Enbridge Inc Q4 FY2023 Earnings Call

Good morning and welcome to the Enbridge Fourth Quarter and Year-end 2023 Financial Results 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. As per usual, this call is being webcast and I encourage those listening on the phone to follow along with the supporting slides. We will try to keep the call to roughly 1 hour. To answer as many questions as possible, we will limit questions to 1 plus a single follow-up, if necessary. We will prioritize questions from the investment community. 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.

Well, thanks very much, Rebecca, and good morning, everyone. Thanks for joining us again. I’m pleased to be here today to recap a record fourth quarter and 2023 results. Throughout the year, the Enbridge team worked hard to execute on our strategic priorities and ensure Enbridge remains the first choice for energy delivery in North America and beyond. These efforts further enhanced our long-term value proposition, which we will talk about today, along with providing you an update on our businesses. Pat will then walk you through our financial performance, our capital allocation priorities and our outlook. And as always, the Enbridge team will be available to answer any questions you may have at the end of the presentation. Folks, I'm really proud of the Enbridge team for all its achievements in 2023. We met our financial guidance for the 18th straight year and once again exceeded the midpoint for both EBITDA and DCF per share, demonstrating the low-risk predictable nature of our business. Sustainably returning capital to shareholders remains a key priority, and our investors are benefiting from that as we increased our dividend by 3.1% this year, marking our 29th consecutive annual increase. Our debt to EBITDA, including the prefunding, was 4.1x, leaving ample balance sheet room in preparation for the closing of the U.S. gas utility acquisitions in 2024. In addition to the outstanding financial performance, we had an equally impressive year operationally. Enbridge employees matched our best-ever company safety performance. We had high utilization rates across our systems and set record throughputs on the mainline, Gray Oak and at our Ingleside export facility. We also concluded open seasons on Flanagan South, Southern Lights, and Algonquin gas pipeline, and are about to initiate an open season for the expanded capacity on Gray Oak Pipeline, which we expect to be very positively received. On the execution front, we filed with unanimous customer approval the mainline tolling agreement with the Canadian energy regulator and expect approval in the coming months. The settlement we filed is consistent with the terms we outlined for you in May and is a win-win-win for the customers, industry, and Enbridge, and I'll touch on that more later in the presentation. The sale of our interest in Alliance and Aux Sable continues our track record of recycling capital at attractive multiples and puts us in a position where we have largely completed the funding for utility acquisitions. I'm extremely proud of the organic growth projects we announced in 2023, securing an additional $10 billion to our growth backlog, which will help to drive low-risk returns to shareholders for years to come. We announced the acquisition of three gas utilities, which will create the largest integrated gas utility in North America, as well as several accretive tuck-in acquisitions in other business units. These transactions will enhance our service offering to customers and blend and extend our growth for years to come. Lastly, we placed over $2 billion of growth capital into service, primarily through our GTM modernization and utility growth capital programs. Of course, sustainability continues to be a key component of our license to operate. Last May, we published our 22nd annual sustainability report, which highlights our industry-leading performance on environmental, social, and governance issues as well as progress on our indigenous Reconciliation Action Plan. Today, I'm pleased to report that we've already met 10 of those commitments with continued efforts on the remaining elements. When it comes to emission reductions, our approach continues to be leading edge, not bleeding edge. And our recent R&D investments as well as the Ingleside blue ammonia project we're partnering with Yaron are strategically aligned with this philosophy. Before I move on to the business, I want to take a moment to highlight our record financial performance. 2023 EBITDA is up 6% from last year, primarily due to the strong performance from our Liquids business unit. DCF per share is up 1% even after absorbing the dilution impact from the upfront $4.6 billion equity issuance in September to finance the utility acquisitions. And our balance sheet is well-positioned ahead of the closings of the gas utilities at 4.1x debt to EBITDA. Altogether, another excellent year of financial performance ahead of the midpoint of our guidance and in line with our multiyear outlook. Pat will walk you through the main drivers of the strong fourth quarter shortly. As we reflect on 2023, I want to remind everyone why our business is a first choice investment opportunity. Our assets generate strong, reliable and growing cash flows that are underpinned by low-risk commercial frameworks and a stable balance sheet. We consistently and sustainably return capital to shareholders and late last year announced our 29th consecutive annual dividend increase. 2023 was a hallmark year for growth at Enbridge with approximately $23 billion of announced acquisitions and $10 billion of new projects adding both greater visibility and duration to our growth outlook. And consistent with our vision, we continue to develop Enbridge's lower carbon strategy, benefiting the enterprise and supporting an appropriately paced global energy transition. Enbridge is operating from a position of strength and its predictable cash flow growth, low business risk and strong total return profile makes it a first choice investment opportunity. So let's take a minute and revisit the low-risk nature of Enbridge's businesses. As I mentioned earlier, 2023 marked the 18th consecutive year of meeting our financial guidance. And as indicated upfront, we achieved this without needing to adjust the bought deal equity issuance from our financial results. 2023 showcased the predictability of our business amid continued geopolitical instability, persistent inflation and rising interest rates. This is because 98% of Enbridge's earnings are generated from either cost of service or take or pay contract assets. Our debt portfolio is less than 10% exposed to floating rate volatility. Our customer base is over 95% investment grade, and 80% of our EBITDA is earned from assets with protection against inflation. We are rated BBB+ by all rating agencies and remain committed to our long-held leverage target of 4.5x to 5x. Our business risk is sector-leading amongst our midstream peers and the Gas Utilities acquisition will only enhance that. Now let's spend a few minutes on the key accomplishments of each of the business units, and we will start with Liquids. Liquids Pipeline really delivered record utilization once again in 2023. The mainline transported over 3.2 million barrels per day during the fourth quarter and averaged 3.1 million barrels per day for the full year. These numbers are a new all-time high and result from our team's continuous efforts to optimize our pipeline network. Growing production out of the Permian Basin and increased export demand continues to draw record crude oil volumes through our integrated Gray Oak pipeline and, of course, Ingleside export terminal. We also concluded an oversubscribed binding open season on Southern Lights, which will lock up 165,000 barrels per day of existing capacity that was coming up for