Enbridge Inc. (NYSE:ENB) Q3 2025 Earnings Call Transcript

Enbridge Inc. (NYSE:ENB) Q3 2025 Earnings Call Transcript November 7, 2025

Enbridge Inc. misses on earnings expectations. Reported EPS is $0.33 EPS, expectations were $0.39.

Rebecca Morley: Good morning, and welcome to the Enbridge Inc. Third Quarter 2025 Financial Results Conference Call. My name is Rebecca Morley, and I’m the Vice President of Investor Relations and Insurance. Joining me this morning are Greg Ebel, President and CEO; Pat Murray, Executive Vice President and Chief Financial Officer; and the heads of each of our business units: Colin Gruending, Liquids Pipelines; Cynthia Hansen, Gas Transmission; Michele Harradence, Gas Distribution and Storage; and Matthew Akman, Renewable Power. [Operator Instructions] Please note, this conference call is being recorded. As per usual, this call is being webcast, and I encourage those listening on the phone to follow along with the supporting slides.

We will try to keep the call to roughly 1 hour. And in order to answer as many questions as possible, we will be limiting questions to one plus a single follow-up if necessary. We’ll be prioritizing questions from the investment community. So if you are a member of the media, please direct your inquiries to our communications team, who will be happy to respond. As always, our Investor Relations team will be available following the call for any follow-up questions. On to Slide 2, where I will remind you that we’ll be referring to forward-looking information in today’s presentation and in the Q&A. By its nature, this information contains forecast assumptions and expectations about future outcomes, which are subject to risks and uncertainties outlined here and discussed more fully in our public disclosure filings.

We’ll also be referring to non-GAAP measures summarized below. And with that, I’ll turn it over to Greg Ebel.

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

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

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

We’re still on track to sanction Mainline optimization Phase 1 this quarter and Phase 2 next year, and we’ll get into more details on those projects during the business update. Over the quarter, we added $3 billion of new growth capital to our secured capital program, showcasing continued execution on the commitments we laid out last Enbridge Day. In liquids, we sanctioned the Southern Illinois Connector, adding incremental egress out of Western Canada and providing a new long-term contracted service to Nederland, Texas. In Gas Transmission, we sanctioned expansions of our Egan and Moss Bluff storage facilities to support the LNG build-out along the U.S. Gulf Coast. And in the deepwater Gulf, we’re expanding our previously approved Canyon system to provide transportation services for bp’s recently sanctioned Tiber Offshore development.

And earlier in the quarter, we sanctioned the Algonquin Gas Transmission enhancement project in the U.S. Northeast as well as the Eiger Express gas pipeline out of the Permian. And finally, we have advanced a joint venture with Oxy to develop the Pelican CO2 hub in Louisiana. These projects demonstrate the competitive edge from our all-of-the-above approach and our ability to meet growing energy demand across all parts of our business. Now let’s look at our value proposition and recap our year-to-date execution before diving into the business updates. Enbridge’s low-risk model continues to deliver superior risk-adjusted returns in all economic cycles. Our cash flows are diversified from over 200 high-quality asset streams and businesses that are underpinned by regulated or take-or-pay frameworks.

Over 95% of our customers have investment-grade credit ratings. We have negligible commodity price exposure and the majority of our EBITDA has inflation protection. All of this results in Enbridge’s industry-leading total shareholder return while maintaining lower volatility compared to peers and broad index constituents. Looking ahead, Enbridge’s utility-like business model remains well-positioned and policy support for new investment in critical projects is improving, creating a business environment that incents coordination, dialogue, and growth. And I’m very pleased with how the team continues to grow the business and excited by the opportunities ahead for Enbridge. With that said, let’s jump into the business unit updates, starting with Liquids segment.

Mainline volumes had another strong quarter, delivering a record 3.1 million barrels per day on average for Q3. The system was a portion for the entire quarter, reflecting continued strong demand for Canadian crude and the need for reliable egress out of the Western Canadian Sedimentary Basin. Given the continued strong demand for the Mainline this year, we expect to reach the top of the performance color ahead of when we initially anticipated. This is a great sign for us and our shippers. We’re achieving the maximum allowable returns under the mainline tolling settlement, delivering competitive value to our shareholders and our alignment with customers incentivizes us to move the increased volumes and provide them with access to the best markets.

