Enbridge Inc Q1 FY2024 Earnings Call

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 Investor Relations. 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. Please note that this conference is being recorded. As per usual, this call is being webcast, and I encourage those listening to follow along with the supporting slides. We'll try to keep the call to roughly 1 hour. 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'll 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'll also be referring to non-GAAP measures summarized below. And with that, I'll turn it over to Greg Ebel.

Thank you, Rebecca, and good morning, everyone. I appreciate you joining us today. I'm happy to share that we have achieved record financial results for the quarter, fueled by strong operational performance and solid energy fundamentals. I will provide a brief overview of Q1 and update you on our various businesses, after which Pat will delve deeper into our financial performance, capital allocation priorities, and future growth outlook. As always, our management team is available for any questions from the investment community after our presentation. I am pleased to share that adjusted EBITDA has increased by 11% year-over-year, and we are well on track to meet our financial guidance for 2024. We observed high utilization rates across our systems, and safety—our top priority—was also outstanding during the quarter. As mentioned, we closed the acquisition of East Ohio Gas on March 6, enhancing our business diversification, growth outlook, and stable cash flow profile. We have secured over 85% of the necessary financing for the U.S. gas utility acquisitions, and we will cover the remainder through a mix of alternatives, potentially including hybrid or bond issuances, capital recycling, and ATM issuances. We can utilize these funding sources to optimize market conditions and will be updating security filings to maintain this funding flexibility and ensure timely completion of all utility acquisition funding before year-end. In April, we finalized the Alliance-Aux Sable divestiture, continuing our record of capital recycling at favorable multiples. The Canadian Energy Regulator has recently approved the Mainline Tolling Agreement, and the Mainline continues to operate near capacity, ready to add additional egress as needed. We announced exciting growth in the U.S. Gulf Coast with our recent Whistler JV, the sanctioning of the Sparta Pipeline, and the acquisition of two marine docks and land at our Ingleside export facility. We have also progressed to full FID on the Tennessee Ridgeline Expansion project after the TVA decided to build a new natural gas combined-cycle plant in Kingston, Tennessee. This project emphasizes the essential role of pipelines in facilitating lower-carbon power generation via gas. Today, we released our 23rd annual sustainability report, which highlights our approach and performance on environmental, social, and governance goals. Before discussing the developments further, I want to emphasize our exceptional financial performance this quarter. Pat will provide more details later, but we will present side-by-side results for clarity, showing adjusted actuals and our base business guidance. This openness allows you to see our base business against our 2024 guidance along with all-in results, incorporating a partial month of East Ohio Gas ownership and all utility financings to date. Overall, our EBITDA is up 11% and DCF per share is up 4% from last year, mainly due to robust asset performance across Liquids, Gas Transmission, and Renewables, alongside a partial month contribution from East Ohio Gas. Our balance sheet is strong ahead of the Questar and PSNC closings, with a debt-to-EBITDA ratio of 4.7x. This figure reflects numbers as of March 31 and does not yet account for the beneficial proceeds from the Alliance and Aux Sable sale. Briefly discussing the base business, we are on track with our financial guidance, with base business EBITDA and DCF per share up 8% and a debt-to-EBITDA ratio of 4.6x. In both perspectives, we have achieved record financial results this quarter and aim to maintain that momentum. Our industry-leading business risk supports our long-held leverage target of 4.5 to 5x. Enbridge has virtually no commodity price exposure, with over 98% of our earnings coming from cost-of-service or take-or-pay contracted assets, and 80% of our EBITDA is derived from assets protected against inflation. We are also well-hedged against interest rate volatility, with less than 5% of our debt portfolio exposed to floating rates. Now let's look at notable highlights from our businesses, starting with Liquids. Liquids Pipelines once again delivered high utilization. The Mainline transported over 3.1 million barrels per day in the first quarter, and we anticipate an average throughput of 3 million barrels per day for the year. The Canadian Energy Regulator's approval of the Mainline Tolling Settlement is viewed positively for Enbridge, our customers, and the industry. Shifting to the U.S. Gulf Coast, we purchased two strategic docks and adjacent land at Ingleside for $200 million. This acquisition will enhance existing operations by increasing VLCC docking windows and help transform Ingleside into a leading multiproduct export terminal in North America. In the Permian, we've initiated our open season to potentially expand Gray Oak capacity by up to 120,000 barrels per day. Recently, we