renewal in 2025. We filed our mainline tolling settlement with the Canadian energy regulator in December and expect an expedited review process. Our customers will receive the competitive and responsive service they are accustomed to, and Enbridge will earn attractive risk-adjusted returns. The mainline will continue to feed North American and global markets with a long-term source of safe, secure and affordable energy. When approved, the mainline will continue to earn an attractive risk-adjusted return on equity between 11% and 14.5%. The agreement also includes customer support for Line 5 capital expenditures, ensuring that this critical piece of infrastructure remains operational, and Enbridge can continue to deliver reliable and affordable energy to Michigan, Ohio and Eastern Canada. The settlement was unanimously approved by the Representative Shipper Group, and we are grateful for the support from our customers. Downstream of the mainline, we successfully concluded the 110,000 barrel per day open season on Flanagan South pipeline, which secures full path transportation from Western Canada to the U.S. Gulf Coast, ensuring the mainline remains well utilized. Earlier in 2023, we sanctioned the initial phase of the Enbridge Houston oil terminal. This greenfield project located at the terminus of the Seaway pipeline will provide shippers with 2.7 million barrels of premier storage that is accessible by the Houston refineries. In the Permian region, we are still planning to initiate an open season for the Gray Oak pipeline in the coming months that will offer full path export service from the Permian Basin all the way to our Ingleside docks. On the low carbon front, we are progressing the feed engineering for a blue ammonia production facility at Ingleside. This potential investment highlights the value of existing and diversified infrastructure to the energy transition. The proposed facility will source feed gas from our Texas Eastern gas pipeline, and the associated emissions will be sequestered in a nearby carbon storage facility through our partnership with Oxy, all of which further underlines the value enhancement opportunities our integrated liquids, natural gas and lower carbon platform offers customers and investors. Finally, we continue to advance the technical evaluation work for the planned carbon capture utilization and storage hub in the Wabamun area. So let's move on to gas transmission. Starting in Canada, we closed the acquisition of Aitken Creek Gas Storage, a 77 Bcf working capacity facility in British Columbia, which is uniquely positioned to support local demand and upcoming Canadian LNG exports. In December, we sold our interest in Alliance and Aux Sable for proceeds of $3.1 billion, continuing our track record of servicing value for shareholders through ongoing capital recycling. This transaction reduces our commodity price exposure and proceeds helped to finance the upcoming utility acquisitions. We've also refined our engineering estimates for the 300 million cubic feet per day expansion of the T-South gas pipeline in British Columbia. The total project is estimated to cost $4 billion, up from $3.6 billion originally. The increased costs are based on recent Class 4 estimates, which includes extensive engineering analysis, community consultation and also includes lessons learned from recently completed projects in the region. Of course, before proceeding, we will ensure that the full investment and return is recoverable through our cost of service framework on the West Coast pipeline. In the U.S., we continue to extend our LNG service offering as we progress the Rio Bravo Pipeline and the Venus extension pipeline, which we expect to place into service later this year. We've concluded an open season on the Algonquin pipeline system for additional gas delivery to New England. We are pleased with the results and are currently evaluating potential options to satisfy our customers' needs. In March, we acquired Tres Palacios, which adds 35 Bcf of working gas storage and enhances our customer service offering in the area. This facility is a key piece of infrastructure that serves local gas-fired power generation, LNG exports, and pipeline capacity to Mexico. Finally, we announced the acquisition of several high-quality operating landfill waste RNG assets in Texas and Arkansas from Moral Renewables. These investments align with Enbridge's utility-like cash flow framework and are underpinned by long-term off-take contracts. The landfills we acquired are expected to double in size by 2040 with minimal capital investment, which will supplement our growth for years to come. The renewable investment aligns well with our corporate strategy and supports our energy transition and growth expectations. Turning to gas distribution and storage. Enbridge Gas had a strong year. We added 46,000 new customers, which was ahead of expectations. We invested $1.2 billion modernizing and expanding the distribution network during '23 to support the growing needs for reliable and affordable energy in the province. In December, the Ontario Energy Board issued its decision on our rebasing application for 2024. Overall, we are not pleased with the outcome as it doesn't align with the provincial government's policy on the future of natural gas within Ontario nor the affordability and reliability of gas for our residential and industrial customers. While the decision itself isn't material to Enbridge's '24 guidance, we filed a notice of appeal with the divisional court and a notice of motion with the OEB regarding several aspects of this decision that we believe are inconsistent and amount to an error in law. In the meantime, we will continue to focus on delivering safe and reliable energy for our customers in Ontario. Now moving to the gas utility acquisitions in the U.S. We continue to be very excited about the transaction, including the fact that it was executed at a historically attractive valuation of 1.3x the forward rate base. The assets all operate in supportive and transparent jurisdictions and will add low-risk regulated earnings in quick cycle rate base investment opportunities to our backlog. As you can see on the slide, we've prefunded approximately 85% of the aggregate purchase price since we announced the transaction in September last year, and all three are on track to close in 2024. With that, let's jump into the renewables. Our scale and diversification and investing approach to renewables allows us to continue to find attractive opportunities even as returns compress for many across the sector. In Germany, we acquired additional interest in the Hohe See and Alberta offshore wind farms. These are high-quality operating assets that we know well and the transaction is immediately accretive to our DCF. In France, we continue to approach the commercial operation dates for both Fecamp and ProvancGrand Large in early 2024. Calvados is scheduled to come into service in 2025. Enbridge was also awarded the right to develop a 1 gigawatt offshore wind farm in Normandy, which we expect could enter service around 2030. We will be developing that wind farm with EDF, continuing a partnership of successful developments in the renewable space. Last November, we extended the partnership onshore in North America where we jointly are constructing and operating the 577-megawatt Fox Squirrel solar facility in Ohio. The initial phase of this project generates about 150 megawatts and was placed into service in December 2023. Our portfolio of late-stage onshore development projects continues to approach the construction ready phase with expected 2025 in-service dates. Finally, we also placed three solar self-power projects into service during the year, adding some 30 megawatts of capacity and reducing our mainline emissions footprint. So now I'll pass it off to Pat to walk through our financial results.

