Enbridge Inc. (NYSE:ENB) Q3 2023 Earnings Call Transcript

Enbridge Inc. (NYSE:ENB) Q3 2023 Earnings Call Transcript November 3, 2023

Enbridge Inc. misses on earnings expectations. Reported EPS is $ EPS, expectations were $0.45.

Rebecca Morley: Good morning and welcome to the Enbridge Inc. Third Quarter 2023 Financial Results Conference Call. My name is Rebecca Morley and I’m the Vice President of Investor Relations. Joining me this morning are Greg Ebel, President and CEO; Pat Murray, Executive Vice President and Chief Financial Officer and the heads of each of our business units, Colin Gruending, Liquids Pipelines, Cynthia Hansen, Gas Transmission and Midstream; Michele Harradence, Gas Distribution and Storage; and Matthew Akman, Renewable Power. 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 recorded and 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. [Operator Instructions] 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 would be happy to assist you. As always, our Investor Relations team will be available following the call for any follow-up questions. On 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: Thanks very much, Rebecca and good morning, everyone. Thanks for joining us. I am pleased to be here today to review another strong quarter. We are also excited to share a number of new announcements that further enhance our long-term value proposition, and of course, provide an update on our businesses. Pat will then walk you through the financial performance, our capital allocation priorities, and our outlook. And lastly, I’ll close with a few takeaways. And as always, the Enbridge team is here to address any questions you may have at the end. Q3 was another solid quarter for Enbridge. Strong operational performance across the business drove strong financial results that were consistent with our expectations. As such, we are pleased to reaffirm our EBITDA and DCF per share guidance.

As part of the pre-funding for the Gas Utilities acquisition, we successfully raised over $8 billion in September. And when combined with the assumed debt, we have over $14 billion of required funding in place, which significantly derisks our financing plan associated with the utility acquisitions, which we expect to close on a staggered schedule through 2024. Adjusted for pre-funding of the acquisitions, our debt to EBITDA for the quarter is right at the bottom of our stated 4.5x to 5x range. On an unadjusted basis, you will note debt-to-EBITDA at 4.1x. System utilization across the business was really strong. In our liquids business, we are relaunching and upsizing an open season on Flanagan South Pipeline, which should further strengthen our mainline path.

And we are also set to initiate an open season for the Gray Oak pipeline in the fourth quarter and will offer full path Permian service by exports through Enbridge Ingleside Energy Center. In Gas Transmission, we initiated an open season on the Algonquin gas pipeline system to provide additional service to New England, where reliable and affordable gas is desperately needed. And our teams continue to demonstrate their ability to execute. We are on track to successfully place approximately $3 billion of secured capital into service by year end and our [indiscernible] large French offshore wind projects remain on budget and are still expected to come into service in Q1 2024. From a regulatory perspective, we expect to file the Mainline tolling agreement with CER before year end.

And our Ontario gas utility rebasing process is well underway and we expect the OEB will issue a decision on ‘24 rates by year end. Together with Dominion, we have filed applications for all key U.S. federal and state required regulatory approvals to complete the pending U.S. gas utility acquisition and all are still expected to close in 2024. Last but not least, on the execution front, we continue to make progress on our emissions, social and diversity and inclusion goals and remain committed to global ESG leadership. As you are aware, in third quarter, we added visibility to our growth outlook through the aforementioned gas utilities acquisitions. The assets have an embedded rate base CAGR of 8% and cost recovery mechanisms that result in improved capital efficiencies.

And in our renewable business, we are excited to announce a European offshore wind acquisition which we will discuss in greater detail in a few minutes. We are continuing to execute on our tuck-in M&A strategy and are excited to welcome the moral RNG operations team to Enbridge. These fully contracted landfill gas to RNG facilities further establish Enbridge in the RNG space. All in all, 2023 has been a great year so far, operationally and financially. As mentioned earlier, we remain on track to achieve our guidance and deliver on our growth commitments. Before we dig into the details of the quarter, I’d like to revisit our investor value proposition that we laid out earlier this year. Our business is stable and we remain committed to delivering predictable cash flows.

The balance sheet is strong and remains a key priority. We have a long track record of sustainably returning capital to shareholders and will continue to grow our dividend. We have visibility to our near-term and medium-term growth outlooks with conventional and lower carbon opportunities embedded throughout the business. All of our project announcements during and subsequent to the quarter are individually and collectively aligned with that value proposition. Each will generate an attractive risk-adjusted return that is regulated or backed by long-term off-take agreements. Looking forward, our 5% EBITDA medium-term growth outlook that we set out at Investor Day significantly derisked and today’s announcements enhance Enbridge’s lower carbon footprint across multiple business units while increasing DCF per share.

Together, these value drivers have underpinned 20 years of dividend growth and average annual shareholder returns of approximately 11% and we expect this to continue. We are confident that our recent acquisitions enhance each component of our value proposition. Let’s take a minute to review the quality of our cash flow profile. Post closings of the Gas Utility acquisition, Enbridge’s EBITDA mix will be approximately 50% natural gas and renewables and 50% liquids. During the quarter, we have seen continued volatility in interest rates and foreign exchange markets, but our longstanding active risk management strategy is designed to allow us to continue to deliver results in all market cycles. 98% of Enbridge’s earnings are currently generated from either cost of service as noted or take-or-pay contracted assets and that will only improve as we close the gas utilities transactions.

We actively manage our forward interest rate exposure through risk mitigation policies, which leave us with just 10% of our debt portfolio exposed to floating rates through the end of 2024. 95% of our customer base is investment grade and 80% of our EBITDA comes from assets with built-in inflation protection against rising costs. This enables our business to deliver consistent, high-quality cash flows, which drive predictability in all economic cycles. And we take tremendous pride in our 17-year track record of achieving our guidance and we look forward to continuing that trend this year. Turning to the acquisition of the three premier U.S. Gas Utilities that we announced during the quarter, this transaction represents a generational opportunity for the company.