completed the construction of four new storage tanks at Ingleside, raising total storage capacity to 18 million barrels, with an additional five tanks sanctioned to add 2.5 million barrels by 2025. Moving onto Gas Transmission, Woodfibre is advancing well in Canada, and we expect to achieve the 60% engineering milestone in the second half of 2024. In the U.S., we formed the Enbridge-Whitewater-MPLX joint venture, which will enhance our balance sheet metrics while establishing a natural gas presence in the Permian Basin. The Tennessee Ridgeline Expansion project has reached full FID, and construction will start in 2025, with an expected in-service date of Q4 2026. We also approved the construction of offshore pipelines for Shell and Equinor's U.S. Gulf Coast operations. Before I talk about our strategic joint venture more, I'd like to comment on the growing demand for natural gas to support LNG terminals, as well as data centers and generative AI that require significant increases in power generation. This new power generation will rely on a blend of natural gas and renewables, supporting our belief that the world needs all energy forms. Enbridge is well-positioned to meet this increased demand through our extensive asset footprint connected to key supply basins. With our asset base, we can provide customers with reliable power by supporting both natural gas generation and renewable energy. This competitive edge allows us to serve regions throughout North America. We expect the demand from data centers to gradually increase, and we are prepared to meet our customers' energy needs through our integrated infrastructure network. Now, let’s discuss our Whitewater joint venture. We announced the formation of the Whistler Pipeline JV on March 26, connecting the Permian Basin to the increasing demand on the U.S. Gulf Coast. This partnership extends our access to U.S. Gulf Coast LNG terminals, including a link to Cheniere's Corpus Christi terminal. The JV comprises four assets: the Whistler Pipeline and Waha natural gas storage, which are operational, and the ADCC and Rio Bravo pipelines, coming online in 2023 and 2026, respectively. These assets are predominantly contracted with investment-grade counterparties, aligning with our low-risk commercial strategy. Additionally, the system presents growth opportunities that will support increasing LNG export volumes. This new joint venture strategically enhances our presence in a prime gas supply basin, uniting three key Texas midstream partners in a favorable manner. Now, let’s turn to Gas Distribution and Storage. Following our March 6 acquisition of Enbridge Gas Ohio, we are making solid progress on the remaining gas utility acquisitions in the U.S. Our integration teams are dedicated to ensuring the safe, reliable, and affordable delivery of natural gas to millions of customers. The Ohio gas utility, serving 1.2 million customers, features rate structures that decouple revenue from volumes, minimizing earnings seasonality. Additionally, over 80% of the capital is eligible for recovery riders, allowing swift capital recovery. We are collaborating with Questar and PSNC's regulatory bodies and expect to close those acquisitions later this year. Regarding our Canadian gas utility, we have filed a court appeal and submitted a motion with the OEB to review the December rate rebasing decision for EGI. The court appeal is on hold until the OEB review is concluded, which we expect in Q3 or Q4 of this year. The Ontario government has enacted the Keep Energy Cost Down Act, and we are pleased with their steps to maintain customer choice and affordability. Meanwhile, we will continue providing safe and reliable energy to our expanding customer base in Ontario. On the operations front, our Dawn Hub serves nearby markets with approximately 290 Bcf of networking storage capacity, about one-third of which is nonregulated and can benefit from improved storage rates. Now, looking at the Renewables segment, we are enthusiastic about offshore wind in France due to favorable risk-adjusted returns, strong partnerships, and long-term government-backed offtake agreements. This focus is reflected in three upcoming French projects: Fécamp, PGL, and Calvados. At Fécamp, all 71 turbines are installed and the wind farm is generating electricity, powering more than 400,000 homes. At Provence Grand Large, all turbines and floaters have been installed. Now, let’s move to our ESG progress detailed in our 2023 Sustainability Report. We published our 23rd Annual Sustainability Report today and I am proud to report significant advancements towards our environmental, social, and governance objectives. Since 2018, we have reduced our GHG emissions intensity by 37%, and we are on track for net-zero emissions by 2050, having cut our absolute emissions by 20% and methane emissions by 40%. In terms of diversity, we have surpassed our Board targets and increased workforce representation across measurable categories since last year. Safety is still our top priority, and we have achieved a 10% improvement in our total recordable incident rate over the past three years. Sustainability is fundamental to Enbridge, and we are devoted to meeting customer, investor, and societal needs while providing energy in an environmentally-conscious manner everywhere it is needed. Now, I'll hand it over to Pat to walk you through our quarterly financial results, capital allocation priorities, and growth outlook.

