TC Energy Corporation (NYSE:TRP) Q2 2025 Earnings Call Transcript

TC Energy Corporation (NYSE:TRP) Q2 2025 Earnings Call Transcript July 31, 2025

TC Energy Corporation beats earnings expectations. Reported EPS is $0.59, expectations were $0.56.

Operator: Thank you for standing by. This is the conference operator. Welcome to the TC Energy Second Quarter 2025 Results Conference Call. [Operator Instructions] The conference is being recorded. [Operator Instructions] I would now like to turn the conference over to Gavin Wylie, Vice President of Investor Relations. Please go ahead.

Gavin Wylie: Thanks very much, and good morning. I’d like to welcome you to TC Energy’s 2025 Second Quarter Conference Call. Joining me are Francois Poirier, President and Chief Executive Officer, Sean O’Donnell, Executive Vice President and Chief Financial Officer, along with other members of our senior leadership team. Francois and Sean will begin today with some comments on our financial results and operational highlights. A copy of this slide presentation is available on our website under the Investors section. Following opening remarks, we’ll take questions from the investment community. Please limit yourself to two questions. And if you’re a member of the media, contact our media team. Today’s remarks will include forward-looking statements that are subject to important risks and uncertainties.

For more information, please see the reports filed by TC Energy with Canadian Securities regulators and with the U.S. Securities and Exchange Commission. Finally, we’ll refer to certain non-GAAP measures that may not be comparable to similar measures presented by other entities. A reconciliation is contained in the appendix of this presentation. With that, I’ll turn the call over to Francois.

Francois Lionel Poirier: Thanks, Gavin, and good morning, everyone. Through the first half of 2025, TC Energy’s performance remains strong, delivering across all key priorities we set at the beginning of the year. First and foremost, our safety record remains exceptional with incident rates holding at 5-year lows. This is a direct reflection of our team’s unwavering commitment to safety in every step. Safety drives operational excellence, which allows us to maximize the value of our assets and supports our strong financial results. So during the second quarter, we delivered a 12% year-over-year increase in comparable EBITDA and are increasing our 2025 comparable EBITDA outlook to $10.8 billion to $11 billion, which represents an approximately 9% increase over 2024.

Contributing to this increase, we have reached a settlement in principle with customers on our Columbia Gas system that is expected to result in an increase relative to pre-filed rates as evidenced by the interim settlement rates that Columbia Gas put in effect, which reflects a 26% increase in pre-filed FTS rates. This outcome underscores both the demand we see across our assets and our ability to collaborate effectively with stakeholders. To date, we’ve completed or placed into service approximately $5.8 billion of capacity projects, including Southeast Gateway and our East Lateral XPress Project. Our results continue to emphasize TC Energy’s resilient low-risk business model that continues to deliver solid growth and repeatable performance.

The fundamentals underpinning our business have never been stronger, and our assets are strategically located to benefit from incumbent positions in the markets we serve. This strengthens our ability to compete for and capture the next wave of growth. North American natural gas demand is now forecast to grow by 45 Bcf per day by 2035 as opposed to our prior forecast of 40 Bcf per day. And this driven by LNG exports, power generation and industrial demand growth. This growth is structural and long term in nature. And we’re seeing this play out across our entire footprint. Electrification, coal-to-gas conversions and the rise of AI and data centers are accelerating the need for reliable, low-emission baseload power. In response, strong customer demand is emerging for incremental service on new and existing projects, such as our Pulaski and Maysville projects, which were sanctioned last year and have now been upsized to meet growing needs.

Our origination pipeline also remains robust. We are currently engaged in commercial conversations with more than 30 counterparties across the data center value chain, several of which have indicated the potential to require greater capacity than originally planned. These developments reinforce our confidence in our rising cadence of project announcements through the second half of the year and into 2026. So 2025 is stacking up to be an excellent year for TC Energy as we continue to expect to place approximately $8.5 billion of assets into service, roughly 15% below budget. July of this year, the newly constituted CNE approved our regulated rates required to provide service to potential future interruptible service users on the Southeast Gateway pipeline other than the CFE.

In addition, we placed approximately $300 million of projects in service in our U.S. natural gas business, including the East Lateral Xpress project, an expansion on our Columbia Gulf system that enhances connectivity to the U.S. Gulf Coast LNG export markets. Looking ahead to the second half of the year, we have multiple projects under construction. This includes the Virginia and Wisconsin Reliability Projects, ANR Oak Grove and the VNBR Project in Canada, all of which are tracking below budget or ahead of schedule and on budget. Across our North American footprint, we’re consistently executing on a diverse set of projects totaling approximately 3 Bcf per day of incremental capacity expected to be operational this year. These results reflect the strength of our disciplined approach to excellence in project execution.