Thanks, Greg, and good morning, everyone. I'm very pleased to present a record quarter and full year financial results here at Enbridge. As Greg mentioned earlier, we exceeded the midpoint of our 2023 EBITDA and DCF per share guidance, representing our 18th straight year of achieving or beating our outlook. Year-over-year, fourth quarter EBITDA was up over 5%, and DCF is up 3%. Our DCF per share is down 2%, including the dilution related to the derisking of the financing plan for the gas utility acquisition. These quarterly results cap off a fantastic year for Enbridge and are underpinned by high utilization across all our systems. In liquids, our mainline transported a record 3.2 million barrels per day during the fourth quarter. Our Mid-Continent and Gulf Coast assets also delivered strong operational results with Ingleside and Gray Oak setting new quarterly volume records. These record volumes were partially offset by lower mainline toll, which took place on July 1. Gas Transmission is down marginally over the quarter due to the timing of revenue recognition related to the Texas Eastern case in the fourth quarter of last year. EGI continues to benefit from higher distribution rates from EGI's incentive rate mechanism despite a mild winter negatively impacting fourth quarter results by about $30 million compared to normal conditions. Our renewable business improved during the quarter, primarily from the increased interest in our German offshore wind assets, which closed in early November. Energy Services results improved compared to the same quarter last year due to the expiry of transportation commitments, as we have noted in prior quarters, and less pronounced backwardation in commodity markets. Realized foreign exchange losses were lower in the fourth quarter as our hedge rate was right around the spot rate of $1.35. Below the line in DCF per share, higher interest expense, the effect of the bought deal I mentioned earlier and lower distributions in excess of earnings from our equity investments, were partially offset by higher EBITDA and operations this quarter. With that, let's quickly review the year ahead. I'm pleased to reaffirm Enbridge's 2024 EBITDA guidance range of $16.6 billion to $17.2 billion and DCF per share guidance of $5.40 to $5.80 per share. This represents 4% EBITDA growth versus the 2023 guidance midpoint. As a reminder, our 2024 guidance is set on the base business, excluding the EBITDA, CapEx and associated financing impact of the U.S. gas utilities expected to close throughout this year. The reason we chose to issue guidance excluding the acquisition is that we want to showcase the strength of our base business and how it is performing relative to the growth outlook we shared at our Investor Day last March. There's some uncertainty around the timing of the close for the LDCs, but we do expect some level of contribution from all three utilities this year, and I'll discuss that on the next slide. There are a few key assumptions underpinning our 2024 guidance. Our 2024 mainline volume forecast is approximately 3 million barrels per day. This estimate was struck using TMX's public service date estimate when we release guidance. For reference, apportionment on the mainline rose throughout the fourth quarter, and our December throughput averaged 3.26 million barrels per day. Today, we have more conviction than ever that the mainline will continue to be very well utilized for years to come. We also included the sale of our interest in Alliance and Aux Sable in the guidance we provided in November. As a practice at Enbridge, we've minimized our foreign exchange and interest rate exposure for the upcoming year. The U.S. dollar-denominated DCF is almost entirely hedged at 135, and less than 10% of our total debt portfolio is exposed to interest rates volatility in 2024. Now let's look briefly at the EBIT implications from the expected closing of the gas utilities. We continue to expect staggered closes of the utilities throughout the year. Each will provide incremental contributions above our base business guidance. Given that the timeline for regulatory approvals are fluid, we limited the associated incremental contributions from our guidance. That being said, if the utilities close on schedule, our overall EBITDA could exceed the upper band of the guidance range while per-share metrics in 2024 will be impacted by the full-year share dilution. Let's turn over to our secured growth outlook. Our secured growth program sits at $24 billion. New to the table this quarter is the addition of the Fox Squirrel Solar Phase 2 and the incremental capital for T-South Sunrise Expansion as well as another year of utility growth and GTM modernization capital. In 2023, we added an additional $10 billion of new secured capital to our backlog, adding visibility and duration to our multiyear growth outlook, which I look forward to discussing more at Enbridge Day in March. We placed over $2 billion of organic capital into service, primarily from our utility growth program in Ontario and our GTM modernization program. With that, let's revisit Enbridge's capital allocation priorities before I turn the presentation back to Greg to wrap things up. Our approach to capital allocation is focused on maximizing shareholders' return. We are excited by all the opportunities ahead of us, but we are going to grow in a disciplined manner while sticking to our leverage and payout targets. Enbridge is fully committed to our leverage guardrails of 4.5 to 5x debt to EBITDA, and we will continue to operate within this range post the utility acquisitions. With the announced sale of Alliance and Aux Sable in 2023, we continue our track record of successfully high-grading our capital and we'll continue to look for opportunities to recycle assets at attractive multiples. In November, we announced a 3.1% increase to the Enbridge dividend, our 29th consecutive annual increase. Our long-held dividend payout policy is 60% to 70% of DCF and we will continue to grow the dividend up to our medium-term DCF per share growth. And with that, I'll turn it back to you, Greg.

