Enbridge Inc. (NYSE:ENB) Q4 2023 Earnings Call Transcript

Enbridge Inc. (NYSE:ENB) Q4 2023 Earnings Call Transcript February 9, 2024

Enbridge Inc. misses on earnings expectations. Reported EPS is $0.47 EPS, expectations were $0.5. Enbridge Inc. isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

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

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

Greg Ebel: Well, thanks very much, Rebecca and good morning, everyone. Thanks for joining us 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 the 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, for industry and for 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 the attractive multiples and put 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 as a result of the 98% of Enbridge’s earnings being 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, Enbridge will earn attractive risk-adjusted returns and 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. This 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 docs. And 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. And 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. And 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 offtake 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 more renewables 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. And 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 and 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 3 are on track to close in 2024. So 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. And 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. And then 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. And 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.

Pat Murray: Thanks, Greg, and good morning, everyone. I’m very pleased to present a record quarter and full year financial results here at Enbridge. And 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 a 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 the 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 had 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 and as expected, higher interest expense, the effect of the bought deal I mentioned earlier and lower distributions in excess of earnings from our equity investments, 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 and 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 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 time line 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.

Greg Ebel: 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. And 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. [Indiscernible] 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. And 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.

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Q&A Session

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

Robert Catellier: 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 pairs?

Michele Harradence: Sure. So let me start just with the regulatory approval. We have two out of the three federal regulatory approvals in the hands of CFIUS and HSR. We are waiting on FCC for a couple of the utilities we received North Carolina, I think earlier this week, and we expect rest of those by mid-month. And then things are progressing really well with the three utilities from a state level perspective. We expect — we still expect Ohio to go first than Utah than North Carolina and all of that through the course of this year. As you pointed out, with a couple of the utilities, we do want to be able to demonstrate a net benefit. We think overall for all of the utilities, we can demonstrate a net benefit. And a lot of that is going to be off of leveraging the fact that this creates the largest natural gas platform, 7 million customers, that ability to bring together the strengths of the different utilities rather.

So if you think, as an example, Ohio is very technically strong. Utah, a very good cost to serve, very commercially strong in North Carolina. And of course, the benefit of 175 years of multiple areas of growth in Ontario and just already having 4 million customers really allows us to scale up. So we are looking at all of those things and demonstrating all those things to the utilities. In terms of the stay outs, we will consider those if it’s appropriate. It’s part of any discussion. I mean we expect to have some requests for stay outs. I think we had one of the intervenors in Utah last week request to stay out earlier this week. And that will be something that we’ll see — we are quite confident we can come to beneficial terms with everybody.

And like I said, by bringing these four utilities together in the strengths they each have, there’s no question that we’ll be able to demonstrate net benefits.

Robert Catellier: 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 time line that was contemplated in the previous judgment specifically, where the regulatory process to vis-a-vis that time line? And do you expect any protection from the 1977 pipeline Tree? Thank you.

Greg Ebel: Yes, for sure, Robert. Thanks for the questions. And Colin is on the line, so he’s probably the best one to update on that.

Colin Gruending: Robert, yes, sure. So the appeals hearing has started, both Enbridge and the Bad River Band appealed that decision. And that hearing has begun. 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 rive around the community by June 2026. That is doable. We are ready to go the critical path, permit is a Wisconsin DNR permit, which we expect here in the next month or two, which would allow us over a year or two to build that, which is doable. So that’s the plan. And your second question was with regard to the treaty, yes. And we think that holds obviously, that’s the reason the treaties were created and we expect that to endure [ph].

Greg Ebel: Hey, Robert, I’d just add on the treaty. I think that the, one thing I’d say is I give a lot of credit to the Canadian government, provincial governments, been very strong supporters on this. So just understanding the — just really criticality of Line 5 to so many different areas, labor unions, et cetera. So 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 will see whether or not that happens. But just really strong support on both sides of the border and making sure we get through this in the right way so that all those consumers can be served. So you never know with core things, but we feel very good about the level of support that we’ve got.

Robert Catellier: Okay. Thanks for those very positive answers everyone.

Greg Ebel: Thanks, Robert.