Now since 2020, we’ve seen a steady upward trend in the returns of our sanctioned capital program. In 2024, our projects achieved an average unlevered after-tax IRR of approximately 11%, up meaningfully from 8.5% just a few years ago. And looking ahead, we expect this upward trend to continue as we high-grade a growing set of competing opportunities to optimize returns and maximize long-term value. In fact, year-to-date, our sanctioned projects have an expected average unlevered after-tax IRR of approximately 12% and for new projects going forward, we continue to expect to deliver EBITDA build multiples in the 5x to 7x range that translates to low to mid-teens IRRs. Importantly, and similar to the Northwoods project we announced earlier this year, these opportunities are predominantly brownfield in corridor expansions that leverage our existing footprint and long-standing customer relationships.

Contracts are underpinned by long-term take-or-pay agreements with investment-grade counterparties and in many cases, have upside potential. For instance, the strategic upsizing of the Pulaski and Maysville Projects that we sanctioned last year has enabled us to further improve the low 6x build multiples expected on both projects. Turning to Bruce Power, an asset that continues to deliver long-term value and plays a central role in Ontario’s energy future. Our investments through the major component replacement program are enhancing the reliability and availability of our nuclear fleet. These are long-duration investments that support the province’s clean energy goals while delivering strong returns for our shareholders. As shown on the left-hand side of this slide, Bruce Power’s availability has steadily improved from the mid-80s percent range in prior years to an expected average in the low 90s for 2025.

And at the same time, the realized power price we receive continues to trend higher as the contract price is adjusted annually to reflect capital investments, inflation and other factors. Combined with Project 2030, these investments are expected to nearly double our equity income from Bruce Power by 2035. Ontario published its latest electricity demand forecast in April that indicates a 75% increase needed by 2050, with Bruce Power playing a key role in meeting that need. The Bruce C Project is progressing, supported by up to $50 million in federal funding for development and assessment. We are proud to be part of this essential infrastructure and to continue delivering value through disciplined strategic investment. With that, I’ll turn the call over to Sean.

Sean P. O’Donnell: Thanks, Francois, and good morning, everybody. TC’s operations teams delivered exceptional utilization rates across our natural gas and power portfolios during the quarter, which coincided with increased customer demand across our North American footprint. On the left-hand side, we highlight a number of volume increases and new record set in each of our three pipeline business units. On the bottom of the slide, in our Power and Energy Solutions business, Bruce achieved 98% availability in an exceptionally strong quarter while also receiving its annual price adjustment as of April 1. We continue to expect Bruce’s overall availability to be in the low 90% range for full year 2025, which includes the planned maintenance outage on Unit 2 in the third quarter.

Shifting to the EBITDA bridge on the right-hand side, you’ll see that each of our business units increased their EBITDA contribution over the comparable quarter last year. Canada gas EBITDA increased due to increased contributions from Coastal GasLink following its in-service date last October and higher flow-through regulated costs. In the U.S., EBITDA increased mainly due to the settlement in principle and the application for higher transportation rates on Columbia Gas, which became effective on April 1. We also saw incremental earnings from new customer contracts on several existing pipelines and new projects placed into service in the quarter. Our Mexico business increased due to higher earnings in TGNH, primarily related to the completion of the Southeast Gateway pipeline, partially offset by lower equity earnings from Sur de Texas as a result of the strengthening peso and higher income tax expense.

Lastly, our Power and Energy Solutions business had higher contributions from Bruce due to increased generation output and a higher average realized price of $110 per megawatt hour, which is up $8 per megawatt hour relative to the second quarter last year. Our Alberta co-gen continued to deliver strong performance with greater than 90% availability, which maximizes our capacity payments. That was partially offset by lower Alberta power prices that continued to average approximately $40 per megawatt hour in the second quarter. Turning to our 2025 financial outlook that Francois mentioned. We now anticipate 2025 comparable EBITDA to be $10.8 billion to $11 billion. For context, the increase in our 2025 outlook reflects two drivers: first, the strong operational results and market pricing realized during the first half of the year; and second, our high degree of confidence in our execution plan for the remainder of the year.

A key to our execution plan is continuing to place our projects into service on schedule and under budget. That remains a top priority and a tailwind to capital efficiency and EBITDA performance. The combined value drivers of strong asset performance and capital optimization allow us the flexibility to most efficiently fund our incremental growth and prioritize our leverage metrics. On the balance sheet, we expect further deleveraging to approximately 4.75x by the end of 2026 based on the full year contributions of Southeast Gateway and the 7 other projects expected to be placed into service later this year. Looking out to 2027, we continue to target EBITDA of $11.7 billion to $11.9 billion, which implies a 5% to 7% 3-year growth rate that again highlights the predictability of our base business.

A few reminders that we like to offer each quarter on FX. We systematically hedge our U.S. dollar net income to insulate our comparable earnings from FX volatility. So we do not expect a material impact related to FX on our 2025 comparable earnings. Longer term, on an unhedged basis, a $0.01 change in the USD-CAD corresponds to roughly a $0.01 change in comparable EPS. So to wrap up our financial overview, with 97% of our EBITDA being underpinned by rate-regulated or long-term take-or-pay contracts and management’s clear visibility on a low-risk repeatable project backlog, TC continues to operate a resilient business model with a durable long-term value proposition as highlighted by our 25 years of consecutive dividend growth. Finally, we released our 2025 report on sustainability this morning.