Well, thanks very much, Pat. As I reflect on my first year leading the team here at Enbridge, who are tasked with delivering on behalf of our investors, I'm pretty pleased with how 2023 came in and extremely excited about 2024 and beyond. The financial results from the businesses reached record levels, and the same was true of the operational results right across our business units. Whether it was continuing to execute on our organic growth projects, picking up tuck-in assets across our liquids gas pipeline and renewable systems or reaching value-enhancing regulatory outcomes like the mainline toll settlement that serve our customers and investors. The team really delivered in 2023 and set up the company for continued long-term growth. We also continue to deliver record operational and safety results, which further underlines Enbridge's reputation as the first choice provider of energy logistics for all of our stakeholders. Equally important, we further diversified and extended our geographic reach and opportunity set in the natural gas utility business with a significant acquisition of three great gas utilities in growth regions of the U.S., which will extend our growth aspirations through the decade. So a great job by the team on behalf of our investors and customers. I'm very pleased, of course, with the stock performance in 2023, yet very excited about its future. With growing earnings and dividends underpinned by not one, not two, but three of the top position businesses of their kind in North America: liquids pipelines, gas transmission, and gas distribution, and a fourth business, renewables, very prudently becoming a top player, we expect to deliver excellent returns for our investors. As a balanced view of energy transition and the key elements of that become increasingly clear to investors and policymakers alike, Enbridge's diversified and balanced portfolio looks increasingly like the first choice for investors. While I'm not predicting interest rates, the inevitable easing of monetary policy will bring dividend yields on utility-like stocks such as Enbridge back into a more typical range relative to government bonds. With our prudent capital allocation actions, strong commitment to the balance sheet, low risk and growing earnings and dividends, we will deliver long-term value for investors and serve our various stakeholders along the way with excellence. Pat and I, along with our four business unit leaders, look forward to discussing our continued growth opportunities and this investment thesis at our upcoming Investor Day in New York on March 6. Hope to see you there. And now let's open the lines for your questions.