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

Theresa Chen: Good morning. I’d like to touch on the liquid side as well. In terms of your mainline outlook for 2024, given the apportionment many consecutive months, the delays in TMX and likely tracking above where we all originally thought may one would be at this point and heading into summer 2024. What is your outlook for the system for the remainder of the year? And 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?

Colin Gruending: Yes. Theresa, I can take that. It’s Colin. Yes. So Listen, we are very confident in the mainline full path to the U.S. Gulf Coast. We think it will be substantially full the foreseeable future. I think we’ve used numbers like 95% to 100% even in ’24 through the piece. And I guess to your point, I mean, the main line has been basically full for 75 years. So it’s a trend that continues, and there’s a bunch of fundamental reasons for that. So as Pat said, we’re confident in our ’24 guidance of 3 million barrels per day on average. That assumes the April 1 CIMX and service date. But to the extent it is delayed, that’s a slight tailwind. Again, we believe we are going to be substantially full anyway. So a slight delay doesn’t provide a massive increase for us, but there is some upside to that.

I’m sure we’ll get into this more at Enbridge Day. But there’s, like, to your point, there’s a lot of demand pull on the mainline path, 39 refineries directly and directly connected traditional markets, they pull that way. We’ve got a very competitive toll. We’ve contracted as much as we can on Flanagan South. That was very successful, that should be a strong market endorsement for that pull as well. I won’t make any comments on TMX’s time line or capabilities, but very confident in the mainline path. And of course, we are building [indiscernible], I forgot about that, in Houston to further strengthen that. So yes, confident in 3.0 that’s relative to 3.1 delivered just this year. And we’ve seen, to your point, massively overscribed nominations in the last number of months including January and February.

So the trend continues.

Theresa Chen: Got it. And 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 as far as prioritization i.e., aside from additional asset sales, you would rather do DRIP ATM over additional hybrids and bonds?

Greg Ebel: No, I wouldn’t look at it like that, Theresa, it’s Greg. I think we just — I wouldn’t read anything into the listing there. I think we just wanted to make the point that look, we’ve got all options available to us. And we may not use all those options. So yes, we’ve got the debt markets unsecured notes and hybrids. And I guess if I had to go down any list, I would say DRIP was probably the least interest from that perspective. But frankly, everything is on the table from that perspective. And as you know, we’ve done a good job on recycling, too. So no, it’s going to be situational. As you know, we brought in much of the financing. So if somebody came along tomorrow and said you can close this utility or that one, we are ready to go. So I think that creates a ton of flexibility, which is why we went out early. Pat, I don’t know if you want to add to that.

Pat Murray: I think you add it with us — I think you hit it with us securing well over 85% of that funding. We are in really good shape to be selective of what we do and make sure we are making the best decision for our shareholders as we move forward.

Theresa Chen: Right. Thank you.

Greg Ebel: Thank you, Theresa.

Pat Murray: Thanks, Theresa.

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

Robert Kwan: Great. Good morning. If I can just continue on the funding side for the Dominion utilities acquisitions. So you’ve got that 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 as to — obviously, you don’t want to get necessarily into assets, but how much is in flight in terms of processes right now relative to that $3 billion?

Pat Murray: Well, I’d say — we are always looking at asset recycling. So I wouldn’t even necessarily tie it to the transaction. I mean, I trying to think about if there’s been a year in the last 4 or 5, where we haven’t recycled. So we are always looking at assets. So I wouldn’t necessarily, the dollars are back and forth fungible. From a timing perspective, I would again go down in many respects, depending on which ones happen. The first two are basically financed. So we are going to have to look at what is the timing of those actual approvals, and that’s going to determine which instrument we actually use. Obviously, some are quicker to exercise than others. So not meaning to be evasive, but I wouldn’t necessarily tie recycling to just this transaction.

I think we look at it. Look, if somebody else has got greater value on an asset than we put on it then you pull that trigger, right? And if it doesn’t seem to have the growth or they can do something different. And I think Alliance and Aux Sable is exactly that. It had commodity exposure, but relatively low growth. and it fit the buyers desire to kind of be more in that business and probably they could take more risk than we’re willing to do given our utility-like structure. So I wouldn’t tie any one of these instruments just to the transaction, I tie it more to — we’ll know more as each one of these close, which ones we’ll pull at that point in time.