Upon closing, Enbridge will be North America’s largest natural gas utility platform, delivering approximately 9.3 Bcf of natural gas per day to approximately 7 million customers. Enbridge was able to secure historically attractive acquisition multiples on the assets, creating long-term value for our shareholders. And as a reminder, we agreed to pay approximately 1.3x the estimated 2024 rate base and approximately 16.5x price to earnings based on 2023 estimates, both of which are significantly below recent precedent and subsequent transactions. Pro forma, these gas utilities further enhance the stability of our already industry leading risk profile by adding incremental regulated earnings. And those earnings will grow alongside $1.7 billion of annual low-risk quick cycle rate base investment.

Each of the utilities is located in gas supportive jurisdictions and has an attractive capital structure allowing us to earn constructive returns with favorable equity thickness. Since the announcement of the deal, we have made significant progress on the financing of these acquisitions. So let’s move on to that now. The all-in purchase price of the transactions is $19 billion, inclusive of $6 billion of assumed debt, which initially left approximately $13 billion left to finance. Immediately following the announcement, we issued $4.6 billion of common shares and issued an additional $3.7 billion of hybrid notes, which received partial equity treatment from rating agencies. In combination with the assumption of debt, we have approximately 75% of the required financing in place significantly derisking the funding plan.

The remaining financing needs are very manageable and can be satisfied through the various tools available to us, including the issuance of senior unsecured notes, asset recycling, the reinstatement of Enbridge’s DRIP program or initiating at the market common share issuances. We’ll make use of that flexibility and the staggered closing time lines to optimize the financing plan and factor in changes to the marrow economic environment. Now let’s jump into the business unit update, starting with liquids. In Liquids Pipelines, our highly competitive system remains heavily utilized with record third quarter volumes on the Mainline and significant apportionment levels in the month of November. In May, we reached a settlement for the mainline tolling framework, and those tolls took effect on July 1.

We expect to finalize that settlement with industry and submit a joint application to the Canadian energy regulator before the end of the year. With the expectation that the new tolling settlement will be approved and implemented in the first quarter of 2024, we relaunched and upsized our previously announced FSP open season in addition to contracting throughput on Flanagan South, the open season volumes also secure long-haul throughput on the Enbridge network from Western Canada to the Gulf Coast. In the Permian region, we saw a new record for export volumes through Ingleside again this quarter. Giving us further verification of and confidence in our Gulf Coast strategy. In order to support further growth in the Permian and meet our customer needs, we expect to initiate an open season on our growth Gray Oak pipeline by the end of this year and will add 2 million barrels of storage at our Ingleside terminal in 2024.

Now let’s take a look at our Gas Transmission Business. Starting in Canada, the engineering work on wood fiber LNG is progressing, and we expect to hit our 60% engineering milestones and to set our preferred return in the second half of 2024. We also closed the previously announced acquisition of Aitken Creek Gas Storage on November 1. This asset is well positioned and will enhance our service offering to our customers and support our LNG export strategy in B.C. And in the U.S. Northeast, we’ve initiated an open season on the Algonquin pipeline, which will provide much needed supply to New England and will help stabilize energy prices in the area. All told, we are continuing to progress on overall $11 billion high-quality investments in the gas transmission business and capitalize on strong North American gas supply and demand fundamentals.

Moving to our gas distribution business in Ontario. We continue to see growth in our distribution business, which is supported by population growth and customer additions. We are on track to exceed our customer additions, forecast of 42,000 for this year. Ontario population is expected to grow by approximately 2.5 million people over the next decade. All of those people will need access to cost-effective reliable energy, an Enbridge will be there to provide it. And as we mentioned on the previous call, the Ontario government has publicly promoted that natural gas will play a critical role in supplying the province’s energy mix. The need for natural gas and customer growth at Enbridge Gas will continue to underpin our estimated $1 billion of annual capital investment in Ontario for the foreseeable future.

On the regulatory front, the Ontario Energy Board approved our partial settlement to support the assessment of our ‘24 rates, and we expect them to do a final decision on the remaining items by the end of the year. We look forward to providing a comprehensive update alongside our year end results. Next, let’s take a closer look at some of the developments in our renewable business. I am pleased to announce that the acquisition of additional ownership in Hohe See and Albatross offshore wind farms, which are located approximately 100 kilometers off the Northern coast of Germany. These are assets we know well and where we have been ahead of strong relationship and partnership with EnBW. The acquisition will almost double our ownership of the assets and is expected to be immediately accretive to DCF.

The step-up in ownership of Hohe See and Albatross will materially grow the size of our renewable power business and continue our track record of investing in assets that generate utility-like cash flows, while working towards our net zero commitments. In France, we are on track to bring a gigawatt of new generation online by 2025. Fécamp will install about half of the turbines and Provence Grand Large, all turbines have been installed and all floaters have been secured. All three projects are in budget. Fécamp and PGL are expected to be in service during the first quarter of 2024 and Calvados continues to make good progress towards its 2025 in-service date. Now let’s take a deeper look at the equally attractive investment in renewable natural gas we announced today.

Enbridge has entered into an agreement with moral renewables to acquire 7 high-quality operating and fully contracted landfill gas to RNG assets located in Texas and Arkansas. The facilities we are acquiring currently collect, compress treat and sell approximately 4.5 Bcf of pipeline quality renewable natural gas each year. And as the landfills continue to grow that production number will continue to grow at approximately 3% annually, with minimal required capital investment. RNG fundamentals are strong in the United States, and indicate continued growth in demand over the long-term as gas utilities increasingly continue to set R&D blending targets. This was the perfect opportunity to meaningfully add to our RNG portfolio with an accretive Enbridge like tuck-in, which has long-term full volume off-take agreements with Shell Energy North America and BP.