Your first question comes from the line of Robert Catellier from CIBC Capital Markets. You may proceed with your question.

Hey, good morning. Congratulations on the results. This question is probably better suited for Michele. I was wondering if you could characterize the progress you're making towards regulatory approval for the U.S. utilities. And specifically, can you comment on where you're trying to demonstrate a net benefit? Can you provide your view on rate case stay out periods compared to other benefits that you might have as options to offer rate payers?

Sure. Let me start with the regulatory approval. We have two out of the three federal regulatory approvals and are waiting on the FCC for some utilities. We received North Carolina's approval earlier this week and expect the rest by mid-month. Progress with the three utilities at the state level is going well. We anticipate Ohio will go first, followed by Utah and then North Carolina, all within this year. We aim to demonstrate a net benefit with a couple of the utilities, and overall, we believe we can show a net benefit for all utilities. This is largely due to creating the largest natural gas platform with 7 million customers and leveraging the strengths of the different utilities. For instance, Ohio is technically strong, Utah excels at cost to serve, and North Carolina has strong commercial capabilities. We also benefit from 175 years of growth experience in Ontario, already serving 4 million customers, which enables us to scale effectively. We will demonstrate these advantages to the utilities. Regarding stay outs, we will consider them as appropriate and expect some requests for them, like the one we received from an intervenor in Utah last week. We are confident we can reach beneficial terms with everyone involved. Bringing these four utilities together showcases their respective strengths, ensuring we can demonstrate net benefits.

Okay. Thank you for that. And just a second question here with respect to the regulatory process around rerouting Line 5 around the Bad River lands. Understanding that you've appealed the 2023 decision. I wondered if you can give an update on the timeline that was contemplated in the previous judgment, specifically, where the regulatory process stands vis-a-vis that timeline? Do you expect any protection from the 1977 pipeline treaty? Thank you.

Yes, for sure, Robert. Thanks for the questions. Colin is on the line, so he's probably the best one to update on that.

Robert, yes, sure. The appeals hearing has started; both Enbridge and the Bad River Band appealed that decision. That hearing has begun, and we expect a decision on that later this year. In the meantime, we continue to try to work cooperatively with the band to come to an amicable settlement. The original decision, if that survives, would have us reroute the 41-mile river around the community by June 2026. That is doable. We are ready to go. The critical path is the permit from the Wisconsin DNR, which we expect to receive in the next month or two, which would allow us over a year or two to build that, which is doable. Your second question was with regard to the treaty. Yes, we think that holds. Obviously, that's the reason the treaties were created, and we expect that to endure.

Hey, Robert, I'd just add on the treaty. One thing I'd say is I give a lot of credit to the Canadian government and provincial governments for being very strong supporters. They understand the criticality of Line 5 to many different areas, including labor unions, etc. We feel good about that. We will have to see, and I know there's been a request for the U.S. government to have a viewpoint on this. We'll see whether or not that happens, but we feel very good about the level of support we've got.

Okay. Thanks for those very positive answers, everyone.

Thanks, Robert.

Your next question comes from the line of Theresa Chen from Barclays. Your line is open.

Good morning. I'd like to touch on the liquid side as well. In terms of your mainline outlook for 2024, given the apportionment trends over many consecutive months, the delays in TMX, and likely tracking above where we all originally thought may one would be at this point heading into summer 2024. What is your outlook for the system for the remainder of the year? What kind of upside can it bring relative to the 3 million-barrel per day throughput assumption embedded in guidance? And how does that translate to the upper end of the guidance or above?

Yes, Theresa, I can take that. It's Colin. Yes, we are very confident in the mainline full path to the U.S. Gulf Coast. We think it will be substantially full in the foreseeable future. We think that we’ll be at 95% to 100% utilization even in '24 through the piece. I guess to your point, I mean, the mainline has been basically full for 75 years. The trend that continues is driven by growing production out of the Permian Basin and increased export demand continues to draw record crude oil volumes through our integrated Gray Oak pipeline and the Ingleside export terminal. And on top of that, there’s already a lot of demand pull on the mainline path; 39 refineries directly and indirectly connected traditional markets, they pull that way. We’ve got a very competitive toll and have contracted as much as we can on Flanagan South. I won’t comment on TMX's timeline or capabilities, but we’re very confident in the mainline path. We are building additional capacity in Houston as well. So, yes, we're confident in 3 million barrels per day as relative to the 3.1 delivered just last year. We've seen massively oversubscribed nominations in recent months including January and February, so the trend continues.

Got it. Then in terms of the Dominion asset acquisitions, as we consider the remaining funding, just to clarify, the list of funding options that you put out there, is that consistent with your preference in prioritization? Aside from additional asset sales, would you rather do DRIP or ATM over additional hybrids and bonds?

