Enbridge Inc. (NYSE:ENB) Q1 2024 Earnings Call Transcript

Enbridge Inc. (NYSE:ENB) Q1 2024 Earnings Call Transcript May 10, 2024

Enbridge Inc. misses on earnings expectations. Reported EPS is $ EPS, expectations were $0.59. ENB isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Rebecca Morley: Good morning, and welcome to the Enbridge Inc., First Quarter 2024 Conference Call. My name is Rebecca Morley and I’m the Vice President of the Investor Relations team. 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 and Midstream; Michele Harradence, Gas Distribution and Storage; and Matthew Akman, Renewable Power. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session for the investment community. [Operator Instructions] Please note that this conference is being recorded.

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

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

Greg Ebel: Well, thanks very much, Rebecca and good morning, everyone. Thanks for joining us with this call. I’m pleased to be here today to record financial results for the quarter, driven by strong operational performance and strong energy fundamentals. I’ll provide a quick recap for Q1 and update you on each of our businesses, and Pat will speak further to our financial performance, capital allocation priorities, and future growth outlook. And as always, the management team is here to answer any questions that the investment community has following our presentation. I’m pleased to report adjusted EBITDA is up 11% year-over-year and we’re well on our way to meeting our financial guidance for 2024. We saw high utilization rates across our systems and safety, which remains a top priority, was also excellent during the quarter.

As you know, the acquisition of East Ohio Gas closed on March 6th, which further diversifies our business, extends our growth outlook and enhances the stable cash flow profile of our asset base. As a reminder, we’ve already secured over 85% of the required financing for the U.S. gas utility acquisitions and will fund the remainder using a combination of alternatives which may include hybrid or bond issuances, capital recycling, and ATM issuances. We have the capacity to utilize any and all of these sources of funding and so that we can be in a position to optimize market conditions, you’ll see us updating and preparing security filings to preserve this funding flexibility and ensure we complete all the utility acquisition funding well in advance of year-end.

We closed the Alliance/Aux Sable divestiture in April, continuing our track record of recycling capital at attractive multiples. The mainline tolling agreement was recently approved as filed by the Canadian Energy Regulator. The mainline continues to operate at or near capacity and we are ready to add additional egress as our customers need it. We had exciting growth announcements in the U.S. Gulf Coast with our recent Whistler JV, the sanctioning of Sparta pipeline, and the acquisition of two marine docks and adjacent land at our Ingleside export facility. We’ve also recently progressed to full FID on the Tennessee Ridgeline Expansion project following the TVA’s decision to construct a new natural gas combined cycle plant in Kingston, Tennessee.

This project further underlines the criticality of pipelines in fueling lower carbon power via gas generation. Today, we published our 23rd annual sustainability report, which highlights our performance and approach to environmental, social, and governance goals. Now before I touch on these developments further, let me take a moment to highlight what really was the first rate financial performance in the quarter. Pat will be getting into this in more detail later, but we’re going to be presenting side-by-side results, those being adjusted actuals and the base business we guided against. We believe this transparency will let you see our base business against our ’24 guidance as well as the all-in results which include a partial month of owning East Ohio Gas and all our utility financings to date.

Starting with all-in, our EBITDA is up 11% and DCF per share up 4% from last year, primarily due to strong asset performance across liquids, gas transmission, and renewables as well as a partial month contribution from EOG. Our balance sheet remains well-positioned ahead of the closings of Questar and PSNC at 4.7x debt to EBITDA. Since this number is as of March 31st, these leverage numbers don’t yet include the beneficial proceeds from the sale of Alliance and Aux Sable. Touching briefly on the base business, we are very much on track with our financial guidance. In fact, our base business EBITDA and DCF per share are up both 8%, and debt to EBITDA is at 4.6x. Under both views, we’ve had a record financial quarter, and we look forward to keeping that momentum going.

Our industry leading business risk supports our long held leverage target of 4.5x to 5x. Enbridge has virtually no commodity price exposure and over 98% of our earnings are generated from either cost of service or take or pay contracted assets and 80% of our EBITDA is earned from assets with protection against inflation. And we are well hedged against interest rate volatility with less than 5% of our debt portfolio exposed to floating rates. Now let’s take a look at the notable highlights I mentioned earlier from each of our businesses starting with liquids. Liquids pipelines delivered high utilization levels once again. The mainline transported over 3.1 million barrels per day during the first quarter and we continue to expect average throughput of 3 million barrels per day for the year.

As I mentioned earlier, the Canadian Energy Regulator approved the mainline tolling settlement which we view as a win-win-win for Enbridge, our customers, and the industry. Switching gears to the U.S. Gulf Coast, we acquired two strategic docks and nearby land adjacent to Ingleside for $200 million. This acquisition will optimize existing operations in the area by increasing VLCC docking windows at Ingleside and will help set the stage for Ingleside to realize its ultimate potential as the industry leading multi products export terminal in North America. In the Permian, we’ve launched our open season to expand Gray Oak capacity by up to 120,000 barrels per day, pending a successful open season. Recently, we finished constructing four new storage tanks at Ingleside, bringing total storage capacity to 18 million barrels there.