This leads in well to mainline optimization projects that I’ll discuss shortly here, in addition to the previously announced projects like Mainline capital investment. In the U.S., we sanctioned the Southern Illinois Connector project, which is backed by long-term contracts for full path service from Western Canada to Nederland, Texas. Once complete, the new pathway will add 100,000 barrels per day of contracted full path capacity to the U.S. Gulf Coast via a 30,000 barrel increase per day on Express-Platte system, 56 miles of new pipeline between Wood River and Patoka, and utilization of 70,000 barrels per day of existing capacity on the Spearhead Pipeline. Looking ahead at additional egress projects, we are continuing to advance approximately 400,000 barrels per day of incremental capacity to the best refining markets in North America via mainline optimization Phase 1 and 2.

MLO1, which will add 150,000 barrels per day of incremental egress is entering the final stages of customer approvals. and we are still on track to make FID this quarter and place the project into service in 2027. MLO2 has made significant progress as well, and that project could now add another 250,000 barrels per day of additional capacity in 2028. This second phase of mainline optimization will utilize capacity on the Dakota Access Pipeline, and we’re happy to announce that we’re teaming up with Energy Transfer to make that happen. So stay tuned for more on MLO2, including an open season announcement early in the new year. Relative to potential greenfield projects that would require significant energy policy change, these brownfield opportunities offer the quickest and most cost-effective way to adding close to 500,000 barrels a day of capacity to satisfy the near-term production increases forecasted out of the basin.

Finally, for liquids, we added the Pelican sequestration hub to our backlog, a project in Louisiana, which will provide transportation and sequestration for 2.3 million tons per year of CO2 and is underpinned by 25-year take-or-pay offtake agreements. We will partner with Occidental Petroleum to advance the hub with Enbridge managing the pipeline infrastructure, while Oxy develops the sequestration facility. Now let’s turn to our gas transmission business. This quarter, we’ve sanctioned an additional capital-efficient connection to our Canyon pipeline system to support bp’s Tiber development in the deepwater Gulf. Originally announced last October, the Canyon system will transport both crude oil and natural gas under long-term contracts with the Tiber system expected to cost USD 300 million, taking the total Canyon pipeline development to about USD 1 billion and entering service in 2029.

In the U.S. Northeast, the AGT Enhancement will increase capacity of the Algonquin pipeline, providing additional natural gas to the critically undersupplied U.S. Northeast, serving local utility demand and reducing winter price volatility. That project is expected to cost USD 300 million and enter into service in 2029. Switching over to the Permian. The Eiger Express Pipeline is a 2.5 Bcf a day Permian egress development running adjacent to the operating Matterhorn Express system and is now sanctioned and expected to enter into service in 2028. Since our initial 2024 investment in the Whistler joint venture, which holds these pipelines, we have invested $2 billion in operating assets and sanctioned another $1 billion of capital expected to enter service through 2028.

Also in the Gulf region, we’ve sanctioned two natural gas storage expansions to support the market, which continues to tighten due to increased LNG, Mexican exports, and regional power demand. Egan and Moss Bluff storage systems, both salt caverns with exceptional connectivity and withdrawal rates are being expanded to offer a combined 23 Bcf of incremental capacity. We expect to invest approximately $500 million in these facilities at 5 to 6x EBITDA builds and come into service in phases through 2033. It’s worth taking a moment to dive a little deeper into the growing North American storage market and how we are positioned to serve our customers. Between Moss Bluff and Egan as well as the expansion of Aitken Creek announced last quarter, Enbridge is now set to add over 60 Bcf of new natural gas storage directly adjacent to the major LNG centers in North America.