No, I wouldn't look at it that way, Theresa. It’s Greg. I wouldn't read anything into the listing. We aimed to emphasize that we have all options available to us, though we may not utilize all of them. The debt markets with unsecured notes and hybrids are accessible to us. If I had to rank them, I would say DRIP might be the least appealing option. However, all options are on the table. If an opportunity arises to close a utility, we are prepared to act. This affords us significant flexibility, which is why we moved early. Pat, do you want to add anything?

I think you hit it right with us securing over 85% of that funding. We are in really good shape to be selective about what we do and ensure we are making the best decision for our shareholders as we move forward.

Right. Thank you.

Thank you, Theresa.

Next question comes from the line of Robert Kwan from RBC Capital Markets. Your line is open.

Great. Good morning. If I can just continue on the funding side for the Dominion utilities acquisitions. So you've got roughly $3 billion left to go. You've been out in front of the hybrids and the Alliance-Aux Sable transaction. I guess I'm just wondering, how are you thinking about the timing of addressing the rest of the need vis-a-vis the closing? And as you mentioned around asset monetization, can you just give a sense of how much is in flight in terms of processes relative to that $3 billion?

Well, I'd say we're always looking at asset recycling. So I wouldn't necessarily tie it to the transaction. I mean, if you think about the last 4 or 5 years, it's hard to find a year in which we haven't recycled assets. But don't tie the dollars back and forth. From a timing perspective, I'd say it depends on which ones happen. The first two are basically financed, so we will have to look at what the timing of those actual approvals will be, which is going to determine which instrument we actually use. Obviously, some are quicker to exercise than others. Not meaning to be evasive, but I wouldn't tie recycling to just this transaction; we look at it all the time. If someone else has greater value on an asset than we assign to it, then we pull that trigger. If it doesn't seem to have the growth or they can do something different, we look at it that way too.

Understood. I guess that answered as a segue into the second question on the other side, just if we are thinking about capital allocation in 2024, following the announcement of the Utah acquisition, you also acquired some other businesses, the German wind incremental sale or a state, Morrow, Fox Squirrel. Generically, are other acquisitions budgeted into guidance here? And how are you thinking about acquisitions in 2024, given you're still short?

First of all, there are no other acquisitions in our budget or in our forecast, for that matter. So that's one. If anything came along, we get to see opportunities throughout North America all the time. It would have to be tuck-in; first of all, nowhere near as large as what we did last year. Secondly, it has to be immediately accretive to our share per-share metrics. Thirdly, it has to be neutral or accretive to our debt metrics as well. When I think about different parts of the business, we've got some great builds that can be done at low-medium single digits. So competition for capital will be challenging given our base businesses today and the growth opportunities they see. But again, no M&A is in our forecast other than the ones we are closing today. It's a high hurdle rate on the M&A front, and we're very focused on integrating these new assets across all segments, whether it’s renewable assets or storage assets.

That’s great. Thanks, Greg.

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

Thank you. This is a bit of a foundational question on just the regulatory compact in North America, or specifically the U.S. and it relates to the Chevron doctrine. It’s been about 40 years since the Supreme Court decided that the court should defer to a federal agency's reasonable interpretation of an ambiguous statute. If that gets discarded or removed this summer, what impact might that have on your business? How might that inform your approach to a likely higher frequency of settlements in your gas transmission business? How do you see federal agencies shifting their approach? I think there could be a few moving parts there. If you could just comment on how you're thinking of that evolving situation.

Yes, it's a good question. We'll probably have to give that some more consideration at Investor Day and walk through that a little bit. Obviously, there are several pieces to this. It depends on which part of the business, as you point out, and it's probably a much more relevant issue to our utility businesses that are coming in, particularly in the United States. For many of our other businesses, we are often seeking to settle; whether it's Texas Eastern, or whether it's the mainline tolling settlement. We like to work with customers and get more of a deal in that regard. But as with the utilities, I'll go as far as to say that long-term incentive deals like we've been able to do historically on Ontario, I think limits some of our exposure to if there's a change in the Chevron. But it's a good point, and we should probably give it a more fulsome discussion as we move into Investor Day. I don't know if Michele wants to add anything.

Well, I think at the end of the day, a lot of what we deal with at the utilities is determined within the jurisdiction at the state level. So we'll be looking to that certainly. But I think we should take that one back for further discussion.

Yes, I look forward to that as it relates to renewable policy and other aspects. But just as a follow-on, just with respect to your appeal in motion in Ontario. Can you give us an update on how you’re partnering with the provincial government because they had an intention to introduce legislation to overturn a certain aspect of the OEB decision as it related to eliminating amortization of new gas connections for homes and affordability? Can you comment on the timeline of these processes and when you expect them to be resolved? If you’re fully successful, what would the upside be versus the current decision?

