Enbridge Inc. (NYSE:ENB) Q2 2023 Earnings Call Transcript August 4, 2023

Operator: Ladies and gentlemen, welcome to the Enbridge Incorporated Second Quarter 2023 Financial Results Conference Call. My name is Abby, and I will be your operator for today’s call. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session for the investment community. [Operator Instructions] Please note that this conference is being recorded. And I will now turn the call over to Rebecca Morley, Director of Investor Relations. Rebecca, you may begin.

Rebecca Morley: Good morning, and welcome to the Enbridge second quarter 2023 earnings call. My name is Rebecca Morley, and I’m the Director 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, Liquid Pipelines; Cynthia Hansen, Gas Transmission and Midstream; Michele Harradence, Gas Distribution and Storage and Matthew Akman, Renewable Power. As per usual, this call is being webcast, and I encourage those listening on the phone to follow along with the supporting slides. We’ll try to keep the call to roughly 1 hour. And in order to answer as many questions as possible, we will be limiting questions to one plus single follow-up, if necessary.

We’ll be prioritizing questions from the investment community. So if you’re a member of the media, please direct your inquiries to our communications team, who will be happy to respond. As always, our Investor Relations team will be available following the call for any follow-up questions. On to Slide 2, where I’ll remind you that we’ll be referring to forward-looking information during today’s presentation and question-and-answer period. By its nature, this information contains forecast assumptions and expectations about future outcomes, which are subject to the risks and uncertainties outlined here and discussed more fully in our public disclosure filings. We’ll also be referring to non-GAAP measures summarized below. And with that, I’ll turn it over to Greg Ebel.

Greg Ebel: Thank you, Rebecca, and good morning, everyone, and thanks for joining us. I’m excited to be here today to review our strong second quarter results and provide a business update. I’ll start off by doing a midyear check-in on some of our key priorities that we laid out for you at our Investor Day. I’ll then take you through some updates from our four businesses and provide highlights from our 22nd Annual Sustainability report. I’ll also highlight how our industry-leading diversified cash flow profile underpins our strong balance sheet and will continue to support Enbridge as a first choice investment opportunity. Pat will then walk you through the financial performance, our capital allocation priorities and growth outlook.

Lastly, I’ll close with a few key takeaways. And as always, the Enbridge team is here to address any questions you may have. Q2 was a really good quarter for Enbridge. We saw high utilization across our assets and had strong financial results, consistent with our expectations. This performance puts us on track to meet our full year EBITDA and DCF per share guidance. Our balance sheet is in great shape. We have a high investment-grade credit rating, and we exited the quarter at 4.5 times debt to EBITDA, the very low end of our targeted range of 4.5 to 5 times. We are pleased to have reached a settlement in principle with shippers on the mainline tolling early in the quarter, which was great news for us, our customers and the industry overall.

We will provide an update on next steps when we discuss our business units. On growth, we made good progress on our U.S. Gulf Coast crude oil strategy by extending and upsizing Flanagan South Open Season, where we saw very strong interest for customers for that pipeline service. We also sanctioned new storage capacity with Enbridge Houston Oil Terminal [indiscernible] enhancing the competitive profile of our mainline system to deliver Canadian oil to the U.S. Gulf Coast. We have filed a partial settlement on our utility rebasing application, which includes important matters and has been verbally approved by the OEB pound. We expect a final outcome on 2024 rates by Q4. This will provide benefits to our investors and customers and will support Ontario’s population growth, energy affordability and economic growth in the products.

We continue to see growth opportunities in our renewable business and anticipate reaching FID on certain U.S. onshore development projects by year-end. And we’re pleased that next decade reached FID on Phase 1 of their Rio Grande LNG facility. We are in the process of obtaining necessary permits and regulatory approval for our Rio c Pipeline project and plan to start construction in 2025. We’ve executed over $1 billion of accretive tuck-in M&A year-to-date. In Liquids, we increased our ownership and acquired operatorship of Gray Oak pipeline, which delivers crude to our world-class export facility at Ingleside. In Gas Transmission, we enhanced our North American LNG export strategy by closing the Trace Platos [ph] natural gas storage acquisition and acquiring Aitken Creek natural gas storage facility, which we expect to close in Q4.

Lastly, we continue to sustainably return capital to our shareholders. On and all, a great start to the year. And as mentioned, we are on track to achieving our financial guidance, and we are making good progress on our growth commitments, which include all forms of energy across our premier franchises. We continue to believe that all forms of energy will be required for years to come. Natural gas and oil will remain critical components of our energy supply in all energy transition scenarios that balance the energy trilemma of reliability, sustainability and affordability. Our asset network is large, diverse and unmatched providing opportunities to grow each of our base businesses, while our customer relationships, diversified asset footprint and capabilities open up new opportunities for lower carbon investments.

Now let’s take a closer look at some of the recent highlights in our business units, which support our low-risk pipeline utility model. Let’s start with Liquids. In Liquids pipelines, the mainline system remains highly competitive. We saw record volumes in the first half of the year and extended and upsized a binding open season for the Flanagan South pipeline. FSP will approach being 90% long-term contracted, reinforcing strong utilization of mainline infrastructure, delivering barrels into Chicago and downstream infrastructure serving the U.S. Gulf Coast, including the Seaway Pipeline and Enbridge Houston oil terminal. The Liquids system really is one of a kind. It provides attractive transportation access to approximately 75% of North America’s refining capacity.