Unique to this deal and in keeping with our commitment to protect our balance sheet, we’ve staggered the purchase price over 24 months. This transaction represents a uniquely derisked portfolio of operating scalable RNG assets that add immediate accretive DCF to Enbridge and accelerate progress towards our energy transition goals. Finally, both this transaction and the increased ownership in the Hohe See and Albatross operating wind power facilities were fully contemplated when we announced the acquisition of the 3 gas utilities. Now let’s turn to Pat to walk through the quarterly financials.

Pat Murray: Thanks, Greg, and good morning, everyone. I’m happy to announce that continued strong operational performance led to record third quarter EBITDA, which is up 3% year-over-year and DCF per share, which is also up 2% year-over-year. In liquids, our systems remain highly utilized, the mainline transported just under 3 million barrels per day, a record for third quarter volumes. In the Gulf Coast, Ingleside also posted record volumes, and we realized a full quarter of contributions from the increased economic interest in Gray Oak and Cactus II. Overall, strong operating performance in liquids was partially offset by the lower toll on the mainline, which took effect on July 1. Gas transmission is down slightly, primarily due to lower ownership interest in DCP Midstream following our transaction with P66 last year.

Performance at the utility was down slightly as well due to the reversal of storage and transportation favorability that we noted for investors earlier in the year would occur over Q2 and Q3. Our renewable business performed in line with expectations. We benefited from development fees earned on generation projects from our North American renewable onshore development acquisition in 2022, partially offset by lower wind resources year-over-year. Energy Services results improved versus 2022 due to expiry of transportation commitments earlier in this year and lower commodity backwardation. Below the line in DCF higher interest expense, the timing of maintenance capital and higher NCI distributions to our Athabasca Indigenous investment partners offset some of the EBITDA benefit this quarter.

Our results once again underline the low-risk nature of our businesses and the predictability of our financial and operational results that support our capital structure. With that, let’s talk about how we’re tracking the guidance. Greg mentioned, we’re reaffirming our 2023 financial guidance again this quarter. Our business outlook remains unchange, and we continue to expect high utilization across our asset base. We’ve executed a number of tuck-in acquisitions throughout the year which will contribute to our fourth quarter EBITDA, but we expect these tailwinds to be offset by the impact of the lower mainline toll and the equity pre-funding of the U.S. gas utilities. All told, we expect to finish the year with another quarter of strong operating performance, which, alongside our risk management initiatives, provides us confidence that we will achieve the full year guidance laid out for you last year, even when taking into account the equity issuance in early September.

Let’s turn to our medium-term outlook, which we’re also reaffirming. As we look forward, business optimizations remain a key area of focus for us, and we’ll continue to look for opportunities to optimize within our upcoming rebasing framework and mainline agreements. In the second bucket, the LDC acquisition bolstered our secured organic growth projects by adding an incremental $1.7 billion of low-risk annual rate base investments post closing. And finally, we are judiciously deploying our investment capacity. We’ve added another $2 billion of tuck-ins this quarter with the additional ownership of Hohe See and Albatross wind farms and the R&D assets, bringing us to $3 billion for the year. We continue to execute the strategy we laid out at Investor Day and allocate capital to deliver the quality growth we committed to.

Prudent capital allocation is core to our value proposition, and we will continue to evaluate opportunities for organic growth and opportunistic tuck-in M&A that maximizes shareholder returns. Let’s move on to our capital allocation priorities, which continue to follow a deliberate and disciplined approach. While we’ve been active in the M&A space, each transaction fits very well into our long-term strategy and add additional low capital utility-like growth to our portfolio. The funding plans we have laid out highlight our continued commitment to our stated guardrails. We carefully structured the financing of the U.S. gas utilities to be flexible and as importantly, to maintain our leverage within the 4.5x to 5x range. Furthermore, the plan articulated in September during the announcement of the LDC acquisition, had contemplated additional tuck-ins before the end of the year.

The associated incremental low-risk cash flows will help to preserve our balance sheet strength and support our growing dividend for years to come, while staying within our DCS payout range of 60% to 70%. And as always, we are constantly evaluating opportunities to recycle capital at attractive valuations. Let’s turn to our secured capital. Today, our secured growth program sits at $24 billion. New to our backlog this quarter is the addition of $1.7 billion of annual rate base investment and announced U.S. Gas Utility post closing. We concluded a 3-year program, keeping with how we present our Ontario utility growth program but we expect that level of annual investment to continue through the decade. By the end of the year, we expect to place approximately 3 million of organic capital into service, primarily through our Ontario customer additions and GTM modernization program.

Our robust secured growth program is diversified geographically across our business units and is expected to be deployed over the next 5 years. This diversity of location, timing and business unit helps mitigate against the impact of delays or inflation on any one single large project. And with that, I’ll turn it back to Greg to close the call.

Greg Ebel: Well, thanks very much, Pat. And as we wrap up for your questions. I want to leave you with a few key takeaways. Enbridge’s resilient low-risk business model is supported by our scale, diversification and high-quality cash flows, which enables us to deliver reliable growth in all market cycles. Balance sheet strength is always a priority for us, and we are committed to our debt-to-EBITDA range of 4.5x to 5x while continuing to return capital to shareholders through sustainable dividend growth. As we discussed today, the U.S. Gas Utility acquisition will enhance each of these takeaways by adding regulated earnings that enhance our cash flow quality, increased credit worthiness and underpin our dividend growth for years to come.

Our visible growth backlog, incorporating conventional infrastructure investments and lower carbon opportunities supports long-term shareholder return and positions us as a first choice investment opportunity. Finally, let me let you know that we will be releasing our guidance at the end of November for next year, and we will be hosting our Annual Investor Day in New York in March of next year as well. We look forward to seeing you there. But until then, thank you very much, and we look forward to taking your questions. I think we’re ready now to open up the lines for those questions.