These expansions will come in a timely manner as there is over 17 Bcf per day of additional LNG-related natural gas demand expected to enter service by 2030. This demand dramatically shifts supply economics and increases the importance of strategically located storage capacity. We are connected to all operating U.S. Gulf Coast LNG terminals and continue to invest heavily in infrastructure to enable the future growth of North American LNG. To date, we have sanctioned over $10 billion in projects with direct adjacency to operating or planned export facilities. There is a growing storage deficit across the U.S. Gulf and British Columbia coasts and having existing assets with the opportunity to execute brownfield expansions is incredibly valuable to our customers and investors.

Through acquisitions and expansions, we have positioned ourselves as an industry leader in the storage space. With more than 600 Bcf of storage across our North American businesses, we can strongly support our customers as they continue to build out North America’s LNG capacity and navigate the overall power demand growth we are expecting in the future. Now let’s spend a few minutes recapping all the work we’ve done in Gas Transmission segment since Enbridge Day earlier this year. At our Investor Day in March, we shared Enbridge’s $23 billion gas transmission opportunity set, noting the potential to FIT up to $5 billion in projects within 18 months. This opportunity set has grown since then. And today, a little over 6 months later, we’ve already announced over $3 billion of new projects across our footprint, serving all pillars of natural gas demand growth, including reshoring, LNG, coal-to-gas switching and data centers.

With over 23 Bcf a day of new gas demand coming online by 2030, critical investment will be needed to ensure reliable service for customers. And with this list here, you can see we are doing our part, deploying capital to meet the significant increase in natural gas demand across North America regardless of the end-use market. Now let’s turn to our gas distribution business. The GDS segment is yet another way for us to capitalize on power demand theme. We’ve seen data center and power gen opportunities continue to be a tailwind for the segment with over 50 opportunities that could serve up to 5 Bcf a day of demand, including almost 1 Bcf per day of demand for already secured projects. During the quarter, we also reached positive rate settlements with two of our U.S. utility regulators, which are currently being reviewed for final approval.

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

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

Patrick Murray: Thanks, Greg, and good morning, everyone. It’s been another strong quarter across all four business units, thanks to continued high utilization of our assets as well as recent acquisitions. Compared to the third quarter of 2024, adjusted EBITDA is up $66 million, DCF per share is relatively flat and EPS is down from $0.55 to $0.46 per share. The decrease in EPS is primarily due to the profile change associated with our gas utilities, where Q3 tends to be a softer quarter for EPS as EBITDA is seasonally lower, but items such as interest and depreciation remained flat quarter-over-quarter. In Liquids, despite the strong mainline volumes, contributions from the Mid-Con and U.S. Gulf Coast segment are tracking lower due to tighter differentials and strong PADD II refining demand.

In Gas Transmission, we experienced a strong third quarter with favorable contracting and rate case outcomes on our U.S. gas transmission assets and contributions from the Venice extension and the Permian joint ventures we added since last year. The Gas Distribution segment is up relative to last year, thanks to a full quarter contribution from Enbridge Gas North Carolina as well as benefit of the quick turn capital we experienced within our Ohio utility. In Renewables, results were up from last year with higher contributions from our wind assets and from the Orange Grove solar facility recently placed into service. Higher financing and maintenance costs from the acquisition of the Enbridge Gas North Carolina assets kept DCF per share relatively flat year-over-year.

I’m pleased to once again reaffirm our 2025 guidance and growth outlook across all metrics. Our resilient business model positions us to deliver strong and predictable results through all cycles. We remain confident we will achieve full year EBITDA in the upper half of our guidance range of $19.4 billion to $20 billion, but don’t expect to exceed the top of the band. As we mentioned on previous quarterly calls, due to higher interest rates, particularly in the U.S., we continue to expect DCF per share at the midpoint of our $5.50 to $5.90 per share guidance range. Mainline volumes, FX rates, and the acquisition of an interest in the Matterhorn Express Pipeline earlier in the year continue to be the tailwinds to the full year guide. This is partially offset by higher interest rates, along with tight differentials and strong PADD II refining levels, which are expected to continue into the fourth quarter and thus have been reflected as an additional headwind relative to our assumptions heading into the year.