The report provides a comprehensive overview of our sustainability performance and progress, including how TC Energy has reduced absolute methane emissions by 12% over the last 5 years, while increasing throughput by 15% and increasing comparable EBITDA in our natural gas business by 40%, it highlights how we’re continuing to work to drive down methane emissions, including the introduction of a new methane intensity reduction target of 40% to 55% by 2035 as measured by 2019 levels. And finally, how our strong safety performance is the foundation of our operational excellence and a key driver behind the financial results we shared with you this morning. We hope you read more about our team’s important sustainability efforts in the report on our website.

With that, I’ll pass the call back to Francois.

Francois Lionel Poirier: Thanks, Sean. As we look ahead, our focus remains squarely on those three priorities we continue to drive our success on. First, maximizing the value of our assets through safety and operational excellence; second, executing on our high-quality capital-efficient growth portfolio, including completing or placing approximately $8.5 billion of assets into service this year, and third, maintaining financial strength and agility to support long-term value creation. Strong momentum across our operations and capital program, we remain confident in our ability to deliver low-risk, repeatable growth through 2025 and beyond. Operator, we are now ready to take questions.

Operator: [Operator Instructions] Our first question will come from Praneeth Satish of Wells Fargo.

Q&A Session

Praneeth Satish: Congrats on a strong quarter here. Maybe I’ll start with the Columbia Gas settlement filing. So I think in the filing, it mentions the establishment of rates over three defined periods. Can you maybe just provide more details on the rates during these periods? What are the conditions to see a step-up in rate? What’s the magnitude? And I understand it’s not conditional on CapEx investments. So I guess what are the gating factors there to step the rate higher over the next few years.

Tina Veronica Faraca: Praneeth, this is Tina Faraca. I’ll take that question. We’re really excited about the outcome of the PUCO or the Columbia Gas rate settlement in principle. We’ve had a constructive agreement with our customers that resolved all major issues in the case. As you’re probably familiar, the settlement in principle established interim rates that were put into effect that reflects about a 26% increase to our pre-filed firm transportation rates. The rates obviously are subject to final settlement once we have filed and seen approval by FERC. There were several key issues that were addressed by the settlement in principle, including the establishment of rates for three defined periods, also 3-year moratorium and a required comeback in 6 years and roll-in treatment for a couple of our recent reliability projects.

Related to your question on the step-up in rates, that is not detailed in the settlement at this stage, and the step-up in that detail of rates is going to be provided in the final filing. So at this case, we can only communicate. There are three defined periods established and more details will come in the final filing.

Praneeth Satish: Got it. Okay. And maybe switching gears. I mean, I don’t think it’s a secret that Meta is actively building out its campus in New Albany, Ohio, including a planned multi-gigawatt cluster there. So I know Columbia Gas is already feeding one of the behind-the-meter projects in that data center park. But I guess how much available capacity do you have upstream of that interconnect point if, let’s say, gas demand there grows significantly? I guess how much more gas can you push into New Albany off of the Columbia system? And I asked that in the context of Meta’s earnings last night where they said they’re targeting a 30% increase to CapEx to over $100 billion. So potentially, there’s a lot of spending coming to that region.

Tina Veronica Faraca: In that region, Praneeth, we obviously have a lot of pipelines that run through the New Albany area, and we’re in a very strong position as these opportunities develop to serve capacity or transport capacity into that region. We have had some recent open seasons in that area. that were secured by various entities. We’ll continue to see how we can optimize capacity in that region. And in addition, we are certainly positioned to expand if necessary, depending on where the supply is required from, given our footprint in that region. Also, as you know, we have several utility connections with some of our major customers there. So if any of these opportunities progress within their service territory, we’re very well positioned to serve that demand.

Operator: The next question comes from Aaron MacNeil of TD Cowen.

Aaron MacNeil: I guess this one is probably for Sean. I know it’s unchanged in the disclosures, but how should we be thinking about your 2027 EBITDA guide given the increases in 2025 and positives you’ve outlined in the prepared remarks, including the Columbia rate case, increasing gas demand forecast, improving IRRs and improved visibility on growth projects since you outlined the target at the Investor Day.

Sean P. O’Donnell: Yes, Aaron, it’s a good question. A couple of parts to that. Look, the back half of our guidance this year is fundamentally underpinned in our confidence to execute on a lot of these emerging trends that Tina just talked about. So look, it’s still a little bit early. We’re very confident in that 11.7% to 11.9% range. We have a handful of rate cases in flight this year that I’m sure Tina could talk about. And importantly, and what Francois mentioned in his Slide 8, that IRR slide, what you’re seeing right now in terms of ’25 EBITDA performance, this is really the vintage of projects we’re bringing online right now were sanctioned 2 and even 3 years ago. So when you look at that slide and see the projects we’re sanctioning now and kind of the 12% range, it will take 2 or 3 years for them to come online.