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Q&A Session

Operator: [Operator Instructions] Our first question is from Robert Kwan with RBC Capital Markets. Your line is open.

Robert Kwan: Hey, good morning. If I can just start with capital allocation and specifically just the thought process around how you’re looking at leverage and the tuck-in deals you’ve announced in light of the acquisition financing that’s still outstanding and just given the current market environment. And I guess just one thing specifically. You mentioned the tuck-ins were contemplated as part of the utility disclosures. So if you can just confirm that the chart you had that had leverage kind of around that midpoint at the high end, 4.75 that these deals would not be taking leverage into the high end of the range.

Greg Ebel: Yes. Sure, thanks, Robert. And yes, definitively, that’s exactly what we contemplated. So these – both before – during the utility acquisitions and now, that is still where we are. I think equally important to we’d obviously run by those possible transactions with rating agencies, etcetera, as well. So and then from a capital allocation perspective, I think maybe just going back and thinking about we’ve been very deliberate over the last couple of years to swiftly amasodically move the corporation to a much less risky setup in a very utility leg setup, right? So recall that we first sold the Canadian G&P assets. We then went down the root of lowering our position in DCP, swapping those positions for very utility-like pipelines, lowering both any volume exposure and commodity exposure and then went on to achieve this year, what is really a utility-like mainline toll settlement and then next, the utilities as well.

And then these transactions that we announced today fit very much in that same vein, long-term contracts, great offtakes, and the same on the – with the German power projects and the same on the RNG facility, which is a little bit unique. Not everybody would do that with RNG, but we felt that’s really important. And that’s because that supports the 4.5 to 5x debt-to-EBITDA structure and continues to allow us to pay out dividends in that 60% to 70% payout range. And yes, so I’ll leave it there, Pat, do you want to add anything to that?

Pat Murray: One thing I might add is that, as you mentioned, that 60 to 70 payout range, we brought that down over the last few years or 2, so it’s at the midpoint, which should allow us to continue to grow dividends up to the level that we grow cash flows over the next go up.

Robert Kwan: That’s great. If I could just finish – excuse me, with the RNG strategy. Just where do you this business going for you? Did you see this acquisition as being more opportunistic or something that you want to build upon in similar sizes? And I guess, just generally, can you just talk about these facilities? Are they general landfills? And how do you think about just with the increasing separation of organics away from general landfills, what the risk there might be?

Pat Murray: For sure. And Cynthia is here. So maybe I’ll let Cynthia start with that.

Cynthia Hansen: Sure, Robert. Thanks. So we’re, as you know, excited about this RNG opportunity and because, as Greg noted, this is an opportunity for us to have a utility-like return. So these are unique assets. And the market is fairly large and growing. So overall, R&D, I think last year, ‘22, there was 75 Bcf in North America. It’s growing to around 95. So there is lots of growth, but again, we will be very disciplined with how we look at the opportunities. What we like about tomorrow is that it positions us as a leader in the space and that will understand and continue to be able to evaluate future growth opportunities. So it is a unique asset. There will be other opportunities like that. But again, the discipline required to make sure it fits the type of utility like structure and our ability to have those offtake agreements will be critically important as we go forward.

Robert Kwan: Your thoughts on general landfill versus targeting something that is specifically organic?

Cynthia Hansen: Yes. So you would remember that we had invested in Diverge earlier this year, which specifically addresses the food weight component. So when we look at this opportunity, where this landfill or these seven landfills are located. There is a lot of growth opportunities just there. And as Greg said, there is an embedded kind of 3% growth with very little capital outlay. So you do have to be looking at where the landfills are located. And fortunately, these assets are in geographic areas in Texas and Arkansas, where we’re going to see that growth. So we’re not concerned that there is going to be any kind of cannibalization of that kind of other food waste growth.

Robert Kwan: That’s great. Thank you.

Greg Ebel: Thanks, Robert.

Operator: The next question is from Theresa Chen with Barclays. Your line is open.

Theresa Chen: Good morning. Greg, I wanted to ask about the remaining funding options for that $4.5 billion related to the gas utility acquisitions. Can you talk about your order prioritization for those really four tools in the toolkit? And specifically related to the asset sales. Can you just help us think about valuation, execution in this market as you rotate capital and optimize the portfolio, given that there are other assets from some of your competitors are in the market as well?

Greg Ebel: Yes, for sure. So yes, let’s start there. Recycling is always have been an important part of the financial complex and methodology here at Enbridge. So – and I wouldn’t just think about it as a sale of assets. Think about things like some of our partnerships that we’ve done with indigenous communities, we did that last year. Those continue to create really great opportunities for us to recycle capital and still, frankly, be involved in the projects and maintain operational strategic control. So that’s an element. Yes, and you look across the size of the company, we’ve got various pipe assets. You can look at wind assets and renewables. I don’t think we are restricted in any way, shape or form in terms of what we will look at.

And you’re right, there is a market out there for selling assets, but we think the way that we’ve structured virtually all of our assets now that they are low risk utility like and will be very attractive, as opposed to, say, selling G&P assets in this type of market, that’s one. And then two, is we still got some hybrid move ability in there. It’s something, obviously, we will look at in unsecured notes. And then we do have the possibility of using the DRIP in the ATM. So that’s probably the route I would go down. But again, you’ve got to judge this based on what you see in the economic environment from a macro perspective. What I’m really happy about is we are a long ways down the trail of securing that financing, and it will be into ‘24 and target, say, the end of ‘24, we have all these assets in the house.

So I think we’ve structured this well by getting three quarters of it off the table and setting our stuff up well with multiple avenues to achieve the last 25%.