And we’ve already sanctioned an additional five tanks to add another 2.5 million barrels of storage capacity by 2025. Now let’s take a deeper look at gas transmission. In Canada, wood fiber is progressing well, and we expect to reach the 60% engineering milestone in the second half of 2024. In the United States, we announced the formation of the Enbridge WhiteWater MPLX joint venture. This transaction will be immediately accretive to DCF per share and our balance sheet metrics and allows us to establish a natural gas footprint in the Permian Basin. The Tennessee Ridgeline Expansion project has progressed to full FID. This is the natural gas pipeline we announced a few years back that will deliver gas to the Tennessee Valley Authority’s new natural gas combined cycle plant, an emissions friendly replacement of their existing coal fired power plant.

Construction will begin in 2025 with an expected in service date of Q4 2026. We also sanctioned the construction of offshore pipelines to service Shell and Equinor’s U.S. Gulf Coast operations. Now before I discuss our strategic joint venture in more detail, let me take a moment to comment on the topic du jour [ph]. In addition to the growing demand for natural gas to feed LNG terminals, the build out of data centers and generative AI is forecasted to require a material increase in power generation. This new power generation will be fed by a combination of natural gas and renewables and supports our view that the world needs all forms of energy. As the sector evolves, Enbridge is well positioned to serve this increased demand through the vast footprint of our assets connected to key supply basins.

And with Enbridge’s asset base, we can offer customers access to permanent power by fueling natural gas generation and renewable power. It’s a competitive advantage that we have to offer at jurisdictions throughout North America. We expect this trend of serving data centers will take some time to ramp up but are ready to serve our customers and their energy needs through our integrated infrastructure network. Now let’s take a deeper dive into our WhiteWater joint venture. On March 26th, we announced the formation of the Whistler pipeline JV, which will own a gas pipeline and storage network connecting the Permian Basin to the growing U.S. Gulf Coast demand. This transaction further extends our access to the U.S. Gulf Coast LNG terminals, adding a connection to Cheniere’s Corpus Christi terminal.

There are four assets within the JV, the Whistler Pipeline and the Waha Natural Gas Storage, which are currently in operation. The ADCC pipeline, which is expected to come into service in Q3, and the Rio Bravo pipeline, which will enter service in 2026. The portfolio of assets is highly contracted and backed by predominantly investment grade counterparties, which aligns perfectly with our low risk commercial model. Beyond that, the system has embedded future growth opportunities which will support growing LNG export volumes. This new JV is a strategic move into a prime gas supply basin bringing together three key Texas Midstream partners in an extremely attractive and financially beneficial manner. So now let’s take a closer look at gas distribution and storage.

As I mentioned earlier, we closed the Enbridge Gas Ohio acquisition on March 6th, and we are making great progress on the remaining U.S. Gas Utilities acquisitions. The integration teams are working hard, and we look forward to continuing to deliver safe, reliable, and affordable natural gas to millions of residents and businesses. The Ohio Gas Utility serves 1.2 million customers and includes rate structures that decouple revenue from volumes, reducing earning seasonality. In addition, over 80% of the capital is subject to recovery riders, which allows Enbridge Gas Ohio to recover on that capital in a matter of months rather than years. We continue to work collaboratively with Questar and PSNC’s regulatory bodies and expect to close those acquisitions later this year.

Turning to our Canadian Gas utility, we filed a court appeal and submitted a motion with the OEB to review their December rate rebasing decision for EGI. The court appeal has been placed in abeyance until the OEB review is complete, which we expect could be during the third or fourth quarter of this year. The province of Ontario is enacting the keep energy cost down act, and we’re encouraged that the government of Ontario is taking positive steps to preserve customer choice and affordability. In the meantime, we’ll continue to focus on delivering safe and reliable energy to our growing customer base in Ontario and the second phase of the rebasing proceedings. On the operation side, our Dawn hub continues to serve nearby markets with about 290 BCF of networking storage capacity, roughly a third of which is non-regulated, and available to benefit from improved storage rates.

Let’s jump into the renewable section. As mentioned at investor day, we like offshore wind in France because of the solid risk adjusted returns, strong partnerships, and long-term government backed offtake agreements. This focal point is exhibited through the three French projects we have coming into service shortly with Fox Squirrel, PGL, and Calvados. At Fecamp, all 71 turbines have been installed and the wind farm has begun generating electricity, powering the equivalent of more than 400,000 homes. At Provence Grand Large, all turbines and the floaters have been installed. Now let’s pivot to our ESG progress outlined in our 2023 sustainability report. Today, we published that 23rd annual sustainability report, and I’m pleased to report great progress towards our environmental, social, and governance goals.

Since 2018, we’ve reduced our GHG emissions intensity by 37%, and we’re well on our way to net-zero emissions by 2050, having reduced our absolute emissions by 20% and our methane emissions by 40% since 2018. On diversity, we’ve already met and exceeded our board targets and have increased our workforce representation in all measurable areas since this time last year. Safety remains our highest priority, of course, and we continue to drive industry leading standards and achieved a 10% improvement over our previous three-year average total recordable incident rate. Sustainability is core to Enbridge, and we’re committed to meeting the needs of our customers, investors, and society as we continue to provide energy in a planet friendly way everywhere people need it.

So now let me turn things over to Pat to walk you through our quarterly financial results, our capital allocation priorities and our growth outlook.

Pat Murray : Thanks, Greg, and good morning, everyone. We’re off to a great start in 2024. It’s been another strong quarter operationally and I’m proud of the teams for successfully closing the acquisition of the Enbridge Gas, Ohio on March 6th. Utilization was high across all franchises, showcasing continued demand for assets. I’m going to speak primarily about the actual results today. We’ve also broken out what we refer to as our base business results, which exclude the contribution from and the related financings of the U.S. gas utilities, and we’ll continue to report our base business results for comparison against financial guidance. In the supplementary materials posted on our website, we provided a reconciliation between the two for transparency purposes.