So we want to give it just a little bit more time for these projects to season and for the backlog projects to kind of get up and running from a sanctioned basis. We’ll have more for you on that in the fall with a fully detailed long-term plan update.

Aaron MacNeil: Fair enough. Francois, this one is probably for you. The recent Alliance settlement is top of mind for investors, and that sort of got me thinking about if other Canadian pipeline assets may experience sort of negative toll revisions in the future. I can appreciate that you can’t directly link Alliance with the Canadian Mainline, and I’d like to get your perspective on the differences. But the asset does generate an ROE in excess of stated ROE due to the incentive sharing mechanism, and that’s obviously benefited from meaningful volume growth over the settlement period. With that settlement expiring at the end of ’26, do you think we’ll see a resetting of the sort of revenue and cost assumptions embedded in that sharing mechanism?

Francois Lionel Poirier: Yes. Perhaps I’ll start, Aaron, and I’ll ask Tina to provide some additional detail. And I’ll just focus on sort of the macro backdrop across our whole Canada gas network. We did a capacity expansion on the mainline last year for the first time in many, many years. Every time we run an open season, either on NGTL or the Mainline, we get very robust subscriptions for our service at full rates. When you look at our settlement on NGTL as an indication, we got accelerated depreciation to allow us to get a return of capital more quickly, but that was in exchange for adding capacity. So fundamentally, our system being the incumbent system in Canada to transport WCSB natural gas to all markets needs to expand in order for producers to have access to other markets.

We are their distribution channel. So it’s not really an apples-to-apples comparison, and I don’t really see any concern or potential for us to have downward pressure in returns. But over to you, Tina.

Tina Veronica Faraca: Yes. Thanks, Francois. Through our customer and regulator, we worked very collaboratively to get the approval of the 2021 to 2026 mainline settlement. And as part of that settlement, we had incentive sharing mechanisms. That has resulted in significant optimization of our operations, and we’ve realized value through those efforts, including the fact that we’ve had very strong system flows, which have resulted in lower tolls for our customers. It’s been a real win-win, and that has driven commencement returns for the mainline. So as we look forward to post 2026 settlement discussions, we’re going to look to carry forward elements of this approach with the goal of maximizing return of and on capital in our business while continuing to provide competitive tolls for our customers.

Operator: The next question comes from Jeremy Tonet of JPMorgan.

Jeremy Bryan Tonet: Just wanted to pick up a bit on the visibility into a steady cadence of project announcements in the back half of ’25 and into ’26 here. And wanted to dial in a little bit more in Pennsylvania here, given the recent Pennsylvania Energy and Innovation Summit. It seems like your pipelines are nicely positioned around some of those assets there. I was just wondering if you could elaborate a bit more, I guess, on TRP’s ability to maintain or gain market share as far as logistics opportunities in that area based off announcements at that summit.

Francois Lionel Poirier: Thanks, Jeremy. I’ll start and Tina will provide some detail. I’ll just focus on the macro picture here. As I mentioned in my prepared remarks, we’ve seen an increase in our long-term forecast of natural gas demand growth out to 2035 from 40 Bcf a day to 45. You see the Pulaski and Maysville capacity increases despite the fact that those projects were sanctioned last year. Essentially, what’s happening is when a utility or a data center developer announces energy supply, it’s attracting other demand to that location. And that dynamic is going to manifest itself not only in those two projects, but you could potentially see us upsizing other projects that we’ve recently announced over the coming months. So just a really good picture in terms of our ability to be competitive. And as to Pennsylvania and the Appalachian Basin in general, I’ll pass it over to Tina.

Tina Veronica Faraca: Thanks, Francois. Our assets sit on top of some of the largest demand centers in North America and — whether that’s data centers, power demand or the like. So that really gives us optionality across our footprints. I won’t speak to any specific projects in Pennsylvania, but we do have a number of conversations underway. Those are continuing to progress well. We currently have, as we talked about earlier, over 30 conversations with data center developers across the entire value chain. And our primary focus is going to be working collaboratively in the U.S. with our utility or LDC customers where we see we have the most alignments with the long-term trends. Really, our job is to take this significant opportunity set and select high-grade projects that deliver compelling returns in the 5 to 7x build multiple with long-term contracted cash flows.

And that discipline is really paying off, and we’ll continue to see that as we progress more projects, whether it’s in Pennsylvania or other places.

Jeremy Bryan Tonet: Got it. That makes sense. And then I think TRP has shown a good ability to reduce capital in projects coming under budget there. I’m just wondering if you could talk about the ability to, I guess, to continue doing that in the future, how you think about that? And really want to hear more of your thoughts on the incremental ability to add projects as this opens up balance sheet capacity and how you think about that?