Theresa Chen: Got it. Thank you. And turning to the liquids business, Related to the Flanagan South open season, really interesting to see the upsizing, given that I’m sure your shippers like everyone else is evaluating the TMX sometime next year, but not only if there are enough for the previous open season, but it’s been upsized now. Can you talk about what’s driving that demand to bring barrels all the way to the Gulf Coast in your conversations with the shippers as this open season progresses?

Colin Gruending: Theresa, it’s Colin, thanks for the question. We’re less surprised. I think the fundamental in play here is a demand pull for Canadian heavy to the PADD 2 and PADD 3 for many, many years. It’s been growing and growing, growing. So we see some demand pull. I think you also see some supply push. It basically represents contracted egress in a sense, that you have variability through the mainline to get on to FSP. And as you see, the pricing basis is very wide. Now, and I think it’s expected to be wide through the decade as egress will become constrained again. So I think it’s I think it’s less surprising maybe than you’re observing. But of course, you’re building EHA to determines of that in Houston. And it’s a very competitive path or I think it bottom line underscores the resilience of the Mainline system.

Theresa Chen: Makes sense. Thank you.

Greg Ebel: Thank you.

Operator: The next question is from Robert Catellier with CIBC Capital Markets. Your line is open.

Robert Catellier: Hi, good morning. I wondered if you could start with giving us a description of how you think the recent Supreme Court depending on the impact of Assessment Act that will impact your appetite for asset development in Canada?

Greg Ebel: Yes. Robert, I think it’s a little bit early. Obviously, you can read a lot of tea leaves in this. The federal government says they are going to make some adjustments and fix that. I’m not sure exactly what that means. And so we will have to consider that over the coming months and year. So that’s one. I think you also have to think about it from the clean electricity standards. And none of this really immediately solves just the overall getting certificates to move forward with major pipelines from my perspective. So I’m not – I think it’s status quo at this point in time. I don’t see it impacting any of the projects that we have in a big way in Canada. As you know, most of those are inter – intra provincial.

So whether it’s things going on in Ontario or major projects in British Columbia, they are within the province. And so I don’t see a major issue from that perspective. But I just think it’s early days, wherever we will have to see, it’s not easy to build anything anywhere. And that’s why we kind of like having that portfolio of businesses where we can pick and choose with the best returns and the most accretive projects across multiple jurisdictions. But yes, I think time is going tell I would say a better answer for you, Rob, and I just don’t think it’s clear yet where they are going to go.

Robert Catellier: Right. Okay. And then a similar question in the U.S. As you look at U.S. offshore wind projects having some difficulty with supply chain and everything else. How does this play into your gas transmission assets, including the Algonquin open season? And what do you think is possible with respect to that open season in terms of the scale of what you might accomplish?

Greg Ebel: Yes. I’ll let Cynthia answer. But I guess just from a macro perspective, I think we’ve been extremely careful at Enbridge of considering pace. And I think the pace of the transition, I think it served us very by sticking with gas assets with liquid assets with keeping our renewables business going. So I really do think we – you’ve heard us pitch it for a long time in all of the above strategy, and it’s going to continue. But if anything, the last 24 months, whether it’s activities in Europe, the war between Russia and the Ukraine or the war in the Middle East, the instability that’s out there has really underline the need for North America infrastructure and North America infrastructure that looks at exports at to help in us stable regions. And probably one of the worst served areas is the Northeast. So Cynthia, do you want to speak to that?

Cynthia Hansen: Yes. Thanks, Greg. We have been participating in many technical conferences with FERC and others to just address those issues. And these are near-term reliability concerns. So yes, there’ll be more in the future potentially for those concerns if you see any wind development scale there. But this is really to this open season is to address near-term issues as well as some peaking issues that are starting to create these problems and dynamics in the Northeast. So we have two different actions that we’re speaking to the – our customers up in the Northeast as for this project maple sound receive another sample. So what we see for that opportunity, one would be up to 500 dekatherms per day, the other received is 250 dekatherms per day.

So there has been a lot of interest. We are having great conversations. That open season closed on November 17. So more to come as we work with our customers to find what the best received client was that build-out is, but we will continue to do that. And service dates for these projects is targeted to be in 2029. So lots of work to go, and I’m sure we will continue to have more and more discussions as we see more of that energy transition in the U.S. Northeast.

Greg Ebel: Hey, Robert. And the only other thing I’d add is kind of related. I really don’t see North American offshore as something that’s attractive to us, it would not fit our risk parameters from a return perspective, a risk and getting it very different than what we’ve seen in Europe with really long-term contracts with things that actually get done on time. I think people often forget there is only one operating offshore wind facility in North America, I think, still today and it took 1.5 decades to get done. Maybe there is 2, but they are small. So that – just to be clear, that’s not something that we find attractive.

Robert Catellier: No, I understand that last point. I was just saying the dynamics offshore or offshore one are actually playing into your hands with your gas assets. But thanks for those answers. Thank you.

Greg Ebel: Thank you.

Operator: The next question is from Jeremy Tonet with JPMorgan. Your line is open.

Jeremy Tonet: Hi, good morning.

Greg Ebel: Hi, good morning.

Jeremy Tonet: Just wanted to come back to the compensation of capital allocation if it could, especially in light of rates moving up sharply here. I’m just wondering how that has impacted your thoughts on the different components of capital allocation. Particularly as it relates to acquisitions on renewables, I think there is a concern in the marketplace that the returns there are a bit more – or a bit lower. And so just wondering how you see that factoring in times it seems like in midstream, there is a preference for return of capital here. So just wondering how that all kind of blends together in this new environment.