Now on to the results of the business. Year-over-year, first quarter adjusted EBITDA is up 11% and DCF per share up 4%. Inclusive of share issued last September to fund the U.S. gas utilities. In Liquids, continued demand for our full pass system drove strong results, particularly on the mainline and our Mid-Continent and Gulf Coast assets, specifically the Flanagan South Pipeline and the Ingleside export facility. Gas Transmission had another quarter of high utilization and favorable recontracting on storage and transmission assets, as well as benefiting from the acquisition of our gas storage facilities at Tres Palacios and Aitken Creek and the new Tomorrow RNG portfolio. Despite significantly warmer weather in Ontario, which impacts first quarter results by almost $80 million, EGI’s results were consistent year-over-year as the Canadian utility benefited from higher rates and increased customer base.

Enbridge Gas, Ohio, as I noted, closed at the beginning of March and contributed about $50 million of EBITDA in the 24 days of ownership. The renewables business benefited from increased Hohe See and Albatross ownership, compounded by strong international wind resources on those same assets, as well as contributions from our investments in Fox Squirrel as a result of the generation of investment tax credits. As a reminder, our Energy Services segment is now embedded into the business units, so you will not see it as a standalone segment anymore. This change has no impact on our segmented 2024 financial guidance. Eliminations and Other is up in 2024 owing to the higher investment income and lower operating administrative costs within the quarter.

Below the line in DCF per share, higher EBITDA was partially offset by higher interest rates impacting both floating rate and new debt. And finally, the additional share count from the equity issuance in September of last year also impacted our per share measures. Today, we’re also reaffirming base business financial guidance, and we expect to be well within the range. If we are able to close the Utah acquisition within the second quarter, as we expect, we’ll look to update the full year guidance inclusive of the Utah acquisitions on our Q2 call. Before I move on, I want to remind the investment community that our results have implicit seasonality. The first and fourth quarters are typically our strongest financial quarters. Gas consumption at the Ontario utility and gas transmission on our gas pipelines increases during colder months, while refinery turnarounds typically take place in the spring summer, which means our liquid deliveries are lower during these periods.

With that, let’s turn to our growth drivers. This slide drives a bit deeper into our secured capital program and optimization opportunities, providing visibility to 4% to 5% of our overall medium-term growth outlook. As mentioned, our secured growth program now sits at $25 billion. The backlog is heavily weighted towards our gas transmission utility business and the diversity of projects both in terms of scope and geography reduces our exposure to inflation or regulatory risk. Also worth pointing out is that our share of capital in Rio Bravo has been reduced in line with our lower interest in the pipeline as outlined in our joint venture press release in March. On cost savings, we continue to evaluate opportunities to reduce overhead, improve productivity and incorporate inflation protection into our commercial agreements on an ongoing basis.

Asset optimization, cost management and contract negotiations have historically generated 1% to 2% of annual growth for Enbridge and will remain important drivers of our business going forward. Lastly, I’ll touch on our capital allocation priorities that we spoke about at Enbridge Day. With the remaining LDC closes in sight, I’d like to reiterate our continued commitment to balance sheet strength and sustainable capital returns. Our leverage guardrails of 4.5x to 5x debt to EBITDA remain in place and are supported by our industry leading low risk business model. The sale of our interest in Alliance/Aux Sable reinforces the balance sheet and ensures continued financial flexibility ahead of the Questar and PSNC closings this year. As I read last quarter and emphasized to Enbridge Day, our focus remains grounded in capital prudency.

Our value proposition has always been underpinned by a ratable growing dividend. We’ve distributed $34 billion to our shareholders over the past five years alone. And looking ahead, we expect that figure to grow to roughly $40 million over the next five years, while maintaining our 60% to 70% DCF payout range. We’re able to achieve that thanks to the visibility and duration of our multiyear growth outlook. We plan to spend $6 billion to $7 billion per year on our secured growth program and while we have additional capacity, we don’t need to spend it to achieve our growth targets. With that, I’ll pass it back to Greg to wrap things up.

Greg Ebel : Well, thanks very much, Pat. That’s a really nice summary of a very successful first quarter to start the year and of the great progress we’ve made across all of our businesses. The decisions we’re making today are setting the stage for Enbridge to continue growing our dividend and sustainably returning capital to our shareholders for years to come. Over the last 20 years, we’ve generated an industry leading average TSR CAGR of 12% through a balance of capital appreciation and dividend growth. Our value drivers are unchanged, unrivaled and quite unique in the midstream sector. We have diversified utility like cash flows and a strong balance sheet that has supported 29 years of dividend increases, and we maintain an attractive risk adjusted growth outlook.

We benefit from lower carbon optionality throughout our conventional business, which will support affordable and responsibly paced global energy transition. Our strong value fundamentals are expected to continue delivering attractive shareholder returns making Enbridge your first choice investment opportunity. Thank you all. And now let’s open the line for questions.

See also Morgan Stanley’s Top 15 Stock Picks for 2024 and 14 Best Financial Sector Dividend Stocks To Invest In.

Q&A Session

Operator: [Operator Instructions] Your first question comes from the line of Robert Catellier from CIBC.

Robert Catellier: I wondered if you could give us your updated view on financial markets and asset sale markets and how you’re weighing capital recycling versus other options for funding utility acquisitions notably the ATM.