Francois Lionel Poirier: Jeremy, it’s Francois. I’ll take that one. It’s — I think our performance on project execution demonstrates a huge focus within the organization on achieving project execution excellence. That comes with better preparation, deploying more development capital at risk prior to sanctioning so that we have — we’re able to deliver outcomes consistent with Board approval and what we’ve communicated to the marketplace. And we expect that to continue. I think the thing to make note of here is that if you look at our forward pipeline, it is nothing but brownfield in-corridor expansions. And the average size of our projects is down to around $450 million per project. And our performance this year in terms of bringing them in under budget is a good indication of that.

We look at the projects that are midstream for going into service in ’26 and beyond. Our performance is tracking to sort of a similar outcome. Part of the reason why we’re seeing improved returns in that 12% unlevered after-tax range this year is because there’s more competition for our capacity. The industry only has a finite amount of expansion capacity available on a brownfield basis, and there’s an increasing number of customers pursuing that. So that places more negotiating leverage in the hands of the pipeline companies. And I would say, as we look at our forward pipeline, not only the $30-plus billion that’s been sanctioned, but the next wave, the next $30 billion beyond that, we feel we have the ability to do the vast majority of that with brownfield expansions and not really looking to any large greenfield projects.

So the dynamics are just very positive for us right now.

Operator: The next question is from Theresa Chen of Barclays.

Theresa Chen: On the heels of these positive developments, with the significant milestone of SGP now being in service and collecting tolls even 1 month earlier than previously anticipated, plus solid performance across the business in general and financial discipline and organic growth. Can you give us an update on the path forward to get to your 4.75 deleveraging target?

Sean P. O’Donnell: Theresa, it’s Sean. I’ll take that one. Yes, top of mind, just a couple of table setters. We’re bringing $8.5 billion of projects into service this year. This is really a peak year for us from a capital and service standpoint. We’re going into our $6 billion to $7 billion range from here forward. So we’re at a peak kind of delivery this year at $8.5 billion. We’re also at our peak leverage. I think we’ve been pretty clear that 2025 will be in the 4.9 range in large part due to SGP, right, kind of only really getting a half years’ worth of cash flow out of that. So it’s really full year 2026 that we talked about in our prepared remarks that we are on track for our 4.75 in large part due to the 10 projects that Francois highlighted all coming into service by the end of 2025 and then converting to cash flow and organic deleveraging over the course of 2026. But to be clear, our 4.75 leverage is absolutely part of the long-term plan.

Theresa Chen: On Mexico, seeing that the past two administrations have prioritized expanding gas supply to the Southeast, namely the Yucatan Peninsula, but Northern Mexico seemingly also has a dire need for additional capacity, especially after 2030 when the legacy domestic production is expected to decline more sharply. You have assets that span multiple regions within Mexico. Curious to hear what is your outlook for utilization, understanding that the capacity by and large part is spoken for. But for utilization and growth for this set of infrastructure as your assets service these unique drivers of regional demand there?

Francois Lionel Poirier: Yes, Theresa, it’s Francois. I’ll take this one. Our assets in the northern part of Mexico are those that have been in service the longest, 10-plus years. Mexico has been very forward-looking in terms of anticipating growth and capacity. But you’re quite correct. The utilization rates on our assets in the north have steadily gone up. And we are at the stage now where we, along with our very important customer, the CFE, need to be thinking about expansions. The good news is for expansions of those systems, they’re relatively capital efficient. Really, they’re just about compression increases. And so any capital required to increase throughput there would be fairly modest in nature. We will, however, balance that with the need to make sure that the percentage of our EBITDA coming from Mexico is along the lines of our long-term direction.

So balancing those two, there are some growth opportunities for us in the northern half, as you said. But I think since there are only really compression additions and maybe some minor looping, we don’t think that it will really stress increasing amounts of capital allocated in Mexico.

Operator: The next question comes from Maurice Choy of RBC Capital Markets.

Maurice Choy: Maybe just focusing a little bit on Canada here. I just wanted your updated macro view of the Canadian energy policy landscape. Bill C-5 has obviously become law and your views of the path forward for what we may see across the space, including at TC Energy, fully recognizing that the lion’s share of your discretionary capital will still flow to the U.S.

Francois Lionel Poirier: Thanks, Maurice. It’s Francois. I’ll take this one. Look, Bill C-5 is definitely a positive from our perspective. I think it’s nice to see a federal government that understands the sense of urgency around deploying capital to help make Canada an energy superpower. In our interactions with the federal government, we believe very much that, that is a sincere objective on their part. We will benefit from that, we believe, if LNG Canada sanctions Phase 2 of — the Phase 2 expansion of that — at that site with a doubling of throughput capacity on CGL. Our obligation there, again, is to work with them to provide a bona fide estimate to factor into their FID process. We’re nearing the final throes of doing that, and that will be factored into their assessment on their own time line.

With respect to other infrastructure around the country, I think there’s a much better appreciation for the role that natural gas is going to play in terms of increasing the role Canada can play in reducing the world’s emissions. I’ve spoken publicly about the fact that I believe there’s a huge potential for Canada to be the largest exporter of LNG to Asia and that, that could create up to $75 billion incremental GDP for the country. The provinces appear to be supportive. The policy support now appears to be there. And so it’s up to Canada, the provinces, indigenous communities and the private sector to get out there and send the message to international markets that Canada is open for business again.