Greg Ebel: Sure. I’ll start, and then Pat can chime in. Look, obviously, we’re not blind to interest rate move. So from a direct exposure perspective, we have virtually no floating rate debt this year, and we’re around 10% next year. So that’s obviously an important factor to consider. Secondly, most of our virtual or regulated assets have some element of inflation and pass-through on interest rates. Often impacting the return on equity, i.e., increasing it. And then the third point I would make is, obviously, higher interest rates mean that – as we – the size of our company gets so many opportunities coming out of the business units have to hit a higher hurdle to make sure that those projects are accretive. On the wind stuff specifically though, I think that’s why you see that in both the asset the German offshore asset and even on the RNG stuff, long-term contracts are really important to make sure that you know what you’re getting into and the return before you finance it.

So Pat, you want to add further to that?

Pat Murray: Yes. I think that’s right. I think when you think about your comment around certain renewable assets may be getting not the returns and yet, I think we do see that in the market and those aren’t ones we’re interested in. The one we’ve just announced today is an asset we’re very familiar with. We’ve been operating and running it for a number of years. It’s got a long contract left on it. So it’s very specific in the Europe offshore opportunity for us. And then in North America, we continue to look for things to do. But again, we’re going to be very selective, they are going to have to meet the increased hurdle rate, as Greg talked about. And they are going to have to really fit into that risk, low-risk nature with lots of long-term contracts EPC agreements, things like that.

So I think we’re very comfortable with the ones that we’ve announced today, and they’ll have the new products [indiscernible] will have to compete at an even higher clip than they have historically. And Jeremy, from a return on capital perspective, obviously, the dividend has always been the key component for us here at Enbridge. And I think we are very set up nicely and comfortable with our 60% to 70% payout. That’s allowed us to fund businesses internally, but also make sure that we will reward shareholders and our owners who we’re talking about decades of steady, reliable dividend growth and expect that to continue.

Jeremy Tonet: Got it. Thank you for that. And just with offshore wind a little bit more here, just wondering if you could confirm whether you are going to consolidate the newly acquired wind farm into EBITDA, it seems like I think on the slide, there is a significant increase in EBITDA in 2024. So, wondering on that there. And just to confirm, I guess on the last part there as far as renewables that hold the most interest for you where there could be future acquisitions. It’s really European offshore wind in U.S. North American RNG kind of the two focal areas if there is going to be future renewable purchases?

Matthew Akman: Well, Matthew here, yes. Remember, this is a German project that we have been involved with. So, there is – yes, it will be consolidated in the power business. I am not sure we have got offshore renewables in Europe today that we are building out and we are very comfortable with those and love those and the contracts that they have. But obviously, you will recall that we bought a solar and renewable development business here in the United States last year and we are very focused on building out those development projects that they have, too. So, it may not be so much on the acquisition side. I am sure we will look at picking up stuff for the reasons you pointed out. But Pat, do you want to speak to Europe and/or U.S.?

Pat Murray: Sure. Maybe just briefly to add, not a lot more to add, but I think the key is our strategy here has been really differentiated. As you can see, we – there is a lot of turbulence in this space. I think our strategy of being disciplined focusing on contracted assets has really panned out for us here. And this was more of that. These assets that we are picking up today still 17 years left on the PPA. It’s basically government backed. We have years of operating history, double-digit returns still on these. So, they are very good returns and a great partner that’s the kind of stuff we will do. We are going to be very, very selective, especially in offshore given what you are seeing out there. And then with onshore, we are basically organically driven in the U.S. We have got some great projects that are advancing nicely, still on track to realize project FIDs in the coming months on some of those.

But again, they always have to hit our return parameters. We have to de-risk them and ensure we have the right commercial construct. But we do see more growth, particularly on the organic side in North America as we head into early next year, Jeremy.

Greg Ebel: And maybe, Jeremy, I would just add, I think your question around consolidate may have been how we are going to reflect in our financials. We will still own just under 50% to equity account for this going forward. There is, as we noted, a piece of debt that comes with it that will be on our books. But otherwise, we will just equity account for this asset.

Jeremy Tonet: Got it. Very helpful. Thank you.

Greg Ebel: Thanks Jeremy.

Operator: The next question is from Linda Ezergailis with TD Cowen. Your line is open.

Linda Ezergailis: Great. Thank you. Just stepping back a little bit, trying to understand there seems to be a growing amount of opportunities given your incumbency in certain regions. Where are – do you expect to see the most investing opportunities over the next years? Can you just stratify between utilities, renewables, RNG, carbon hydrogen ammonia when might we see that ramping up versus your legacy gas and liquids pipelines because you do have some liquid initiatives going on as well. Can you just help us understand that? And then further to that, looking out over the medium-term as well, is tuck-in going to be the tilt and the focus, do you think, given that you might get some immediate accretion from that versus the longer lead times for building, or can you comment on the mix that you expect tuck-in versus greenfield, brownfield?

Greg Ebel: Sure. Let me try to unpack it a little bit. So, from an opportunistic perspective, from a dollar size perspective, I think if you look at our backlog, the biggest piece is in the gas transmission business. The second biggest piece is in the utility business now that we bring on the three utilities in the U.S., I think there is about USD3.5 billion of capital there through ‘27. So, those are the two big chunks. But as you pointed out, there is great opportunities on the liquids side, which are super efficient from a capital perspective and therefore, very highly returning. And then Matthew’s business has got the development projects. So, I think there is a little bit in every area. I would say in terms of tuck-ins, yes, we look at everything.

We have got the big utilities to bring on site. But as Pat pointed out a little earlier, the tuck-ins have to meet some high hurdle rates from an accretion perspective. So, it’s a little bit of everything. I don’t see us doing any major M&A here as we bring in the three utilities in the United States to make sure that they are fully integrated with the system. But we see a lot of stuff. And I think that’s a great opportunity for us to really high-grade those opportunities for the business units to sharpen their pencil on that front. And then ultimately, we got to make sure that it stays within our 4.5x to the 5x debt to EBITDA and allows us to continue to grow the dividend. So, yes, that’s where I would feel. Pat, I don’t know, would you want to add anything to that?