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 Enbridge Gas Ohio on March 6. Utilization was high across all franchises, showcasing continued demand for assets. I'm going to speak primarily about the actual results to date. 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 business results. Year-over-year, first quarter adjusted EBITDA is up 11% and DCF per share of 4%, inclusive of shares 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 Flanagan South line 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 Morrow RNG portfolio. Despite significantly warmer weather in Ontario, which impacted first quarter results by almost $80 million, EGI's results remained consistent year-over-year as the Canadian utility benefited from higher rates and an 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 OEC and Albatros ownership, compounded by strong international wind resources on those same assets, as well as contributions from our investments in Fox Squirrel due to 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 stand-alone segment anymore. This change has no impact on our segmented 2024 financial guidance. Eliminations and others are 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. The additional share count from the equity issuance in September of last year also affected 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 utility 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 increase during colder months, while refinery turnarounds typically happen in the spring and summer, which means our liquid deliveries are lower during these periods. With that, let's turn to our growth drivers. This slide examines our secured capital program and optimization opportunities, providing visibility to 4% to 5% of our overall medium-term growth outlook. Our secured growth program now sits at $25 billion. The backlog is heavily weighted towards our Gas Transmission and Utility business, and the diversity of projects in terms of scope and geography reduces our exposure to inflation or regulatory risk. It's also worth noting that our share of capital in Rio Bravo has been reduced in line with our diminished interest in the pipeline, as outlined in our joint venture press release in March. Regarding cost savings, we continue to evaluate opportunities to reduce overhead, improve productivity, and incorporate inflation protection into our commercial agreements. 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 discuss our capital allocation priorities that we spoke about at Enbridge Day. With the remaining LDC closes in sight, I'd like to reiterate our 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 and Aux Sable reinforces the balance sheet and ensures continued financial flexibility ahead of the Questar and PSNC closings this year. As I mentioned last quarter and emphasized at Enbridge Day, our focus remains on capital prudency. Our value proposition has always been grounded in a steadily 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 billion 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. While we have additional capacity, we don't need to spend it to reach our growth targets. With that, I'll pass it back to Greg to wrap things up.

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.

Your first question comes from the line of Robert Catellier from CIBC.

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.

Yes, Robert, maybe I'll start and maybe Pat will want to add here. Look, I think you've seen lots 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 is 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.

Okay. 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?

Yes. Sure, Robert. Colin here. So yes, it sounds like you're on top of it. 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 is creating more room for the Canadian heavy barrel, which has been a strategy we've worked on for a long time, and we're going to bring on EHOT 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.

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

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?

Sure. Well, and 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, a 0.5% 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 we'll ask Michele and Matthew to make a comment, too.

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. Michele?