Maurice Choy: Understood. And just finishing off on the U.S. data center and new project seen. I know in your prepared remarks, you mentioned that several customers have indicated potential of requiring a greater capacity than originally planned. Can you elaborate a little bit more on that and what customers are asking — they request materially changed from your last conference call? I fully recognize you’ve not changed your messaging on the timing of new projects, but just curious how the customers are — customer discussions are going.

Tina Veronica Faraca: Maurice, this is Tina. I’ll elaborate on that a bit. As we talked about with our Pulaski and Maysville project that we sanctioned last year, as we’re starting to develop those projects, there’s continued growth on the power generation sector that is driving some of our customers to want to plan for greater capacity as they continue to see that power generation requirement grow. So those are great examples of how we’re in process and then have been asked to “upsize” the facilities for additional projects that they’re seeing behind their service territories. Other examples, you may remember, last year, we had — earlier this year, we were looking at a project in Wisconsin that was a bit delayed. And that project was in the process of looking at increased capacity as well.

And then as we’re looking down the road related to power generation, we see this robust pipeline of about 5.5 Bcf per day and $8 billion of opportunities, which include coal-to-gas conversions or data center-driven demand. And that demand continues to grow. So as we’re developing the projects, we continue to see increased needs that are causing us to, in some cases, add additional facilities before we’re able to sanction those projects.

Operator: The next question comes from Rob Hope of Scotiabank.

Robert Hope: Maybe continuing on the data center theme. So it does appear that we’re seeing the size of the data center campuses getting larger. How is that getting reflected in the project pipeline? Are we seeing some consolidation of projects? Or in aggregate, are we just seeing larger projects overall with the same number? And I guess, could this also result in project sizes above the average of 450 that you just mentioned?

Tina Veronica Faraca: Thank you, Rob. I’ll take that question. This is Tina. We’re seeing several demand drivers in addition to just data centers when you think about power generation. And in the U.S., in particular, you’ll recall that our strategy is to primarily work with our utility companies to support the power gen behind their systems. So as we look at those opportunities, they may include coal to gas, they may include a general electrification, they may include data centers. So a lot of our utility customers are looking at this in a much more aggregated fashion related to how much power they need to serve these loads. That’s working really well for us because then we’re able to put sizable projects together that are not just specific to an individual data center. It’s more for general power generation demand. And we are going to continue to see a cadence of those type of opportunities in the second half of ’25 and ’26.

Francois Lionel Poirier: And Rob, it’s Francois. Just to add to that, sort of the second part of your question, yes, we definitely could see projects getting larger than otherwise or originally planned. But in many instances, what that means is you go from a 30-inch pipe to a 36-inch pipe. The complexity of the project doesn’t really increase dramatically. And — for instance, a 25% increase in capacity throughput does not necessarily imply a 25% increase in the capital cost if it’s just a larger diameter pipeline. So while the projects are trending to get a little bit larger, it does not mean that the complexities also increasing.

Robert Hope: Appreciate that. And then maybe on a longer-term theme, here in Ontario, we’re seeing, I would say, continued or increasing support for nuclear. When we think about Bruce C, and I know it’s a number of years out, but what are kind of some of the key milestones we should be looking for over the next couple of years on that project?

Greg Grant: Yes. Thanks, Rob. It’s Greg Grant here. Maybe just to start with, one of the things that we’re very excited about, certainly, whether it’s Bruce or OPS, we did have the recent publication from the Ontario government on the integrated energy plan. And I just want to highlight that when you look through that document, it talks about affordability, security, reliability and clean energy. And I happen to know two projects that do that with Bruce C and OPS. So we’re very happy with the progress of both of those projects, having both the Ontario and federal government support there. With Bruce C in particular, we continue to progress with the federal dollars that were given to us, the $50 million. We’re looking at various environmental reviews, archaeological and really, it goes towards site preparation and continuing on some of the engineering work.

So we’re going to continue to progress that work. I just would add that it still is fairly early. Like when you think about the work that goes into building a Bruce C, it’s going to continue on until the end of the decade, and you shouldn’t expect an FID on that until early 2030. But you will see also in the early 2030s, Francois mentioned in the remarks, almost a doubling of EBITDA just from the existing work that we’re doing. So some great work from the team and looking forward to progress Bruce C.

Operator: The next question comes from Ben Pham of BMO.

Benjamin Pham: A couple of questions. Can you update us on the status or success of shoring up that $6 billion to $7 billion through the 2030 time frame? I’m thinking specifically the 2026 wedge and also any comments on those elevated years 2 years beyond that.

Francois Lionel Poirier: Yes, Ben, it’s Francois. I’ll start and invite Sean to add some comments. As we talked about last year, looking out to 2030 in terms of unallocated capital, we had about $8 billion of room remaining. We’ve done a good job actually starting to fill that $8 billion. And when we look at our forward pipeline, we certainly expect that we’ll be able to fill that up by the end of 2026 for all of the thematic reasons that we’ve expanded upon on this call. But Sean, anything you want to add there?