Robert Kwan: Understood. I guess that answered as a segue into the second question and 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. Yes. Generically, are other acquisitions budgeted into guidance here, and I get that I’m trying to color code this to a degree, but anything else you do does kind of leave the dominion thing outstanding. So how are you thinking about acquisitions in 2024, given you’re still short.

Greg Ebel: Right. So first of all, there are no other acquisitions in our budget, right, or in our forecast that we’ve put out or in our budget for that matter, it’s the same. So that’s one. Two, if anything came along, as you can imagine, as a big player in the sector and throughout North America, we get to see things all the time. It would have to be tuck-in like first of all, so nowhere near like what we did last year. Secondly, we have to be immediately accretive to our share per share metrics. And thirdly, it would have to be neutral or accretive to our debt metrics as well. And when I think about different parts of the business, and I’m sure Colin will speak to this on Investor Day, we’ve got some great builds that can be done at low medium single digits.

So there’s — the competition for capital will be challenging given the position our base businesses are in today and the growth opportunities that they see. But we’ll have to look at it. So again, no M&A is in our forecast other than the ones that we’re closing today. It’s a high hurdle rate on the M&A front, and we’re very focused on integrating these new assets with excellent right across the board, whether it’s the renewable stuff that Matthew manages or whether it’s the Morro assets. And remember, we bought a couple of storage assets, making sure that’s all running exactly as we wanted to do is going to be a key focus.

Robert Kwan: That’s great. Thanks, Greg.

Greg Ebel: Thanks.

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

Linda Ezergailis: 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 doctor and it’s been about 40 years since the Supreme Court decided that the court should defer to an agency — 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? And how might that inform your approach to, for example, a likely higher frequency of settlements in your gas transmission business, how you might see federal agencies maybe shifting their approach, and I think there could be a few moving parts there. If you could just comment on how you’re thinking of that evolving situation.

Greg Ebel: Yes, it’s a good question. It’s — we’ll probably have to give that some more consideration at Investor Day and walk through that a little bit. I mean, obviously, there are several pieces of this. It depends on which part of the business, as you point out, it’s probably a much more relevant issue to our utility businesses that are coming in, particularly in the United States because many of our other businesses, as you know, we are often seeking to settle, whether it’s Texas Estrem, whether it’s the mainline tolling settlement. We like to work with customers and get more of a deal in that regard. But as it is with the utilities, I’ll even go as far as things like incentive — long-term incentive deals like we’ve been able to do historically on Ontario.

I think that limits some of our exposure to some of the — if there’s a change in the Chevron [indiscernible]. But I think it’s a good point, Linda, and we should probably give it a more fulsome discussion and answer as we kind of move into Investor Day. I don’t know, Michele, do you want to add anything to that, or …?

Michele Harradence: Well, I think at the end of the day, a lot of what we deal with at the utilities is determined and is inside the jurisdiction at the state level. So in that sense, we’ll be looking to them. But I think we’d better take that one back.

Linda Ezergailis: Yes, I look forward to that because, yes, even renewable policy and stuff like that, could be a little good. But just maybe 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 prudential government because they were — I think 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. And then maybe you can just comment on the time line of these processes and when you expect them to be resolved? And if you’re fully successful, kind of what the upside is versus kind of the current decision as it stands?

Sure. I can cover a few of those things. So I wouldn’t say we’re partnering with the government of Ontario, but we certainly made our concerns clear to them, although as you saw by the pretty swift and decisive statements they made within hours of the release, they were well ahead of us on the concerns. I mean, — at the end of the day, obviously, we’re disappointed, but this is a case where the regulators made a decision that’s just simply not in keeping with the policies of the government. That’s exactly what Minister Smith said right away. We don’t expect it to be material to Enbridge’s overall 2024 financial guidance, but it’s frustrating and disappointing on a lot of fronts. I mean there’s a strong bias against natural gas in there. There’s a presuppose that we’ll rapidly electrify all the heating load and abandon the gas network.