Pat Murray: Yes. I mean maybe just a comment on kind of the mix of tuck-ins versus longer build. I actually think we kind of like the mix that we have. If you think about the longer lower multiple build projects that we have in the BC where we have got – it takes a little bit longer, but it’s a good returning very low risk part of the cost of service type asset. Then you supplement that a little bit with some of these tuck-ins that have immediate cash flow that comes in right the door. And then add to that, you have got these new utilities in the U.S. that have really quick capital. It’s not kind of the benefit of both of them, which is – it’s got the low multiple and it comes in quick and you get a return on it quick. So, I think we like the actual complementary way that these all operate together, and it’s why I think we like that we have that optionality. So, I think that’s all I would add to that, Greg.

Linda Ezergailis: Thank you. Just a quick follow-up. Just trying to understand when we might start to see your FIDs on any sort of carbon capture or hydrogen or ammonia related projects, might we see something significant on that front over the next 12 months to 24 months?

Greg Ebel: Yes. Maybe I think 12 months might be kind of tough base has been an important one, but it depends at least from the CCS here in Canada and the Gulf, you want to speak to those and then maybe Michelle a little bit on hydrogen too.

Michele Harradence: Yes. No, it’s a great question and we are working on a number of options, I think as Pat has laid out. So, in Canada, [indiscernible] I think everybody is kind of ready for, we need some policy conclusions from our Federal Government here. But I think everyone is in a position to take investment decisions if those come through, later in 2024, for example. And if you want to put points on the board in Canada, that would be a timely plus at Ingleside our ammonia project and carbon hub there, late ‘24, early ‘25 FID there. Anybody want anything…?

Greg Ebel: Well, I think we have got hydrogen opportunities in Chile [ph] too that’s pretty new. But that’s kind of a late decade stuff. So, going to be real careful on that front. I think things like the renewables, things like the RNG and CCS, I think those are more near-term opportunities. I think the hydrogen. The blue ammonia project is different, given the players that we are working with there, both our sequestration partner there with Oxy and the assets we already have there from a pipeline perspective. And then, of course, the great export facility, we have a fabulous partner in Yara, who – they are a business that they are largest user of ammonia in the world. So, that may be a little bit unique. But we are going to be careful on that front.

Linda, with that it goes back to this space issue. You want to – you don’t want to be on the bleeding edge. You want to be on the leading edge, and we have got $25 billion of organic projects set today. So, delivery on those is our first and foremost priority.

Linda Ezergailis: Thank you.

Operator: The next question is from Robert Hope with Scotiabank. Your line is open.

Robert Hope: Good morning everyone. Two quick ones for me. I want to go back to the discussion on the tuck-ins. Just given the choppiness that we are seeing in the markets currently with the rising rates as well as, we will call it, lessening availability of capital for some participants. Have you seen the valuations for potential tuck-ins come down such that you may want to accelerate investments in them?

Greg Ebel: Well, we have definitely seen some valuation come down. I wouldn’t say we want to accelerate. We have been very disciplined on that. As we have said, historically, and you got $2.5 billion or $3 billion of capacity available to do tuck-ins. So, that’s going to be a good regulator for us as well. But yes, you have seen some multiples come down, but it depends on the assets, right. It depends on the contracting of those assets. It depends on the seller do they need to sell to us. So, I don’t think you can universally look at that and say maybe not tuck-ins, but obviously not tuck-in us buying the three utilities. But the price we get there was really fabulous, but you then saw follow-on transactions from other folks selling gas utilities, which were more typical 1.92x rate base.

So, I think it just depends on the seller in the location. But I would say it’s definitely, there is lots of opportunity out there, and that lets us be very choosy while still staying within our 4.5x to 5x debt to EBITDA targets.

Robert Hope: Thanks a lot. And then just moving over to Dominion, while early days, kind of any incremental feedback you can give on your discussions with stakeholders there, looks like HSR is good.

Colin Gruending: Michele has been waiting for your questions.

Michele Harradence: Thanks very much. And thanks, Robert. Things are going really well on the – bringing the utilities in. We certainly – we filed all the key required applications federally and in the states of the jurisdiction for regulating the utilities. We have got a dedicated integration team that’s set up with a senior leader on it that really has a lot of experience in the utility and in the integration side of things brought together the Spectra and the Union Gas and Enbridge Gas side of things. And we are really happy with the relationship we have got with merchant union. So, I actually have the pleasure of probably 30 or more town halls across the three utilities following the announcement. And I have met with the chairs, commissioners and customer advocates of the public utility commissions in each state.

And I have to say the reaction has been universally positive. The commitment that Enbridge has to local communities, the important role natural gas has to play in the energy evolution. And really importantly, the best-in-class safety and reliability has all been super well received by employees, by all stakeholders. So, we are feeling pretty good that we should be able to meet the timelines we have set out for ourselves. I mean it’s early yet to see anything from interveners, but we really don’t expect to see any significant barriers to our expectation that we closed on all of them by the end of 2024. Just maybe a little more detail. We probably expect Ohio to go first, followed shortly after by Utah and Wyoming and then North Carolina, we expect to close last and that’s not really due to any concerns.

It’s just the order is really a function of the regulatory processes in each jurisdiction, things are going great.

Greg Ebel: Yes. The only thing I would add is I don’t say that Dominion has been awesome from a coordination perspective, and obviously, they want to get the transactions close. But some period of time through the heat and negotiations, not everybody is on the same page and they have just been a class act and they want to make sure these are done well, both for the people, both for the business and obviously, the customers we serve and obviously, great alignment on making sure we do the right thing for our investors as well.

Robert Hope: Thank you.

Greg Ebel: Thank you.

Operator: The next question is from Ben Pham with BMO. Your line is open.