Greg Ebel: Yes, Robert, maybe I’ll start and maybe Pat will add here. Look, I think you seen lot of asset sales, people have adjusted to higher interest rates and you can see what I would argue a more robust market today for asset sales. And as you know, we’ve done well in excess of $10 billion in asset sales since 2018. So that’s always on the table. I think what we want to make sure and I think what we’re doing is making sure that we’ve got maximum flexibility, maximum optionality and preparedness to complete the last 10% or so of the financing. So, no decisions have been made, but obviously everything on the table and we think that probably gives us the best opportunity given the markets, given we’re not exactly sure when the transactions are going to close.

So all that being said, highly confident we’ll get that all closed. In fact, I guess, if you had regulatory approval today, you could actually just close them all right now too. So, I think we’re set up with everything still on the table, maximum flexibility and that’s going to create the best opportunity to maximize value.

Robert Catellier: My next question, just wondering if you could update us on how the U.S. Gulf Coast crude oil export market is evolving. Specifically, in the short- to medium-term here, we have a number of impacts, refinery maintenance in Europe, less Mexican exports and the indirect impacts from the startup of TMX.

Colin Gruending: Sure Robert, Collin here. So yes, you sound like you’re on top that. It’s still pretty robust. Certainly the light export market is on, you can see that Permian supply is up and we’re seeing strong throughputs off the dock. And likewise on the heavy export market or even just maybe even further upstream a little bit, just heavy into the U.S. Gulf market itself is still robust. Like you said, we’re seeing Mexican oil staying home and it’s just creating more room for the Canadian heavy barrel, which were a strategy we’ve worked on for a long time and we’re going to bring on EHA here soon to help our plumbing in that area. So we’re watching that closely. It sounds like you are too. It remains pretty robust.

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

Rob Hope: Wanted to follow-up on the commentary in the prepared remarks on increasing gas demand related to data centers. How large of an opportunity would this be for your gas pipeline systems? And specifically, kind of when do you think you could start to see some expansions being required?

Greg Ebel: Sure. Well, you know what, I’ll turn it over to Cynthia. I guess lots of numbers out there for sure, Robert, and, lots of predictions. I think it’s early to be quite honest, but in any event, it’s going to be positive from a power and gas demand perspective. So whether it’s, on the power side, half to 1.5% increase through 2030 or, I’ve seen numbers from 5 Bcf up to 16 Bcf. I think we’re well situated. It’s not just the pipelines, but I’ll turn it over to Cynthia, maybe, last Michele and Matthew to make comment too.

Cynthia Hansen: Yes, thanks. Rob, we are excited by this opportunity obviously to help build out the supporting infrastructure for the natural gas generation to support AI data centers. Our GTM assets are really well located. We’re within 50 miles of 45% of all the natural gas power generation in North America. So we are going to be in a position to build that out. As you look to timeline, just like Greg said, there’ll be some opportunities in the near-term just depending on what your capacity and availability is and location. And so we look forward to that and in the longer term, it seems to be really positive. Michelle?

Michele Harradence: Sure. Rob, what we’re finding as we’re speaking to customers about data centers is they’re typically looking for reliable and affordable electricity in locally supportive jurisdictions. So the jurisdictions we currently are certainly the ones we will operate in, whether that’s Utah, North Carolina or Ohio. They offer that really very much hand in hand with gas fired generation. So to the degree that there is data growth in those regions, we certainly expect there will be data growth, that center growth in those regions will certainly play a role.

Matthew Akman: Yes. Hi, it’s Matthew. Just quickly on renewables, demand for renewables is already very strong and I think the data center stuff just enhances that. Large tech companies are really our kind of customers, and I think we’re their kind of developer. We’ve got a reliable offering. We can deliver. We’ve got interconnection agreements ready to go and the capabilities. So just adds another tailwind for our renewable business.

Greg Ebel: Yes, good setup. And we did mention storage, but given people want to jump on stuff, so obviously as you know we’ve got 600 Bs or so of storage across the continent that’s going to be powerful too.

Rob Hope: And then maybe just switching over the heavy and the crude oil system. Interesting, we’re talking about expansions as Trans Mountain is ramping up. But even still, it does seem like there’s an increasing pull of heavy to the Gulf Coast. So how have discussions with shippers formed regarding kind of the next phase of expansions of heavy capacity out of Alberta? And what do you think the pacing or timing will be of your phase expansions on the mainline?

Colin Gruending: Sure. Hey, Robert, it’s Colin. Yes, so indeed now that we’ve got the multiyear tolling deal done, it’s kind of cleared the way and the table for discussions with shippers on the next series of things to do in the job jar, expanding the system or even just continuing to optimize the system, which we’ve been doing over and over again, are on the table right now. We’re in discussions with shippers currently and we’ve got some offerings in front of them that are relatively capital efficient, executable permitting wise. With a view to keeping some open egress here through the whole piece, so that prices are higher. So that’s the objective. Timing wise, you’re going to see optimizations continue from us serially here month to month, quarter to quarter and then chunkier expansions in the 100,000 a day category in the next two years, which would pair up pretty well with I think the forecast we’ve been conveying around the system refilling within that period of time.

So that’s the current discussion and plan which is consistent book we’ve had for the last year or two.

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

Benjamin Pham : On the recent Capital Power that shelved their CCS project, how does that impact you or in any way for your Wabamun Hub project?