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 operate in, whether that's Utah, North Carolina, or Ohio, they offer that really much hand-in-hand with gas-fired generation. So to the degree that there is data growth in those regions, we certainly expect that data center growth in those regions will certainly play a role.

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.

Yes. Good setup. And we didn't 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.

All right. And then maybe just switching over to the heavy and the crude oil system. Interestingly, 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 phased expansions on the Mainline?

Sure. Robert, 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 2 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 with what we've had for the last year or two.

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

On the recent Capital Power, they shelved their CCS project. How does that impact your Wabamun project?

Ben, it's Colin. I can 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 the 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 recovered. So that's our update on that hub. But more broadly, we remain keenly interested in growing our carbon capture and transportation and sequester business. Across North America, we've got a couple of other projects under development, as you know, in the States, namely, Texas. So that's a broad update.

It's an interesting situation because it exemplifies that even with significant government support for new technologies, there will be strong competition. As Colin mentioned, the Heidelberg project seems promising. We do compare different jurisdictions, and it appears that Capital Power is also in a good position. The net present value of tax benefits for carbon capture, utilization, and storage in Canada is less appealing compared to the U.S. Therefore, we are being very cautious in our approach. As Colin noted, we have a reimbursement agreement in place, and we will continue to pursue these opportunities. Like many other initiatives, there may be fewer viable options than what has been proposed. We will move forward with discipline, and it seems Capital Power is aligned with that approach as well.

Okay. And maybe on the 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 exports, anything that's been notable over the last quarter or two.

Sure, Ben. We view Ingleside as a versatile facility with ambitions across multiple products. Currently, it handles only crude, but in the future, the advantages of that dock for crude can be applied to other products, such as purity products and blue ammonia, which we are developing. We've announced several expansions at Ingleside for storage and have capacity for both storage and docks. As you know, we've recently announced the acquisition of neighboring docks, which will effectively double our capacity. This allows us to optimize the loading of smaller vessels at those docks while reserving our existing docks for very large crude carriers. Additionally, we've deepened our dock to 54 feet, enabling us to load 1.6 million barrels per day from a 2 million-barrel capacity VLCC, which is a smart use of capital. Over time, we hope to replicate this model with other products. We're still pursuing the blue ammonia project with Yara, but the final investment decision on that is likely over a year away and would require a significant capital investment. The commercial models we are considering would provide utility-like returns with strong margins. I hope that answers your question.

Your next question comes from the line of Theresa Chen from 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 Waha. Do you view additional expansion opportunities on Whistler likely? Or would you be willing to take part of another greenfield egress solution?

Yes, Theresa, it's Cynthia. Thank you for the question. We're very enthusiastic about the joint venture opportunity. As you mentioned, it is quite strategic. The Permian Basin has the potential to expand in order to support all activities in the U.S. Gulf Coast, including the LNG terminal expansions there. Currently, with our contribution to Rio Bravo, there will be a new build-out to support LNG, allowing us to eventually remove additional gas from the Permian. We foresee opportunities for both brownfield and greenfield projects, and we will continue to explore these options. We anticipate being able to achieve attractive returns and further extend our footprint. It will need to meet our standards, and that is something we will evaluate further down the line. Nonetheless, this presents a fantastic opportunity for us to continue enhancing and building upon what we consider our extensive system by increasing connectivity. Additionally, through the Whistler joint venture, we will be linked to all existing LNG facilities as we gain access to Cheniere's Corpus Christi LNG facility.

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, etc., with the JV. And then we're continuing to look at other opportunities because frankly, we haven't been as deep into the Permian as some other players.

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.

Now let's get 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 the 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-Platte and the 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?

Theresa, Colin. Yes, I guess, we normally reserve to late June to update you on volumes for Q2, but maybe a let's sneak a peek here. So line fill is 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.