Ben Pham: Thanks. Good morning. And can you comment on what was driving the strong mainline volumes during the quarter and then the flow-through to rail exports?

Colin Gruending: Hey Ben, it’s Colin. Yes, thanks for the question. The mainline is super resilient. I think you have proven that over and over and over for decades. Speaking to the quarter, supply has been building. I think maybe that’s been quietly lost in the equation here. So, we have seen supply quietly grow or significantly apportioned during the last couple of the months to prove that point out. Keep in mind, we are doing everything we can to move every barrel we can. We are incentivized to do so to win-win for Enbridge and customers. And therefore, some of that spilled over into rail exports, right, to clear the market. The market is backwardated, so producers want to monetize their product quickly and inventories are kind of average historically speaking.

So, there is still a lot of demand pull utilizations or high refineries from activity and also demand pull there from a dearth of foreign imports. So, I think most of the stars are aligned to support mainline volumes here. And I think you will see this in our late November guidance when we put segment guidance out. I think we are going to see strong liquids EBITDA forecasted for ‘24 on the back of what we were just talking about, Ben. So, don’t see a lot of TMX offload. I think that concept is being oversimplified generally. And I think we are going to see pretty robust volumes in ‘24 as well.

Ben Pham: Okay. Thanks for that Colin. And maybe on the balance sheet, could you update us remaining hybrid capacity room. And given reinvestment program, are you able to share what’s the key driver of initiating that? And how early or how late could you have to make the decision?

Greg Ebel: So, I think on the hybrid, I think the reason we said we had in the range of $4 billion to $6 billion of hybrid capacity. We saw us do about $3.5 billion, $3.6 billion of that right after the announcement. So, we have got some capacity there as we go through it. And sorry, the last comment was on the DRIP. Yes. I mean I think we will consider as we talked about all the options that we have whether that be asset sales more hybrids as you just talked about, the fact that ATM or DRIP will assess that. We haven’t activated it as we speak yet. It’s something we will consider as we move through the year at our capital needs.

Ben Pham: Can I maybe follow-up on that, but let’s say you have initiated the DRIP starting ’24. And you see a quick calculation that doesn’t meet the 25%. But if you push it into 2025, it can meet it. Is there opportunity for now in your discussions of agencies and your funding plan that could work or you need to fulfill everything by the end of 2024? Does that question make sense, yes?

Greg Ebel: Yes. I mean I think we have had really good conversations around the fact that we have committed as we have to the equity markets and to our fixed income investors that we will finance this appropriately. We will get the projects in by the end of 2024, and we will do what we have to do from a balance sheet perspective to make sure that we are in good shape entering ‘25. I think ‘25 is really a year that they are most interested in because that’s what will have all the EBITDA. And so we have got some time to do this, Ben. Remember also that there is lots of different options we have as we move through this. And we will see which is most beneficial to our shareholders and our bondholders as we move through that.

Colin Gruending: Yes. I think you could – let’s see how the other pieces go, we are highly confident in our ability as we have talked about, given historics on recycling. And then as Pat said, you have got the other capabilities and then you look at whether you need to drive the AGM.

Ben Pham: Got it. Thank you.

Operator: Our final question is from Brian Reynolds with UBS. Your line is open.

Brian Reynolds: Hi. Maybe to follow-up on some of the capital allocation questions, perhaps through the lens of how transformational M&A is going to impact some of the return of capital opportunities over the near-term. Can you just update us on the dividend per share outlook of 3% to 5% as we think about 2024. Is that maintained, or could we effectively see Enbridge optimize long-term shareholder value by supporting the balance sheet as it executes some of these funding needs over the near-term? Thanks.

Greg Ebel: Yes. Absolutely. Look, I think we can do more than one thing at one point in time. And I think we have proven that historically by staying in that 4.5x to 5x on the debt to EBITDA and the balance sheet structure as well as return capital to shareholders. And the best way to do that is through dividend growth. And as we have said, we expect to grow the dividend consistent with our DCF. You have seen us do that over time, and I think you can expect to continue to see that. But I guess I would hedge a little bit from, yes, we will lay all that out for you in our guidance for next year. But I – we are very comfortable with where we are on dividend payout and where we are on the balance sheet. And that is all driven by the fact we have deeply reduced any risk of the business by setting up utility type structures in all of our businesses.

So, we think that’s the right structure. It’s a bit unique than other folks. But and you see that even this quarter, some companies have G&P and have moved around and they have seen valuations change from a G&P perspective because you have got volume risk and commodity risk directly or indirectly. We don’t have that. Virtually, none of it. We got a little slug of DCP left. But instead, you have got a very risk resilient and reduced entity over the last several years. And again, we think that allows us to both do what we have been able to do on the balance sheet very comfortably and return shareholders’ capital through dividend growth.

Brian Reynolds: Great. Thanks. Appreciate that. And as a quick follow-up, the realized toll seem to be much higher than the posted toll for the quarter. So, can you just help us understand the drivers there? And as we think about the mainline pooling settlement pushed from Q2 to Q4 for October – from October, anything to read into that? And just to confirm, is there anything that can effectively change between what was announced and what will be final? Thanks.

Colin Gruending: Yes, it’s Colin. Maybe the latter point first. Yes. No, we are working with industry to fully paper the settlement agreement from May, it’s unchanged. I wouldn’t read much into it. It takes time and there is also other things that we been working on other applications and filings from others. But it’s trending valuation [ph] of that filed before year-end. I think on the performance during the quarter, I think it’s all of the above, volumes, toll costs, everything. So, we are managing that asset as industry has incentivized us to do so. And I think you should expect more of the same.

Brian Reynolds: Thanks. I will leave it there.

Operator: Thanks so much. I will now turn it over to Rebecca Morley for any 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 good day.

Operator: Ladies and gentlemen, this concludes today’s conference call. Thank you for participating. You may now disconnect.