And fundamentally, it limits access to affordable energy. I mean the fact of the matter is I think there’s short-term issues and there may be some short-term struggles here. But long-term, thyet te fact of the matter is Ontario is not going to meet its economic growth aspirations without the flexibility and affordability of the natural gas and natural gas infrastructure provides it. The government knows that. I mean they’ve said very clearly they need to build 1.5 million new homes in the next 10 years. There’s almost 3 million people expected to move to Ontario in the next decade. And I don’t know that folks fully recognize this, but our — for example, our industrial and contract market growth has been really strong in the last few years, and that’s coming from things like the electrical — the electric vehicle battery, the manufacturing sector.

I was just down looking at the Nexstar plant. They need our cost-effective natural gas to support their manufacturing processes. The greenhouse developers that we have in Southwestern Ontario absolutely rely on natural gas to provide their product affordably. And things like steelmaking, whether that’s Bosco and Hamilton or others need natural gas to reduce the carbon intensity of what they have. So — we are certainly working with the government of Ontaria, making sure they understand the full implications of this decision that it goes well beyond the revenue horizon piece. I mean, to state the obvious, that impacts our ability to deliver those homes, but that’s further reaching than that, over the long-term, should it stay in place. I mean, in the near-term, it’s about $300 million in capital that it pulls back this year for us.

But again, it remains to be seen what actions are taken. We, of course, have preserved our interest by filing a notice to appeal and a motion with the Ontario divisional courts and motion to review. The motion review would likely go first. That’s what the Ontario Energy Board itself or we would set out a number of things, including the fact that there are new facts on the table, the new facts pointing to the press release from the government that clarifies its policy, the energy and electrification transition panel that sort of thing will be out there. Typically, the time line for something like a review motion of this, can it be anywhere from 135 to 165 days. And we’ll go through those steps certainly. But as you said, the government has said that they will take action and take that action much more immediately.

The legislator is coming back, I think it’s February 20. And they certainly do understand that the immediacy of the issue that this impacts us right here and right now should we reduce those levels of capital and that it’s important to them to maintain Ontario is an attractive place to invest. So I’m pretty confident we’re going to get this one resolved. It’s always good to be on the side of where government wants to go in on the side of their policy. And in the meantime, like we talked about earlier, we’ve got lots of focus on to with finalizing the acquisitions of this three utilities in the U.S. and integrating them.

Pat Murray: Yes, Linda, I think the real milestone, as Michele said is let’s 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 have an impact on ’24. The issue is from a long-term perspective, if they get this right and they want to see continued economic growth and reach their sustainability goals that means there’s going to be a greater rate base in the natural gas business, and that’s what it’s all about. And it’s kind of up that obviously, we saw this coming, but it’s kind of [indiscernible] for us that — there are three other jurisdictions that would love to have our investment opportunities and actually are very positively disposed and have legislation even giving the choice that we want Ontario consumers to have.

So I think from an Enbridge perspective, the net opportunity is still more rate base, more earnings opportunity and more growth. Hopefully, in 4 jurisdictions in North America and that’s kind of what we’re focused on achieving.

Linda Ezergailis: Thank you. Your next question comes from the line of Jeremy Tonet from JPMorgan. Your line is open.

Jeremy Tonet: Hi, good morning.

Greg Ebel: Good morning.

Jeremy Tonet: Just want to follow-up, I guess, on the last point as it relates to Enbridge Gas there. And wondering if you might be able to talk a little bit more about the time line, how things could unfold here in as you think about OEB Phase II, Phase III, just thoughts at this point given what’s transpired so far? And at the same time, what you’re touching on there as far as, I guess, when the Dominion acquisition concludes successfully, could you see kind of capital being pulled away towards those jurisdictions, given kind of what you’ve seen for regulatory outcomes so far.

Michele Harradence: Thank you. Yes. Like I said earlier, I mean, the real — and as Greg said, that really indicative point will be later this month when we see what the government of Ontario comes out with in terms of how they propose to rectify this issue and follow through on Minister Smiths statements. That being said, there is the motion to review process that I mentioned that will take a few months. I mean that would likely take till by summer for us to resolve things. But — that being said, there’s plenty of work for us to do in Ontario, and we’re continuing to certainly always focus on investing and ensuring the safety and the reliability of the assets we have and that they continue to flow and provide the gas that people [indiscernible] to want were big fans a set of customer choice.