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

I'm curious, as we observe the rise in economic demand from data centers and the onshoring of industrial needs, and with the supply response working diligently to keep up, I'm interested in whether you identify any pinch points in the transportation value chain. How essential is it for your customers, including producers and end users like utilities or future data centers, to have comprehensive solutions from you regarding gas, especially since you lack upstream gathering? I wonder if this could extend your value chain considerations as the complexity of these molecules moving through the system evolves. Additionally, on the Liquids side, do your shippers have enough expertise to navigate all the steps in the value chain? Are you noticing an increasing demand and interest in bundled, more comprehensive services?

Certainly, I'll begin and then Colin and Cynthia can add their thoughts. We're experiencing remarkable utilization of our assets. For example, in British Columbia, we've seen significant peak days recently. In 2023, the West Coast South system reported nearly 600 billion cubic feet of gas, which is a 6% increase compared to last year. Notably, 99 of our top 100 days on record have occurred since November 22. Customers are seeking pathways, and we're committed to developing those options. They're also interested in storage, and we've acquired Aitken Creek. While we're not heavily involved in the gathering side at the moment, we would consider that if it aligns with our low-risk model. Additionally, on the liquids side, we see our customers are quite sophisticated and our team is effectively delivering innovative solutions for them. This is evident from the number of initiatives we've undertaken, such as the open seasons in the Gulf Coast, our work on Flanagan, and the Mainline Tolling Agreement. Across the board, customers are looking for comprehensive solutions with plenty of options, including utilities. In Ohio, for instance, we have a variety of assets available, including renewable energy, gas, and liquids, along with data center activity. We believe we have the complete set of tools necessary to support both our customers and ourselves, as well as our investors. Cynthia or Colin, would you like to add anything?

I think your observation is correct, Linda. Value chains are indeed becoming longer. We can see this with TMX and also at the Gulf. Customers are certainly sophisticated, but there is that last-mile aspect that is increasingly unfamiliar territory where we can assist with facilities or integrated tools, such as EHOT or the Seaway docks in South Texas. These elements have been somewhat new to the equation over the past couple of years.

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.

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

I just wanted to pick up on that last point, I guess, a bit more. Having closed the Ohio LDC acquisition, I'm 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.

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 are 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.

Remember, Jeremy, that Ohio is notable and much of the growth there is not solely dependent on load, although we'll observe how that develops and we have confidence in it. It primarily revolves around replacement as well, which is integrated into the rates. There is significant capital to be invested in that area. Therefore, any additional benefits from the commercial synergies we are discussing, which we fully expect to realize, were not factored into our acquisition assumptions. So all of that will serve as an advantage.

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 your other jurisdictions, I guess, the potential to wheel capital around to where you see the best opportunity?

Yes, absolutely. I believe it's the same approach across various jurisdictions and geographies, similar to how we assess Gas Transmission for both Renewables and Liquids. We have a limited amount of capital, and we aim to invest that where it generates the best returns. I am optimistic, especially with support from the Ontario government, which ensures that consumers have choices and creates opportunities in Ontario. You're correct that factors like population growth and market penetration in states like Utah and North Carolina will lead to intense competition. Thankfully, we have the resources and support to address those challenges. We also see this in the Liquids sector, where we've redirected a significant amount of capital to the Gulf Coast, an area we were not previously focused on. Additionally, we now have egress opportunities that many didn't foresee two years ago. The Mainline in the Western Canadian Sedimentary Basin continues to be a strong area for us. On the Gas Transmission front, particularly with LNG, a significant portion of our capital has shifted southward in recent years. Eventually, the Northeast will need to make moves, which will create further opportunities. Around the Great Lakes, we have the advantage of a diverse portfolio. Not all regions will be equally appealing at any given time, but with assets spread across 43 states and 8 provinces in 5 countries, we can make disciplined capital allocation decisions.

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

If I can start by discussing the Dominion funding aspect. You mentioned that you expect to exit the deal well funded within the 4.5x to 5x range. Can you clarify that? Initially, you aimed to be around the midpoint or even in the lower half of that range. Given your current target, do you believe it's achievable using strategies that will avoid using the...