Sure. I wouldn't say we're partnering with the Ontario government, but we certainly made our concerns clear to them. As you saw by the swift and decisive statements they issued within hours of the release, they were well ahead of us on the concerns. At the end of the day, obviously, we're disappointed, but this is a case where the regulators made a decision that's not in keeping with the policies of the government. Minister Smith pointed that out right away. We don't expect it to be material to Enbridge's overall 2024 financial guidance, but it's frustrating and disappointing on many fronts. There is a strong bias against natural gas, and there's a presumption that we will rapidly electrify all the heating load and abandon the gas network. That said, the fact is Ontario is not going to meet its economic growth aspirations without the affordability and flexibility that natural gas provides. The government knows that; they’ve said very clearly they need to build 1.5 million new homes in 10 years. Almost 3 million people are expected to move to Ontario in the next decade, and we have seen strong industrial and contract market growth, which is driven by electricity and natural gas for things like electric vehicle battery manufacturing. We're certainly working with the government of Ontario to make sure they understand the implications of this decision. We have filed a notice to appeal and a motion with the Ontario divisional courts. The timeline for a review motion can take 135 to 165 days. The government said they will take action, and they understand the immediacy of this issue. After all, we have a lot of focus on closing the acquisitions of these three utilities and integrating them.

Yes, Linda, I think the real milestone, as Michele said, is to see what happens at the end of February; that's a triggering event for us as to where things look like they're going. As you said, it doesn't really impact '24. The issue is from a long-term perspective; if they get this right, they will see continued economic growth and more rate base in the natural gas business. There are three other jurisdictions that would love to have our investment opportunities, and which are very positively disposed toward gas. So I think from Enbridge's perspective, the net opportunity is still more rate base, more earnings opportunity and more growth; hopefully in four jurisdictions across North America; that’s what we're ultimately focused on achieving.

Thank you.

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

Hi, good morning.

Good morning.

Just want to follow up on the last point as it relates to Enbridge Gas there. Wondering if you might be able to talk a little bit more about the timeline: how things could unfold here as you think about OEB Phase II and Phase III; just thoughts at this point given what's transpired so far? At the same time, what you're touching on there as far as when the Dominion acquisition concludes successfully, could you see capital being pulled away towards those jurisdictions given kind of what you're seeing for regulatory outcomes so far?

Thank you. Yes. As I said earlier, the indicative point will be later this month when we see what the government of Ontario comes out with in terms of rectifying this issue. That being said, there is the motion to review process that I mentioned, which will take a few months; that will likely take us until summer for things to resolve. That said, there’s plenty of work for us to do in Ontario. We're continuing to focus on investing in and ensuring the safety and reliability of the assets we have. The fact is we currently have an equity thickness for the gas utility that, although up marginally with the OEB decision, is still among the lowest in North America. The jurisdictions that are new to us, the three U.S. utilities will have thick equity. They have a good ROE, and we will look to see what the growth opportunities are. We feel very good about these growth opportunities, and we think that as they come in, the revenues will support ongoing growth in all four of our jurisdictions. We know the forecast for customer growth going forward; all the regions are supportive of that, and we will continue pushing forward on that front.

Got it. Makes sense. Thank you for that. Just a second question real quick here. I suppose you're not going to give us everything that's going to be happening at the Analyst Day, but just wondering if there's any foreshadowing or overall objectives that you see for the upcoming Analyst Day that you want the investment community to come away with?

Yes, you are right. We are not going to give you an insight here that would reduce the fun of Inverstors Day on March 6. But the fundamental fact is, and I don't believe that the stock reflects it in any way, is that we've got a growth plan extending beyond the 3-year forecast. I don't think that's being realized in the market from an efficiency perspective. We’re going to walk through how all these pieces fit together. For example, Ohio itself is a good illustration: we see opportunities to provide value for all stakeholders. We have business in liquids, gas transmission, with a utility that is looking to see growth there as well. So we think that will be a key take-home message.

Got it. Thank you for that.

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

Good morning, everyone. A bit of a broader question from me. In your conversations, you've talked about some good regulatory jurisdictions versus a more challenging decision from Ontario. Historically, Ontario has been seen as a relatively pro-gas jurisdiction and a good regulatory regime. When you look forward, especially given the fact that you'll be introducing some incremental jurisdictions here, how do you ensure that the good regulatory jurisdictions stay that way? As you move forward, how do you expect to continue to interact with the government and regulators so they see the value and need of the natural gas systems?