Colin Gruending: Ben, it’s Collin, I could take that. Yes, so that’s disappointing. And I think as Capital Power noted, the project is technically viable, but just economically unviable for a number of reasons, including governmental support for it. Notwithstanding, we’ve got a kind of a sister project at the Wabamun Hub with Heidelberg Materials for their cement plant in Northwest Edmonton. So that project, has garnered some more financial support, and we’ll be working with them to consider FID later this year. So Wabamun open access hub will generally, continue. We’ve incurred some very modest capital costs in preparing for Capital Power, but we have a reimbursement agreement with them. So it’s not be recovered. So that’s our update on that hub.

But more broadly, we remain keenly interested in growing a carbon capture and transportation and sequestered business, across North America. And we’ve got a couple of other projects under development as you know in the states, namely Texas. So that’s a broad update.

Greg Ebel: Ben, it’s an interesting one because I think it’s a good example of even in some of these new technologies where there appears to be lots of government support, they’re going to be highly competitive, right. As Colin said, the Heidelberg project looks quite good. And then you’re going to compare jurisdictions, we sure do. And I think Capital Power sounds like they are too. And thus the NPV of tax benefits in the Canada versus the U.S. for CCS, it’s just more attractive down south. So we’re real careful how we deal with this. As Colin said, we’ve got reimbursement agreement there, but we’re going to keep pursuing these. And I think that’s like a lot of other things, there’ll probably be fewer of these than more than obviously the proposals there, right. We’re going to do this really discipline and it sounds like there as well.

Benjamin Pham : And maybe on Ingleside, just going back to that and the strong volumes, the windows that you’re talking about, what do you think your expectation is in terms of capital deployment each year going forward? And maybe just an update on specific developments like solar generation, ammonia export, anything that’s been notable in the last quarter or two?

Colin Gruending: Sure, Ben. So yes, we considered it, Ingleside is kind of a Swiss Army Knife multi product ambition. Currently it’s just crude, but over time all the advantages that or crude’s advantage of that dock are portable to other products, purity products, blue ammonia, which we’re developing. So we’ve announced a couple of expansions at Ingleside now, right, is for storage, and we’ve got headroom there with both permitting for storage and docs. As you know, we acquired — or announced, we have to close that yet later this year with the docks next door, which are going to basically double the windows, and we can immediately optimize the loading of smaller vessels at the neighboring docks and reserve our legacy docs for the VLCCs. And by the way, we’ve deepened our dock to 54 feet now.

So we can’t — not fully loaded, but 1.6 million barrels a day of a 2 million-barrel at VLCC. So that’s pretty efficient capital deployment. To your question over time, we’d like to copy paste that model, if you like, to other products. We’re still looking at the blue ammonia project with Yara. And the FID on that would be over a year away yet, but that would be a chunkier capital deployment. But the commercial models we’re looking at would be utility-like and strong margins over a hurdle rate. So hopefully, that gets to your question.

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

Theresa Barclays: First, on the gas transmission side. Related to the Whistler JV acquisition, just curious on how you think about optimizing or how this optimizes your portfolio over time? And related to the mention of organic growth opportunities on this. Clearly, we’re seeing very tight Permian egress right now and the need for additional capacity out of [raha]. Do you view additional expansion opportunities on Whistler likely? Or would you be willing to take part of another greenfield egress solution?

Cynthia Hansen: Yes. Teresa, it’s Cynthia. Thanks for that question. We’re really excited about this opportunity with this joint venture. It is, as you mentioned, very strategic Permian has an opportunity to grow to support all the activity in the U.S. Gulf Coast, including the LNG expansion in terminals there. We see right now, obviously, Rio Bravo with our contribution there will be a new build-out to support that LNG, so that will eventually have an opportunity to take incremental gas out of the Permian. Now there will be opportunities, both brownfield and greenfield. And so we’ll continue to look at that. And we’ll look at — we think we’ll be able to get attractive returns and help extend that footprint even more. But again, it will have to meet our threshold, and that’s further out.

But yes, it’s a great opportunity for us to continue to build out and enhance what we believe is our super system already by having that incremental connectivity. And now, of course, with the Whistler JV will be tied to all of the existing LNG facilities because we get the connection to Cheniere’s Corpus Christi LNG facility.

Greg Ebel: Yes. I guess we also look at opportunities outside the JV as well as they come along right areas like Port Arthur and stuff like that. So I think we’re open to any but I think it actually creates good optionality down into the Corpus area, et cetera, with the JV. And then we’re continuing to look at other opportunities because frankly, we haven’t been as deep into the Permian or some other players.

Cynthia Hansen: Yes. And we do have, as Greg noted, an open season right now from Permian to Port Arthur provider that’s going to close on May 20, and we have a lot of interest. So it’s a great opportunity to support the development there.

Theresa Barclays: Got it. And then maybe turning back to the liquids segment. I wanted to follow-up on the line of questioning related to TMX ramping up and how everything is tracking within your internal budget. As we look to second quarter, right, so you have the line fill happening right now and then you have a seasonal producer maintenance upstream. Just quarter-over-quarter, given the strong earnings, not just on your mainline system in the first quarter, but also Express Plus systems south of mainline. Would we expect to see some alleviation or a decrease in volumes from those systems, even as mainline remains a portion just at a lower level. How should we think about the evolution of that for the year?