And that’s really where, as Greg alluded to, that goes to the U.S. jurisdictions and the 3 utilities that we’ve acquired there. I mean they all have very strong equity thickness. They all have good ROEs and we’ll be looking to make sure that we understand exactly what the growth opportunities are. I mean, we’ve looked at it through our due diligence, of course, and we feel very good about the growth opportunities. I mean, Ohio has strong modernization program with very quick return on its capital. We see in Utah very strong customer growth. They’re also using a natural gas for some decarbonization activities. There’s a lot of commercial growth there. And then similarly, in North Carolina, very strong commercial and residential growth. And again, the determinization where they’re looking to move or reduce their intensity of their power production moving off of coal and into natural gas.

We’ve seen really good growth in our regulated business in Ontario. I think I’ve mentioned why I really believe we’ll continue to see really good growth in Ontario. Strong people are moving to Ontario, lots of homes wanting to be built. It’s got all the pieces. I mean, we’re towards the end of our modernization program in Ontario, but we still have lots of work to do to help industrials to reduce their intensity. But the fact is we currently have an equity thickness for the gas utility there that although it went up marginally a couple of percentage points with the decision of the OEB, it’s still one of the lowest in North America. And as LDCs, we need to compete for capital. That’s — whether that’s here within Enbridge or on a North American scale.

So these jurisdictions that are new to us, these new DOS utilities, they operate in strong jurisdictions that recognize that part of ensuring the sustainability of their energy systems and their economies includes ensuring they have a transparent, predictable and competitive regulatory regime. So we’re really, really excited about bringing them in as quickly as possible, integrating them smoothly and looking towards where else there’s growth.

Jeremy Tonet: Got it. Makes sense. Thank you for that. And just 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.

Pat Murrayaa: Yes, well., You are right. We are not going to give you an insight here that would not make March 6 that much fun actually. But look, the fundamental fact is, and I don’t believe that currently the stock reflects it in any way [indiscernible] perform is that we’ve got a growth plan that extends beyond the 3-year forecast that we put out and our expectations. I don’t think that’s being realized in the market, both from an efficiency perspective, in terms of the blending and extending of growth with the new assets that we picked up and that we’re building. And we’re really going to walk through that for all of you and how all of these pieces fit together. And I’ll just — I’ll give a brief example. Rebecca is looking at to say, don’t give too much.

But just a brief example would be think about Ohio itself, you’re just talking about the utilities. We have all of our businesses located in Ohio. It’s a good example where we see opportunities to provide customers, shareholders and stakeholders with real value added. So we have liquids lines that serve refineries there. We have gas transmission that goes through Ohio. We’ll have a great utility there that wants to see growth and Matthews get renewable assets there. So we think that is a real opportunity to create value on all fronts, and I don’t think that’s being realized. So that’s the thesis, and that’s what I want you to walk away from March 6 with.

Jeremy Tonet: Got it. Thank you for that.

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

Robert Hope: 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 and relatively good regulatory regime. So when you look forward, especially given the fact that you will be introducing some incremental jurisdictions here. How do you ensure that the good regulatory jurisdictions stay that way? And then as you move forward, how do you expect to continue to interact with the government and regulators such that they see the value and need of the natural gas systems.

-Michele Harradence: Sure, I can take that. Well, first of all, let’s be clear, Ontario still is progress. I mean that’s — I think if you take nothing from the statement from the Minister of Energy, take that, I’d also refer you to things like the powering Ontario’s growth plan that they have. So — but at the end of the day, I think with all of these jurisdictions, one of the things we really believe is that strong local presence is important. So we will — we have and maintain very strong local leaders of each of these utilities. So the Vice President and GM for Ohio, Utah and North Carolina, they’re there. They’re very well known by the regulators, well known by the folks in government in each of those jurisdictions. Just like our folks in Ontario are very well known and well respected.

I mean it’s really important to us to be seen as trusted advisers to be transparent in our dealings to do what’s best for the communities we operate in. I mean we think of ourselves as being in service. And in fact, that service name is in some of the utilities name. So those are all critical. But in order to ensure that we make the transition smoothly, it’s been very important for us to go out and meet with the regulators. I personally met with the head of every public utility that we are — that has jurisdiction of the assets we’re acquiring, whether that’s Wyoming, Utah, North Carolina, Ohio, I’ve met with their staff. I met with various members of government Grade Greg, I think you’ve met with at least two of the governors. You met with Ohio and you and I met together with Utah.

