohio rate case. We’re very confident with North Carolina and Utah.

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, frankly, we think they've erred in the long. They may even where they're going violate some federal pension laws, but we’ll take that up with them. If we're right, you will see this reverse down the road. That’s the way we think about it.

A lot of those pension assets actually went with Dominion. This is a rate case that was filed by Dominion in 2023. They continue to carry the obligation regarding the pensions for all retired employees. 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. This needs to be updated with the regulator. Our plan is to file for another rate case by the end of this year just to bring all those numbers up to date. These numbers date back to '23—before the acquisition.

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

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

Pat, it's Colin. Up into the right, I think, summarizes your answer. We're steadily growing volumes through the terminal. As we've talked to you about, it's advantaged. More storage is coming online. I'd also point to long-term bigger upsides in adding docks. We’ve done all the dredging historically and continue to add barrels to it. We're adding a fungible service; that's incremental to the historic business model, which has been just dedicated term storage. It all adds to the menu of services and various smaller optimizations and tweaks. Later on, as the Permian Basin grows, we can add docks. I can confirm that we have connected the adjacent Flint Dock and are able to load there to optimize windows to get the smaller vessels there and the bigger vessels, VLCCs, at the legacy dock. The plan is on track; more to come.

It’s interesting that we often focus on domestic demand and things like that, but global oil demand is really strong. 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.

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 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.