Colin Gruending: Theresa, it’s Colin. Yes, I guess, we normally reserve to late June to update you on volumes for Q2, but maybe a quick sneak a peak here. So Linefill’s complete, I think, on TMX, it’s flowing. And from what we can tell, it looks like that was all line filled from inventory, elevated inventories anticipated going into it. So we’ve not really seen a blip on our system here through April or May. And likewise, our downstream pipes remain pretty robust. So I think the thesis we’ve been offering here is unfolding like we thought it would. So I’ll stop short of giving you a volume numbers, but that’s a general trend.

Operator: Your next question comes from the line of Linda Ezergailis from TD Cowen.

Linda Ezergailis: I’m wondering as we see economic demand increasing from data centers and onshoring of industrial demand et cetera and the supply response working as hard as it can to meet that. I’m wondering when you look out through your system and see any pinch points along the transportation value chain, how important is it for your customers, whether it be producers or end users like utilities or in the future data centers to have full path solutions from you on the gas side, you don’t have upstream gathering. So I’m wondering if that might be an extension of your value chain consideration as we see kind of more complexity in terms of these molecules traversing through the system. And then similarly, on the liquids side, are your shippers sophisticated enough to navigate all the steps in the value chain? Or are you seeing increasingly demand and interest in bundled services [indiscernible] services more full path?

Greg Ebel: Linda, maybe I’ll start and then maybe Colin and Cynthia want to chime in to you. Look, I mean, we’re seeing incredible utilization of the assets, right? So [indiscernible] take a place like British Columbia, like — we’ve just seen unbelievable elements of peak days that have gone through there. We saw the West Coast South system, almost 600 Bs of gas in 2023, which is 6% more than a year ago. And 99 of our top 100 days on Tcf have occurred since November 22. So people are looking for that path. As you know, we’re looking to develop that. They’re also looking to storage. As you know, we’ve bought Aitken Creek. We’re not in the gathering side in a big way now. But if we could do that in a way that’s consistent with our low-risk model, that’s something we would definitely look at.

And then, yes, on the liquids side, I mean, not only are our customers sophisticated to look at this. I think we’re doing a great job with the customer team in Colin’s Group figuring out ways that we can bring innovative solutions to them full path, right? So — and you see that with the number of our — whether it’s open seasons in the Gulf Coast or our efforts on Flanagan and et cetera, and obviously, the mainline toll agreement. So — yes, I think on all fronts, we’re — we see they want a full path, and we see they want lots of optionality. And I would even include the utilities now in that regard, too, and look at a place like Ohio, where we’ve got all those assets available, whether it’s renewable, gas, liquids and you’ve got data center activity and stuff.

So I think we’ve got the full suite of tools, and that’s exactly what we’re trying to be able to do to benefit them and ourselves and our investors, obviously. I don’t know Cynthia or Colin.

Colin Gruending: I would just — I think, Linda, your observations, right? Value chains are getting longer, right? We can see that with TMX, we see that heavy down at the Gulf. So customers are sophisticated for sure, but there are that last mile element that is in, let’s call it, increasingly foreign territory where we can help navigate that with the facilities or integrated tools think about something like EHA or even something like the Seaway docks down in South Texas. Those are incrementally kind of new to the equation over the last couple of years.

Cynthia Hansen: Yes. I would just reinforce the point that we’re always looking to listen to what our customers want and having new customers come in on the AI data center space, we’ll look at how we can evolve that. But they are very sophisticated, and there are other players in that space, marketers that can help build out that full value chain too. But our assets are in great locations and we’ll be well positioned to take advantage of that.

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

Jeremy Tonet: I just wanted to pick up on that last point, I guess, a bit more. Having closed the Ohio LDC acquisition — just wondering if you could talk a bit more, I guess, on specific opportunities you see for growth in your footprint such as Nexus running through the state and it seems like there’s some capacity to expand there and having the LDCs. Just wondering if you could walk us through that a bit more.

Michele Harradence: Sure. I mean we’re certainly starting to take a look at it. It’s been about 2 months. It’s gone really well. And Ohio is very, very well served with its position in terms of having that access and availability to gas. We also have about 80 Bcf of storage just in Ohio and, of course, access to the Dawn Hub. So we think there’s quite a few opportunities. We’re also looking for where we have similar customers. So for example, whether that’s steel manufacturing that’s using and converting to natural gas in order to reduce their emissions and that sort of things. So we think there are quite a few opportunities. And the team has been going in pretty deep to look for them.

Greg Ebel: Remember, Jeremy, also that Ohio is interesting and that a lot of the growth there isn’t so much about load, although — we’ll see how that goes and we believe in it. It’s a lot about replacement too, which is structured in the rates and stuff. And as there’s a lot of capital to go in that regard. So anything incremental on these commercial synergies we’re talking, which we fully expect we’ll be able to realize is was not something we had assumed in our acquisition assumptions. So all that will be upside.

Jeremy Tonet: Got it. That’s very helpful. And as you start to close these LDC acquisitions, just wondering if you could talk a bit more, I guess, on how you think about your LDC portfolio. And if EGI doesn’t deliver the mechanisms that are as attractive as maybe some of the other jurisdictions, I guess, the potential to wheel capital around to where you see the best opportunity?

Greg Ebel: Yes, absolutely. I think it’s exactly the same way now with multiple jurisdictions and geographies the same way we look at gas transmission on the renewables side and on the liquid side. You — we only — you only have so much capital a; and b, we want to put that capital to work where it attracts the best returns. I am confident that, particularly with the support from the Ontario government and ensuring that consumers have choice that we’ll have our opportunities in Ontario. But you’re exactly right. Just given things like population growth and penetration in places like Utah and North Carolina, that’s going to be highly competitive. And fortunately, we’ve got the resources and backing to be able to meet all those.