I think I’m meeting with North Carolina here in a couple of weeks, the government of North Carolina met with the [indiscernible] Governor of North Carolina a couple of weeks ago. I mean, that’s an important part of it that they understand who we are, that we’re credible that we’ll do the right thing by these jurisdictions. And I can tell you, all four 4 of them, what they talked to me about is wanting to ensure that gas continues to be delivered reliably and affordably. And that’s something that is a real advantage that all of these utilities have. I mean if you look at the storage, we haven’t talked about our [indiscernible] storage facility because maybe we haven’t had the extreme cold that we’ve had in the past. But Dawn has continued to just set records out of Ontario.

Ohio has what is the sixth major pipelines that are serving it. Utah with the Wexpro asset, again, that really — all of those things really help keep the price stable, keep it affordable, keep it reliable. Same thing in North Carolina. We’ve got an LNG facility there and we will have an LNG facility there. I can’t get ahead of myself and we, of course, the folks in North Carolina are proposing a second one. So that’s really what they care about. It’s important to keep those relationships open. It’s important that they know that they can reach out to us at any time, and it’s important for us to be listening closely to what they want for their people.

Greg Ebel: Robert, I think you’ve taken it up to the overall Enbridge level, I think whether it’s Synthes business, Colin’s business, you’ve heard both Michele or Matthews, I think we work real hard at our regulatory relationships we have to, much harder than we did historically because of some of the, what I’ll say, confusion about energy transition. And I think the whole portfolio, when you look at it from top to bottom, really fits the current state and actually probably the state that it will be in some period of time, long, long tail and future for oil, natural gas, it’s not a destination fuel. It’s an ultimate field that’s going to be — there isn’t really a future without natural gas in most parts of the planet. And that doesn’t take away from renewables.

And we get into those communities. We’re in 40-plus states and 8 provinces. And we’ve got to make sure that they value our investment. I think if you look at our indigenous reconciliation action plan is another good example. And you look at projects we’ve done to include groups that haven’t historically been involved. That’s how you build strong alliances and those strong alliances actually make the regulator’s job easier. And when you get something off balance that seems to be counter to a regulatory outcome that’s counter to policy or the communities, then you see those changes. And that’s what you had in Ontario, right? So the regulators required to independently regulate consistent with government policy. That’s not what happened in Ontario, right?

But it’s our job to keep working with these communities. And when you have issues, make sure that the homebuilders understand the implications. Make sure that the manufacturers understand the implications that our union brothers and sisters understand the implications. So I think it’s much bigger than regulatory. And as an industry and definitely as a company, I think we’ve continued to improve with that. And we’ve got to keep getting better and better at that and selling our message.

– Robert HopeTy.: All right. Appreciate that Folks for the answer

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

Ben Pham: 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. And — and I’m wondering if you can maybe add a bit of color on — do you think some of this is producers building ahead of Tmax? You think it’s more mostly demand-driven that’s driving it?

ColinGruending: Hey, Ben, it’s Colin. Yes, thanks for your question. And I’ve kind of looked through most of the analyst estimates, and I think most analysts have updated their forecast on this. And I think this notion that the mainland is going to lose a bunch of volume and TMAX comes in. It’s a bit of a stale concept. It might have been valid a few years ago, but it’s been delayed materially. And in that multiyear period of delay, supply has structurally and permanently grown. It’s ratable production and that demand is there. It’s basically insatiable. So I mean just to run through this, in 2022, supply grew by 100,000 barrels a day. Last year, in ’23, supply grew by 150,000 barrels per day in Canada. In 2024, it’s looking to grow between 250,000 and 300,000 a day and ’25 another couple of hundred thousand barrels per day.

If you add that up, it’s probably 2x what TMX is likely to practically move. So that’s kind of the math that we’re looking at and gives us a lot of confidence in the 3 million barrels per day forecast for 2024, there has been a bit of storage growth to your — maybe to your point, anticipation of that, and we see that in our nominations and oversubscribed. So apportionment has been high. It may — we may still have apportionment once TMX comes in, depending on the month or day or a crude slate. So we are going to be pretty full. I don’t know if that answers your question.