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

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

Gregory Ebel: Thanks very much, Pat. It was indeed a busy quarter on the growth capital side, and I’m extremely pleased with the progress we’ve made since Enbridge Day in March. The North American energy landscape continues to evolve with energy demand driven by LNG development, power generation, data centers and baseload growth. Enbridge will continue to play a pivotal role in that growth within a disciplined framework that delivers consistent long-term shareholder value. Our low-risk utility-like business with predictable cash flows is underpinned by long-term agreements and regulatory mechanisms that has allowed us to increase our dividend for 30 consecutive years across a wide range of economic cycles and conditions. Going forward, we expect to achieve 5% growth through the end of the decade, supported by our $35 billion in secured capital.

Our scale offers optionality that few in our industry possess, and we’ll continue to evaluate accretive investments across our footprint. Lastly, I’ll just point out one housekeeping item. As has been typical, we intend to issue our ’26 guidance for investors in early December. So please watch for that announcement on December 3. With that, I’ll open the call to questions.

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

Q&A Session

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

Michele Harradence: Sure. So it’s Michele Harradence here, Spiro, and happy to discuss that. And I would say we’re seeing it across the board. I mean that’s the real value of the diversity of the utilities we have. So — when we look at about the projects that make up that 7 Bcf or so of data center opportunities that we’re talking about, we divide that aspect into what I’d call our baseload demand, our data centers itself and the coal to gas. So it’s a lot about power generation. It’s the electrification tailwind that we’ve talked about. So you could bucket that, I would say, the baseload demand is there in Ontario, it’s there in Ohio, it’s there in Utah, data center growth, lots of early-stage developments in Ohio and Utah in particular.

I would say we’re seeing up to 8 gigawatts between the two of them. And that’s some of the early-stage developments we’re seeing. And then the mid-stage stuff, we’re estimated to be serving over 6 gigawatts in those two jurisdictions alone. And Ontario has a lot of growth as well. And then finally, coal-to-gas conversion, again, to support power generation would be in North Carolina. But really, when we look across all the capital opportunities we have for GDS, that’s maybe 20% of what we’re looking at is the data center and power generation opportunity. I mean just the good standard core utility growth, leveraging our modernization program, still lots of opportunity there. We’re seeing a lot of what I’d call major projects. We just put our Panhandle regional project into service.

That’s close to $360 million in Southwest Ontario. We have our Moriah Energy Center, the LNG plant in North Carolina. We have 215 Phase 1 and 2 in North Carolina. That’s — those two combined are USD 1.2 billion alone. We’re doing a reinforcement project in Ontario up in Ottawa. That’s another $200 million. I mean, there’s a lot of growth and opportunity going on in the utilities. And then our residential growth, although it softened in Ontario, continues to be strong in places like North Carolina and Utah, where there’s a lot of folks coming. And finally, we’re looking at our storage opportunities, and there’s a good chunk of our capital that continues to go to storage for us. So a good suite of capital there, but hopefully, that answers your question.

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

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

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

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

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

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

Colin Gruending: Yes. I think — I don’t know that it’s an acceleration here per se. I think it’s being game on here for a while here. And I think the Canadian basin, as Greg was saying, is it turns out relatively advantaged compared to other basins. So maybe we have lost focus on it, but our customers haven’t. And we’ve been all over the fundamentals, we see that 500,000, 600,000 a day of supply growth by the end of the decade. And I think our announcements here line up with what we talked about at Enbridge Day generally. I mean, the team is working hard on this, and I’m very proud of them, the engineering and commercialization of it is very creative and trying to seize the moment. Yes, if there’s bigger policy unlocks, there could be much more upside to monetize the trillions of dollars of value up in Northern Alberta.

But even under the base case, the 600,000 a day is significant. We have, I think, consistently talked about our southbound playbook. And again, if there is an unlock much bigger, then the West solution can come into focus, kind of a companion to that unlock. But in the base case, South is where it’s at. Our customers prefer that direction, integrated business models, lots of big efficient, long-lived refineries that are very competitive and of course, less competition now from Venezuela and Mexico, inbound heavy. So Canadian Oil will gain market share in that basin. I think our solution set is unchanged. We’re proud to sanction Southern Illinois Connector. Maybe in baseball terms, that’s our leadoff hitter, and it’s now on base. We’ve sanctioned this.