So yes, that’s exactly what we want to be able to do. And again, we see it on the liquid side as well. We’ve redeployed a lot of capital into the Gulf Coast, where we weren’t. And at the same time, now we’ve got egress opportunities, which I’m not sure many people were seeing 2 years ago. But once again, the good old mainline in Western Canadian Sedimentary Basin is proving a robust area. And then yes, of course, on the gas transmission side, whether it’s on the on the LNG side. A lot of our capital, I would say, has moved south in the last few years. Eventually, the Northeast is going to have to do something, and that will create opportunities, too. So — and obviously, around The Great Lakes, I mean, it is the benefit of portfolio. Not all jurisdictions are going to be the most attractive at the time.

But when you’ve got assets in 43 states and provinces in 5 countries, you can make those capital allocation decisions with great discipline.

Operator: Your next question comes from the line of Robert Kwan from RBC Capital Markets.

Robert Kwan: If I can just start on the Dominion funding side of things. And you made a comment that you expect to exit the deal funded well within the 4.5x to 5x. I’m just wondering if you can square that out. I think at the outset of the deal, you were targeting being at the midpoint or even in the lower half of the range and just in achieving whatever the target is now — do you think you can do that within the levers that avoids the usage of the ATM?

Pat Murray: Well, I think, Robert, as Greg said, we’ll look at all the levers that we have to complete what is really just about 10%, 15% of the overall funding for that acquisition. — really the goal behind getting some of that — or a big chunk of that financing done early on in the process was allow us as much flexibility as we have to kind of do what we need to do throughout 2024 to close off the rest of the funding. So I think we’re really comfortable that we can fund this in a way that maintains us well within that 4.5x to 5x. And that’s how we’ll move forward on the funding.

Robert Kwan: Okay. As you — also just on finishing on capital allocation and just your approach to thinking about your payout. When you look at your earnings profile and you’ve really focused more on DCF payout versus earnings payout. So just what are the accounting measures that differ sustainably over the long term versus your view of the true economics underlying your assets? And specifically, you’ve got about $1 billion of maintenance CapEx. How much of that is coming from your gas distribution segment?

Pat Murray: So I think about half of the current maintenance capital is coming from the distribution [indiscernible] bit as we acquire these three utilities in the U.S. as we go around. I think if you’re asking kind of what the difference between EPS and DCF is, it really is that primarily that difference between depreciation and what we would call maintenance capital. But I think the important thing to know about with our assets, of course, is that if you maintain your assets appropriately like we believe we do, their life is almost not ending. And so as a result, you can utilize these assets for a very long period of time. So when we look at our payout, what we’re really looking at is that cash flow generation and how sustainable that is and therefore, make kind of dividend increase decisions based on it.

That’s why we’ve been guiding for a number of years now that we’re going to grow that dividend in line with how we grow cash flow. So I think cash is king in our mind within this business. And so we make sure that, that’s sustainable and then we make our dividend recommendations based on that. And our plan would be to continue to grow the dividend in line with cash flows.

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

Praneeth Satish: So as it relates to the funding for the LDC acquisition, you mentioned the levers that you have. But I mean it looks like Q1 was incrementally strong. So is there a scenario here where you generate more EBITDA than expected this year and therefore get to where you need to be from a leverage perspective and avoid having to sell more assets or ATM issuance? Or is it too early to think that? Just trying to think through the dynamics there. .

Greg Ebel: Yes, I think it’s a little early. I think what we’re really trying to release is making sure we’ve got that maximum flexibility. Again, we haven’t come to conclusions where you’re right, very strong quarter. As you know, we’ve got some seasonality in our year in the first quarter and the fourth quarter are always much stronger. I think what we’ll do is, as Pat mentioned in his early commentary, I believe, that as we get the assets in the door here, and I expect you’ll see this as we announce second quarter, give you a good outlook for the full economics of the transaction, if you will, and what the full year will look like on a fully loaded basis. So I think that will give you a good view at this time. Yes, I mean, look, we came into the year stronger and finished stronger than we thought.

We’ve started the first quarter stronger than a lot of people were looking for, and we felt we would have a strong start. And I believe we’ve been able to execute both on the funding to date and getting these assets in the house much quicker than we thought. From an energy fundamentals perspective, I’ve mentioned some of the things going on in the gas side. I mean I think you got to give it to us that the LP team have been bang on their expectations of what would happen with volumes and stuff, and we’re nailing those. So yes, optimistic start to the year, but we’ll come back and talk to you in August exactly how the full year will look.

Praneeth Satish: That’s very helpful. And then on Gray Oak, so you could see the open season started there. Do you think producers though are waiting to see the outcome of some of these potential offshore VLCC docs like spot before committing more barrels to Corpus? And then, I guess, just broadly, how do you think about the risks to your corporate footprint if one of those offshore projects get sanctioned maybe how much of your volume flowing into Ingleside is backed by take-or-pay contracts?

Colin Gruending: Praneeth, thanks for the question. So as you know, the basins tightening serially here every quarter as more production comes on — and by the way, Corpus, I think is trading at $0.30 or $0.40 premium to Houston, just for distance and loading advantages. So there’s a structural advantage to Corpus. We think the timing of this open season, and we’ve sounded customers is going to fit their pistol. I think with your question with respect to offshore [bridge] I think if that were to go ahead or one of them go ahead, I think the competitors that would suffer most of the smaller, probably Houston-based ship channel, less economic docks, whereas I think the Corpus docks will remain advantaged. So we see a pretty positive outlook for Gray Oak and Ingleside.