Ben Pham: Yes. That’s great. It’s interesting term events. And maybe the second question maybe for Greg. When you talk about balanced business mix with Dominion, are you putting renewables and gas when you think about that percentage and how you frame the business mix, are you — do you think about that as a separate part in your business mix?

Greg Ebel: It’s interesting because we definitely — we put the 4 businesses, if you drew a pie chart, if you will. We put them separately. But I guess what I was saying is that they’re just increasingly more integrated in terms of what our customers and I think what investors want as well even on a proportion basis. So here’s the way I would look at it. Just about 50% or once the utilities are closed, maybe a little bit less than 50% of the business will be liquids and 50% or more will be gas and renewables. So that’s probably the way to think about it from a split perspective. There’s no doubt, as you know, a lot of support for renewables is needed by the gas sector, right? So it’s back up. So they’re definitely connected.

And often, that’s done by utilities, but sometimes it’s done by independent other power plants or just the gas pipelines as well, making sure that flows. So I think we kind of — you’re right, we sort of split the liquids business and then the gas business and renewable business together. But they really are working all together on multiple fronts. And again, I think we’re going to talk about that at our Investor Day.

Robert Kwan: Okay. That’s great. Thank you, A – Greg Ebel Thank you.

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

Praneeth Satish: Thanks. Maybe on that last point of being split, 50% gas, renewables, LDC and 50% liquids. I’m just thinking maybe strategically, how you think about the company pro forma for the LDC transactions? Is it more of a utility or a midstream company? And then I guess 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 and then maybe even more leveraged credit from the rating agencies. Just kind of curious for your thoughts on that.

Greg Ebel: Yes, it’s a bit of a — I mean, I guess I would say the entire company, we’ve moved to be more utility like, right, even if you think about the MTS, Colin’s again that filled off that and both to get approved or even as you think about the renewable business, we’ve structured our renewable business very different from some of the folks that you see out there, i.e. long-term power purchase or contracts for projects even before they’re built or immediately upon construction. So I think that’s very utility-like. I think DCF is still the right look because you look at businesses like the liquids business that are generating a lot of cash flow, and they don’t look as utility like. So I think that’s the right way to consider it.

And then obviously, I think dividend yield. Dividend yield relative to long bonds and 10-year bonds of government. I think that’s the other way people should. So I think it’s a bit of a mix. And you’re right, we have a little bit higher leverage for all the right reasons, no more risk than what you’d see at pure midstream, but considerably less than what you’d see major utilities in the United States.

Praneeth Satish: Got it. And then maybe just switching gears on 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 your successful when that capacity could come into service? And then whether you’d be offering a joint tariff for transport and exports out of Ingleside and if so, do you think that concept of bundling the transport and export will give you a competitive advantage? Because as we look at the basin itself, it is kind of overbuilt from a takeaway or egress perspective.

Greg Ebel: 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. There’s a lot of excitement there. So Colin, do you want to take that?

Colin Gruending: Yes, sure. I wish I was still there, it is Snowy up in Calgary here. So the answer is yes and yes. So you should — the market should imminently expect basically gray opening in Engle side open season here in the next few weeks. I hope we talk more about that at Enbridge Day. It’s, as Greg alluded to, very efficient capital deployment here, low, low multiples. Yes, on integrated tariffs. We already have the cheapest path to the water there. It’s already a competitive advantage, but we can do more of that. And pipeline capacity to Corpus is effectively full already, probably some space to Houston, but a very attractive path to Corpus. So we want to bring some of that capacity on, call it, 100,000 to 200,000 barrels a day as soon as we can.

There’s appetite for that. It is relatively efficient, simple, plumbing increase here. So we can bring some of that on some in ’24, some in ’25. And as a reminder, we’ve got a couple of million barrels of new tankage coming into service here in April, independent of that that we sanctioned last year. So — the crawl, walk, run approach continues towards our large ambition in the Permian to create a light super system to rival the heavy super system we have. Thanks for the question. We have reached the end of our question-and-answer period. Rebecca, I turn the call back over to you for some closing remarks.

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

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