This is a dual flow path, 30,000 new egress on Platte and the other 700 coming down our spearhead pipeline existing capacity, and we’re going to move that on ETCOP with our — which we partially own with our partner Energy Transfer. MLO1 is at the plate right now, and we expect to make commercializing announcement here in the next couple of months before year-end. Again, that’s 150 a day. I think that’s well chronicled. It’s capital efficient. permit light using existing pipe in a right of way. And recall, we’ve already successfully run an open season on the Flanagan South path through Seaway with our partner enterprise products. So that’s well advanced. So MLO2, continue the analogy here, I’d say is in the batter’s box. And as Pat and Greg mentioned, it’s got a bigger bat than we thought we had before.

We’ve upsized that from 150 to 250 a day. And again, similar to MLO1, existing pipe and right of way. And so again, using joint venture partners, this is all coming together nicely, not an acceleration, but I think continuing through here and hopefully get the basis loaded.

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

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

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

Patrick Murray: Yes, I think so at the end of the day, we’ve got a pretty fulsome ’26 now. We’ve reserved some capacity for these MLO 1s and 2s. I mean, 1, we’ll have some spend in ’26; 2, probably not as large as it’s a little later, but we’ll reserve some capacity given how confident we now are in those moving forward. And then as Greg said, we’re really happy to continue to build out the back part of the decade. And hopefully, that’s adding a lot of clarity into the growth that the enterprise can have. And I think it’s pretty common in our infrastructure business where you got — you have secured some capital for the next couple of years. It’s kind of close to or just below your kind of capacity in any out years you’re filling up. And I think the team has done a great job in the last 6 months of doing that. So we’re very comfortable.

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

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

Gregory Ebel: Yes. I’m not sure we are going to give you much of that right now because as you say it’s December. But look, I think — look, you’ve heard what we’ve been able to do on the gas side today with announcements. The liquid side, Michele gave you a good tour to tab on that side as well. And despite what some people have looked at, we’ve even done a number of things on the renewable power side in the last year. So I think it’s the benefit of the portfolio. And again, those secondary and tertiary benefits of everything from power demand, from policy changes, from GDP growth that actually give us that confidence, and we see growth right across the system. So if your question is, do we see pullbacks in areas? No. In fact, we see acceleration even the renewable stuff that we have, a lot of that stuff is a long ways down the trail and anything we do sanction would have already been in a good spot from a policy perspective.

So — and as Pat just mentioned, we’ve got the balance sheet capacity, internally generated cash flow to be able to meet those demands. And obviously, every dollar of EBITDA we add adds another $4 or $5 of capacity. So we’re very focused on that. So it’s probably where I’d leave it today. I don’t know, Pat, would you add anything further?

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

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

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

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

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

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

Gregory Ebel: Yes. Obviously, several areas there. And as they relate to the gas distribution side, obviously, prudency kicks in. But recall, those are rate base type driven setups, right? So you’re getting on a capital structure, call it, 10% return in the U.S. on about 50% equity. So as long as we’re being prudent, I’m not feeling too concerned about that. Now that being said, given the size of the company, we are actively and we’re out there doing that, making sure that we’ve got good alliance agreements with various contractors, giving us the best rates, actually going forward and even stockpiling, if you will, compressors and things like that. And remember, on the inflationary side, I’d say about 30% most of these large projects would be CapEx related to equipment and things like that.

So those relationships are really critical. And a lot of them, obviously, we’re avoiding tariff structures through contract mechanisms as well. So far, so good. The biggest concern I have is on the people side of things and just getting the time and equipment in place. So we’re pretty good at that. I think we feel in terms of those long-term relationships with contractors and stuff like that. But Rob, it’s something definitely we’re watching closely. It’s also why I love some of the projects that we announced today that are all relatively small, as Colin said, singles and doubles and quick cycle, relatively speaking, so that you don’t have long drawn-out processes. And then the last piece is, as you know, a better attitude with policy around permitting and acceptance of these critical projects.