Sure, I can take that. First of all, let's be clear, Ontario still is progressive. If you take nothing from the statements from the Minister of Energy, take that. The fact is that in all of these jurisdictions, maintaining a strong local presence is important. We have a strong local leadership team in each utility. They’re well-known by the regulators and government staff. It’s critical to build strong relationships, working as trusted advisors, being transparent, and doing what's best for the communities. We think of ourselves as being in service. Our people are known to be strong community partners in every jurisdiction. We’ve met with the head of every public utility in the jurisdiction of the assets we’re acquiring; Ohio, Utah, North Carolina. It’s important for them to know who we are instead of being a faceless corporation. All four of them are focused on delivering reliable energy affordably. That's part of the long-term value that natural gas provides. We need to stay engaged with the regulators and help them understand how we’re doing all of this.

Robert, I think you took it to the overall Enbridge level. We're in over 40 states and 8 provinces. We've got to work to make sure that communities value our investments. The indigenous reconciliation action plan is a good example. We include groups historically left out of conversations. When you get something off balance that seems counter to a regulatory outcome, then you see those changes. And that's what you had in Ontario. The regulators are required to independently regulate consistent with government policy, and that is not what happened in Ontario. So, it's our job to ensure we're working with communities to convey this message.

All right. Appreciate that folks for the answers.

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

Hi. Thanks, good morning. Maybe I can go back to the mainline. I know you've been talking about the positive trends in terms of volumes this year. I’m wondering if you can add a bit of color on whether you think some of this is producers building ahead of TMX, or do you think it's mostly demand-driven that's driving it?

Hey, Ben, it's Colin. Thanks for your question. I've looked through most of the analyst estimates, and I think many have updated their forecasts. The notion that the mainline will lose a bunch of volume when TMX comes in is a bit of a stale concept; it was valid a few years ago. But given the delays, supply has structurally and permanently grown. It's ratable production, and that demand is almost insatiable. For instance, supply grew by 100,000 barrels a day in 2022, 150,000 barrels in '23, and in '24, it’s looking at another increase of between 250,000 and 300,000 per day. When you add that up, it's probably double what TMX is likely to move. So that's the math that gives us confidence in the 3 million barrels per day forecast for 2024. There has been some storage growth, but apportionment has been high and will continue to be high once TMX comes in.

Yes. That’s great. It’s interesting to watch. The second question may be for Greg. When you talk about a balanced business mix with Dominion before, are you considering renewables and gas together when framing the business mix, or do you think about that as a separate part of your business?

It's interesting because we put the 4 businesses, if you drew a pie chart, we put them separately. But what I was saying is that they’re increasingly more integrated in terms of what our customers want and what investors want. So if you think about it: maybe a little less than 50% will be liquids and 50% or more will be gas and renewables once those utilities close. There's no doubt that the support for renewables is needed by the gas sector. So it's back up for the utilities. They work together on multiple fronts. We’re going to talk about that at our Investor Day.

That's great. Thank you.

Our final question comes from the line of Praneeth Satish from Wells Fargo. Your line is open.

Thanks. Maybe on that last point of being split, 50% gas, renewables, LDC, and 50% liquids. I'm just wondering strategically how you think of the company pro forma for the LDC transactions. Is it more of a utility or a midstream company? In the context of that, do you think there should be more focus by investors on PE multiples and earnings rather than EBITDA and free cash flow, maybe even more leveraged credit from the rating agencies? Just curious for your thoughts on that.

Yes, it’s a bit of a mix, but I'd say we've moved to be more utility-like, even considering how we structure our renewable business. We’ve structured it differently from some others by securing long-term power purchase agreements for projects even before they're built. So I think that certainly makes us look more utility-like. I think using DCF is the right measure because it accounts for cash flows. The liquids businesses generate a lot of cash flow and don't look as utility-like. So that's the right way to consider it. Dividend yield relative to long-term bonds is another way to look at things. It’s certainly a mix of approaches. We have a bit of higher leverage for all the right reasons.

Got it. And maybe just switching gears to Gray Oak. It looks like you're close to launching an open season for the expansion in the coming months. Can you talk about if that goes well and you’re successful; when that capacity could come into service? Do you think you’ll be offering a joint tariff for transport and exports out of Ingleside, and if so, would that be a competitive advantage?

Yes. Good question. I think Colin can take that. We’ve just had the Board down at Ingleside in the last few days for our Board meeting, and there’s a lot of excitement around that.

Yes, for sure. The market should imminently expect the Gray Oak and Ingleside open season in the next few weeks. It’s very efficient capital deployment here, low multiples. Yes, we can bundle tariffs together, and we already have the lowest pricing to the terminal; that’s already a competitive advantage. However, we could do more of that. Pipeline capacity to Corpus is running effectively full already—there's probably space to Houston, but it's a very attractive path. We want to bring that capacity on in '24 and '25; there’s appetite for that. We are also building new tankage to come into service in April, independent of all of this, to further strengthen our position.

Thank you, Colin. And I would just like to thank everyone for their participation today. We have reached the end of our question-and-answer session.

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.

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