Sean P. O’Donnell: Very little. Ben, We monitor the white space, we’ve worked off probably 1/3 of that just in the last 6 months relative to Investor Day, and it’s is really this dual track process, $6 billion for at least the next 2 years so that the balance sheet and the pipeline both get to kind of work in the way that they both need to. So we’re capturing the growth on these 12% projects while still respecting and preserving the 4.75. So we’re going to go slow with this kind of $6 billion to $7 billion range and another at least 2 solid years of kind of execution before we really consider doing anything different.

Benjamin Pham: And this increased cadence of the data center projects or LNG, recognizing its small scale. It sounds like you sanction those projects, you’ll still be more at the $6 billion level. I’m just trying to gauge your comfort level in that $6 billion to $7 billion range.

Sean P. O’Donnell: Yes. Look, it — as you know, Ben, it takes 2 or 3 years to get regulatory approval before you put shovels in the ground. You’re making financial commitments from the time you sanction a project. But in terms of cash going out the door and being deployed for construction, which is where most of the capital goes, that only starts happening when you put shovels in the ground. And so it’s getting harder and harder to contemplate having projects with meaningful spend even in 2027, given the fact that we’re in July of 2025 already. So as I’ve said before, some of the lessons that we’ve learned from our past that have driven our project execution excellence are a respect for human and financial capacity. And first and foremost, as we look at executing a larger backlog of projects in the future, the focus will be first on human capacity.

Do we have the bench, the breadth of bench and do we have the management attention to govern over a larger capital program. So we’re going to do that very carefully and very judiciously and continue to focus on a large number of smaller projects that are brownfield and in corridor. But that sort of points you to it being challenging for us to consider a larger program really until 2028 or beyond.

Operator: The next question comes from Robert Catellier of CIBC.

Robert Catellier: Question maybe for Tina. I just wanted to follow up on the data center theme here. It sounds like from your comments that you’re really focusing on serving the LDC customers and sticking to brownfield and pipeline expansions. But what’s your view on pursuing behind-the-meter power?

Tina Veronica Faraca: Rob, I’ll start, and then I’m going to turn it over to Greg Grant. But as we’ve stated in the past, our strategy in the U.S. is to work with our utility customers to serve data center load, given that there’s additional load typically from a portfolio perspective that they’re trying to serve with power gen. And then we have an attractiveness and depth of our portfolio by doing this. It provides us a low-risk compelling return approach to capturing data center growth, and we can proceed with build multiples in the 5 to 7x range. In select instances, we’ll be looking at direct connections to data centers where there’s utility service limited. But again, that would need to be in the 5 to 7x range with low risk. From a behind-the-meter perspective, there are opportunities that we would be considering in Canada, given the different construct there. I’ll turn it over to Greg to walk through that.

Greg Grant: Sure. Happy to comment on that, Tina. Just that we are open to opportunities and having many conversations where we can leverage our experience and capabilities in that complementary solution, we talked about a couple of quarters ago on both the gas and the electron side. And I think in Alberta, we do have that strategic footprint. We do have the gas storage. We have power assets. We have renewables. We have — on the co-gen side. So we have a great footprint to work from. I would just add, we will be very thoughtful and selective in that approach. We do know that we’ll have to compete for capital, and we’re working with our customers here on some win-win solutions that you can actually bring some capacity on quite quickly. But obviously, they have to compete. And we think with that footprint, we can get competitive risk-adjusted returns to compete with some of the great projects that Tina has been bringing forward.

Robert Catellier: Okay. And then just wondered maybe a question for Sean here. What are the practical impacts of the budget reconciliation bill, the One Big Beautiful Act (sic) [ One Big Beautiful Bill Act ] in the U.S. on your project pipeline as well as cash taxes.

Sean P. O’Donnell: Yes, Rob, the short answer is not much. We’re a regulated service provider, right? We don’t get the benefit of bonus depreciation. But on the flip side, we also don’t get the interest limitations that unregulated folks do in the U.S. So it’s pretty good for our customers, right? We’re bringing new unregulated capacity online. And what you’ve heard Tina and Francois and Greg talk about today is, I think, only going to get better from the Big Beautiful Bills. We’re an indirect beneficiary of it.

Francois Lionel Poirier: One point I’d like to add, Rob, it’s Francois, is our EBITDA guidance long term, our — the execution of our growth plan is not reliant on any prospective reform, permitting reform or concessions or stimulus in the bill you referenced. It’s based on the status quo. So any improvements that come prospectively will simply either improve time lines or improve returns from what’s stated in our guidance.

Robert Catellier: Okay, great. That’s the perspective I was looking forward, thank you.

Operator: The next question comes from Olivia Halferty of Goldman Sachs.