I think you asked a question about take-or-pays. So Ingleside is take-or-pay for us entirely. And it’s fed by [indiscernible] to all 5 types from the Permian and shippers typically have a take or pay on that. One of them is Gray Oak, which we own most of. So it’s basically a take-or-pay model for us all the way to the dock.

Operator: Your next question comes from the line Zackery Van Everen from TPH.

Zackery Van Everen: Perfect. Just a follow-up on Gray Oak. When that open season wraps, how fast will that volume come online?

Colin Gruending: Yes. Thanks. So Open Season scheduled to close June 28, and we’ll bring the capacity on in 2 tranches, 2/3 of it in the second quarter of 2025 and the other piece of it a number of months later. So — that’s how we see it coming on relatively quickly, and it’s a very capital efficient, low multiple expansion for us mostly strike reducing agent, a couple of tanks pretty executable.

Zackery Van Everen: Perfect. That makes sense. And then maybe flipping to the gas side. On your Venice project. I saw you guys delivered a little bit of gas to the Gator Express pipeline. Maybe an update on the time line for that facility or that project to be online.

Cynthia Hansen: Yes. Thanks for the question, Zack. It’s under construction now, and we’re working to get that in by the end of the year.

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

Patrick Kenny: Just maybe on your power business on the back of the Tennessee Ridge line expansion. And as you talked about this new demand profile for more reliable base load capacity, whether it’s from data centers or other industrial customers. Curious if you might be open to integrating combined cycle or other gas-fired opportunities now within your power segment. Assuming you can maintain your long-term utility-like contracted profile.

Matthew Akman: Pat, it’s Matthew. Thanks for the question. It’s not really on our radar to expand into gas-fired right now. We think that you’re right that the data centers and a lot of these customers obviously want reliable 24/7 power, but they also want the renewable credits. So you’ll see gas-fired will be, I think, a real important part of meeting this increased electricity demand, but so will renewable and then the customer will take sort of that combined bundled 24/7 power plus [risk] off the grid. So we’re very focused on building out, as we talked at Investor Day, are late-stage projects that have interconnection agreements. . And we’ll work with the gas-fired and obviously, with Cynthia’s business in order to make sure customers get the product that they need.

I think longer term, you’re right, there’s a potential for — potential for gas fired. But again, we’re not really focused on it right now, and we would have to meet our commercial model utility-like contracts, but again, not a focus right now.

Colin Gruending: Probably the biggest pop we’re going to see from power generation on the gas side will be in Cynthia’s business. And [indiscernible] a lot of gas-fired generation is still 50%, 60% utilization definitely go up. A lot of gas-fired generation does not have long-term contracts that could happen. And because typically, it’s been — we haven’t had as long of utilization full year for the pipelines now we do. So there’s probably going to be a requirement for some of the gas-fired generation folks to firm up, and that’s on storage as well. But yes, we’ll keep our eyes open. And I don’t think there’s any doubt electricity demand is going up.

Patrick Kenny: Yes, that’s great. And Greg, maybe just a follow-up on your comments there around gas storage. Just curious in light of the extreme cold out West here in the quarter and perhaps a view towards more extreme highs and lows in terms of temperatures going forward. If you’re seeing incremental demand from customers for more storage capacity and how you’re thinking about this opportunity from a brownfield, greenfield or perhaps M&A standpoint?

Greg Ebel: Yes. Maybe taking your last one first. We did — I think the team was on it and ahead of the game when we picked up assets on the storage side last year, both Trace and Aiken Creek and others have stepped in there now. And yes, we continue to add additional cavern space where we can from a brownfield perspective. I would say also on the distribution side, we see that, and let’s not forget, 1/3 of our distribution storage in Ontario is market-based. So Cynthia, do you want to make any comments on what you’re seeing from a pricing or even term perspective?

Cynthia Hansen: Yes. So we’ve seen our recontracting prices go up from 100% to 150%. So there’s really strong demand for that. We’re bringing on a little bit more this year with Tres Cavern 4, so that will be on by the end of the year. We continue to get inbounds for looking at what we can do brownfield and even greenfield. I mean, it’d have to be a pretty big demand to get across that and that would take more time. But we’ll look to optimize the existing structures that we have.

Michele Harradence: Oh, I was just going to say on the GDS side, we’re seeing very similar things to what I’ve done to what Cynthia quoted in terms of just the recontracting rates, but a lot of customers who previously maybe were just a couple of years that they were signing up for or going up to 4, even 5 years.

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

Manav Gupta: Just one question. What should be the CapEx cadence? Once you get into this — once you close your utility acquisitions, what would be the CapEx cadence for 2025 or so?

Pat Murray: Yes. We’ve kind of guided to the fact that we’ve got a run rate of $6 billion to $7 billion of growth CapEx on an annual basis, got a little more capacity than that, but we’ll be very selective in how we use that. So — that’s our growth CapEx number that we’ve been talking about.

Greg Ebel: All of which is consistent with equity self-financing, which is important to us, and I know is to investors as well.

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

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

Operator: Thank you, ladies and gentlemen. We appreciate your participation. This concludes today’s conference. You may now disconnect.