And that takes a risk off the table from a CapEx perspective as well.

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

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

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

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

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

But a lot of them are relatively permit light and even not giant CapEx as individual chunks. So I just don’t see us using the major project office at this point in time.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Gregory Ebel: Yes, I think you mean Woodfibre. Cynthia can take that, right? You mean…

Benjamin Pham: Woodfibre, sorry.

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

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

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

Gregory Ebel: Yes. Ben, we’re not opportunity light. We are opportunity rich. So us taking on — I can’t see us taking on an LNG facility with commodity exposure, which is what some other folks that you mentioned have done. We’ll get done the Woodside opportunity here, and then we’ll see. Obviously, there’s a lot of water still to go under the bridge about getting things built in off the BC Coast. So let’s continue with our Woodfibre project. Sorry, I said Woodside. Now you got me saying it. The Woodfibre project before we look at other ones. And Look, you saw us announce today those storage projects are serving LNG on the Gulf Coast. Aitken is going to serve LNG in BC. A lot of the projects that Cynthia mentioned, the pipeline project, that’s the stuff we know and know very well and earn solid regulated rates of return on.

I think in this environment, that’s probably a better setup for us. So we’ll always look. We get an opportunity to take a look at everything, but I don’t think our investor proposition is open to taking on a bunch of commodity exposure. We don’t want to.

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

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

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

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

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

Gregory Ebel: Yes. Look, I think both ourselves and Oxy are pretty darn careful on this front. If this project didn’t earn at least the returns that we get from other Liquids projects, as you say, outside the Mainline, it wouldn’t have got sanctioned. So obviously, I would even argue there’s always some policy risk, so you want to make sure you get this right. So this is very much in that wheelhouse, if not a bit better. And obviously, the tax incentive structures, we’ve got a lot more clarity on that out of the OBBB bill that came out so that we know exactly what our tax incentives are on that. And it’s got a long-term 20-, 25-year contract with offtake player. So I would say returns are at least, if not a little bit better than what we’re seeing in this world. Policy support is there where it may not be for some of the other unconventional investments. And we love our partner on this front who has very similar return type parameters.

Maurice Choy: I might just add on that.

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

Maurice Choy: It’s great to hear. My — I guess, all the best to Cynthia on your retirement, and congrats to Matthew in your new role.

Cynthia Hansen: Thank you.

Matthew Akman: Thank you.

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

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

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

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

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

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

Praneeth Satish: On the Egan and Moss Bluff gas storage expansions, can you break down how much of the 23 Bcf of capacity is already committed under long-term contracts versus any shorter-term contracts or merchant capacity? And then given that you’re moving forward with the expansion, I assume pricing is favorable, much higher than historical levels. But can you provide some color on the contract durations? Is it kind of in the typical 3- to 5-year range? Or are you able to get something longer in this environment? And then I guess as a follow-up to that, like how do you think about the trade-off between locking in longer storage term contracts versus keeping them shorter so you could potentially benefit from higher recontracting rates in the future?

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

Gregory Ebel: Yes. And that 3 to 5 years, 2 to 5 years is pretty typical the way that we’ve done it historically. And look, I think we’ve got a super high level of confidence in the LNG coming in on the Gulf Coast. So that probably lets us leg into the contracts and we want to. But it depends on the location, right? Like, for example, the Aitken Creek contract, I think we took about half of that and have it under a 10-year contract. So it just depends on the situation, and it’s worked extraordinarily well. I’m glad you raised the storage question because we got 600 Bs or so across North America, all with great optionality outside the regulated piece. But we’re adding just the announcements in the last 12 months, 10% to that number. So it’s a big uptick for us at the right time in the market, and I feel very good, as Cynthia says, the way we’ll leg into this.

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

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

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

Rebecca Morley: Great. Thank you, and we appreciate your ongoing interest in Enbridge. As always, our Investor Relations team is available following the call for any additional questions that you may have. Once again, thanks so much, and have a great day.

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