I believe, Robert, as Greg mentioned, we'll examine all the options available to complete approximately 10% to 15% of the total funding for that acquisition. The main objective of securing a significant portion of that financing early in the process was to provide us with flexibility to manage our needs throughout 2024 in order to finalize the rest of the funding. We are confident that we can finance this in a manner that keeps us well within the 4.5x to 5x range. This is our plan for moving forward with the funding.

Okay, I will conclude with capital allocation and your approach to considering your payout. When evaluating your earnings profile, you have placed greater emphasis on DCF payout rather than earnings payout. What are the accounting measures that differ significantly in the long term compared to your perspective on the true economics of your assets? Specifically, you have around $1 billion in maintenance CapEx. How much of that is attributed to your Gas Distribution segment?

So I think about half of the current maintenance capital is coming from the Distribution unit. It'll go up a bit as we acquire these 3 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 non-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.

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

So as it relates to the funding for the LDC acquisition, you mentioned the levers that you have. But 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.

Yes, I think it's a bit early to discuss that. What we're really aiming for is maximum flexibility. We haven't reached any conclusions yet; you're right, it was a very strong quarter. You know we experience some seasonality in our year, with the first and fourth quarters typically being much stronger. As Pat mentioned earlier, as we bring the assets in, I expect that we will provide a positive outlook for the transaction's full economics when we announce the second quarter results. That should give you a clearer picture for the year on a fully loaded basis. We've entered the year and finished stronger than anticipated. The first quarter has started strong, as we expected, and we've been able to execute well on funding and acquiring these assets much quicker than we initially thought. From an energy fundamentals standpoint, I've discussed some developments on the gas side. The LP team has met their expectations regarding volume forecasts, and we are hitting those marks. So, it's an optimistic start to the year, but we will reconvene in August to discuss how the full year will shape up.

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

Praneeth, thanks for the question. So as you know, the basin is 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 found customers, it's going to fit their needs. I think with your question with respect to offshore buoys, if that were to go ahead or one of them go ahead, I think the competitors that would suffer most are 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 and connected to all 5 pipes 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.

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

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

Yes. Thanks. So the 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 drag-reducing agent, a couple of tanks, pretty executable.

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

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.

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

Just maybe on your power business on the back of the Tennessee Ridgeline expansion. And as you talked about this new demand profile for more reliable baseload 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.

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 RECs up 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 us, potential for gas fired. But again, we're not really focused on it right now, and it would have to meet our commercial model of utility-like contracts, but again, not a focus right now.

The most significant increase we anticipate in power generation on the gas side will come from Cynthia's business. It's important to note that many gas-fired generation facilities are currently operating at only 50% to 60% capacity, which could certainly improve. Additionally, a large portion of gas-fired generation lacks long-term contracts, so there is potential for changes. Historically, we haven't had sustained full-year utilization for the pipelines, but now we do. As a result, gas-fired generation companies may need to secure arrangements, including storage. We will continue to monitor this situation closely, and it's clear that electricity demand is rising.

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?

Yes. To address your last question first, I believe the team was proactive and prepared when we acquired storage assets last year, including Tres and Aitken Creek among others. We are also continuing to expand our cavern space where possible through brownfield development. Additionally, on the Distribution side, we recognize that one-third of our Distribution storage in Ontario operates on a market-based model. Cynthia, would you like to share your insights on pricing or term trends?

Yes. So we've seen our re-contracting 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.

I wanted to mention that on the GDS side, we are observing trends similar to what Cynthia noted regarding the re-contracting rates. Many customers who previously signed contracts for just a couple of years are now extending them to four or even five years.

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

I have a question about the CapEx cadence. After you finalize your utility acquisitions, what do you anticipate the CapEx cadence to be for around 2025?

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.

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

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

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

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