Olivia Grace Halferty: I wanted to start on the multiyear growth plan on NGTL, specifically that today’s announcement brings total commitments under the plan to roughly $700 million within the plan’s $3.3 billion framework. Could you share how we should think about the cadence of project announcements from here in order to add 1 Bcf a day of capacity by 2030? And secondly, how do you think about allocating capital towards NGTL under this framework versus pursuing, let’s say, incremental U.S. gas projects with potentially higher returns?

Tina Veronica Faraca: Thank you, Olivia. I’ll take the question, and then I’ll pass it over to Francois for any additional comments. The multiyear growth program obviously was completed as part of a multiyear settlement we have on NGTL. And as we are evaluating the need for egress, we’ll continue to have a cadence of how those projects will be supported. We have recently announced the Program 1 and Program 2, and we’ll continue on a cadence through the next several years. Nothing really prescriptive about that, but the opportunity will be there to continue to provide egress from that. We were able to procure that opportunity set through that settlement that gives us opportunity to earn more than we would otherwise. And so the criticality for us is to continue to be able to provide egress from the basin, and we have a solution for that with this program.

Francois Lionel Poirier: And to add to that, Olivia, and by the way, the capital spend for the multiyear growth program is back-end loaded in the 5-year period. The first two waves that we’ve sanctioned are fairly modest in size, as you referenced. In terms of capital allocation going forward, and we are going to honor our commitments, obviously, to our customers in Canada, very important customers. Part of the settlement was for a commitment on our part subject to board sanctioning of each individual project is to increase — meaningfully increase egress from the basin. Beyond that, however, Canada gas has to compete for capital with the other business units in the company. And currently, the risk-adjusted returns in the U.S. are meaningfully higher than in Canada.

So for our discretionary capital, you can expect that we are going to be allocating capital predominantly in the U.S. as and until competitive projects in other jurisdictions present themselves that compel us to allocate capital elsewhere.

Olivia Grace Halferty: Got it. That’s clear. Appreciate the color there. Maybe a second question for me. I wanted to touch on the willingness to lean into partnerships on future projects as discussed last quarter, which could allow TC to capitalize on the numerous project opportunities across the footprint while managing capital requirements. Could you frame up, first, your willingness to pursue projects with partners versus pursuing projects independently? And second, where partnership opportunities are most interesting across your current footprint? And then maybe last, zooming out, how might partnership opportunities compare and contrast in the different business segments like U.S. versus Canada gas or power?

Sean P. O’Donnell: Olivia, it’s Sean. Let me take that question generally, and maybe I’ll pass it over to Greg to talk about some of the past partnerships. Look, as Francois mentioned, our average project size is $400 million to $500 million, and its brownfield on our current systems. We do not need partners for projects of that type. That being said, right, as part of our capital efficiency, capital rotation partnership, always looking for partners that can either add value through capabilities, through cost of capital. But by and large, on our brownfield strategy, we’re perfectly well suited and capitalized to prosecute most of that, if not all of that. I would tell you on maybe some of the larger projects, maybe, Greg, particularly in [indiscernible], if you want to talk about how we think about some of the JV opportunities there.

Greg Grant: Sure. No, happy to. I think that there’s plenty of opportunities strategically to bring in partners. I think there’s a strategic in the capability’s perspective in financial. Obviously, when you look at in OPS, we’re working quite closely with the SON, Saugeen Ojibway Nation as equity partners. We have numerous partners when you think about CGL. We’re partners with OMERS on Bruce. And — so I think there’s plenty of opportunities where we will look strategically for partnerships and JVs, and we’ve been quite successful in prosecution and execution of those.

Operator: The next question comes from Burke Sansiviero of Wolfe Research.

Burke Charles Sansiviero: Just curious if you’ve met with S&P since you’ve received payment on Southeast Gateway. Just any thoughts on when you think they might deal with a very long 29-month negative outlook.

Sean P. O’Donnell: Burke, it’s Sean. I’m happy to take that one. Look, let me just say we’re in constant contact every quarter, every agency and they kind of move through their review cycles, obviously, independent of one another. So without speaking specifically about any recent conversation, that report has been 29 months, as you say. S&P was pretty clear in that February report as to what they were looking for this year. SGP obviously coming online on time and under budget was an important one. And the second element of the conversation with the S&P team and candidly, all of the agencies was maintaining the capital discipline and the project delivery kind of 5 to 7x. We’ve done everything that we said we were going to do. We’ve completed everything that the agencies kind of had on their watch list. So as it relates to each agency’s review period from here towards probably the fall, I’m not at liberty to say it, I don’t know. So we stay in constant contact.

Operator: Ladies and gentlemen, this concludes the question-and-answer session. If there are any further questions, please contact Investor Relations at TC Energy. I will now turn the call over to Gavin Wylie.

Gavin Wylie: Thank you, and thanks, everybody, for participating this morning. As the operator mentioned, if we didn’t get to your question today, please do contact the Investor Relations team. We’re always happy to help. And of course, as always, we appreciate your interest in TC Energy and look forward to our next update that’s likely going to be early November. Enjoy the rest of your summer. We’ll see you soon.

Operator: This brings to a close today’s conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.