As mentioned, we reached a win-win-win mainline tolling agreement in principle with our customers in May. This was the result of committed engagement and negotiation by both our team and the shipper representatives. The settlement will provide utility-like returns and aligns with customers’ desire for safe, reliable service at a competitive toll.

5: Cash flows generated by the asset will be protected from inflation with O&A and power expense escalators set to begin in mid-2024 with annual increases thereafter. In terms of next steps, we expect to jointly finalize the settlement with industry and submit an application for its approval to the Canadian energy regulator by October, with the expectation that the new tolling settlement could be approved and implemented later this year. Now Line 5 has made a few headlines over the past few months. So I thought I’d spend a few moments addressing our position on what’s happening in Wisconsin. We were pleased that the Federal District Court agreed that Line 5 continues to operate safely and is critical infrastructure delivering life-saving energy to millions of consumers downstream.

3 years ago, we filed for a 41-mile reroute in Wisconsin to relocate the pipeline of the Bad River Band land. We believe the pipeline can be relocated in the 3 years provided regulatory approvals are obtained in a reasonable time frame. And as a reminder, the new mainline tolling agreement also provides support for investment in both the line fiber plant in Wisconsin and the tunnel project proposed in Michigan. Line 5 continues to operate safely and reliably, and we look forward to working with the Bad River Band regulators and other stakeholders to relocate Line 5 with no service disruption expected. Looking at our Permian strategy, the Enbridge Ingleside Energy Center is turning out to be an all-purpose with Army node [ph] It is indeed a one-of-a-kind terminal with the largest crude export capacity in North America, on-site storage and a suite of lower carbon development opportunities, including renewable power.

We’ve seen record quarterly volumes at the facility and our Gray Oak Pipeline, confirming our belief that a full past service for our customers from the Permian to Tidewater is a highly attractive competitive offering. In March, we signed an LOI with Yara to jointly construct a blue ammonia production facility at Ingleside that is backed by a long-term offtake agreement. We’re also planning to construct a carbon capture and sequestration hub in the region as part of our previously announced partnership with Oxy Low Carbon Ventures. A key competitive advantage of the terminal is ownership of two pipelines, Cactus II and Gray Oak that deliver Permian crude to the facility. We are looking to expand Gray Oak pipeline by up to 200,000 barrels per day with an open season planned for later this year.

Additional capacity will provide customers with access to low-cost, integrated value chain that provides operational synergies and the lowest cost of Tidewater from the Permian. Now let’s move on to some of the exciting developments in our gas transmission business. In the U.S., we are excited about next decade announcing a final investment decision on the first three trains to export LNG from their Rio Grande LNG facility at the Port of Brownsville. Now this allows us to advance our Rio Bravo Pipeline project, which will supply 100% of the feedstock gas to the terminal as a key part of our U.S. Gulf Coast strategy. We are in the process of obtaining necessary construction permits and notice to proceed from FERC for the project with commercial operations expected in 2026.

We recently closed our acquisition of the 35 Bcf Tres Palacios gas storage facility, further supporting LNG customers along the Gulf Coast. We’ve seen recontracting rates move significantly higher, and permitting is underway to expand the facility by up to 6.5 Bcf and we will work with our customers to deliver more capacity in the next 12 to 24 months. Currently, we provide service for 15% of the export capacity on the Gulf Coast through 4 LNG facilities operating in the region, and we expect to grow that position to about 30% of the market share by 2030. In the U.S. Northeast, we’ve identified significant and scalable expansion capability on Texas Eastern, which kept through the heart of the Appalachian show. Our Appalachia to market projects are a perfect example of this, and we look forward to helping Appalachia gas reach the growing markets for all gas in all directions.

In Canada, the engineering work on wood fiber LNG is progressing on schedule, and we expect to set our preferred return early next year. On our West Coast pipeline system, we’re progressing $5 billion of investment on the T-North and T South systems to feed West Coast LNG terminals and other industrials in the Pacific Northwest. On T-North, we’ll be looking to relaunch a binding open season for a second expansion of that BC pipeline system by year-end. You’ll recall that we were acquiring Aitken Creek gas storage. Closing is on track to occur later in 2023. This asset is well positioned and will enhance our service offering to our customers and support our LNG export strategy in British Columbia. So now let’s take a look at our gas distribution business.

We are expecting another strong year of customer growth. We’re on track to achieve more than 42,000 new customers with 21,000 added year-to-date. Ontario’s population is expected to grow by over 2 million people over the next 10 years, making natural gas critical to meeting customer energy demand. On the industrial side, there are a few economic alternatives to natural gas to meet demand, and we’re seeing tremendous growth opportunities across all sectors. On the rebasing application, we have held the supplement hearing for our new incentive rate application for the period of 2024 to 2028. We negotiated a partial settlement on important matters such as operating rate base and operating costs with recommended approval by the OEB staff. There are still some important items that need to be settled, including equity thickness and depreciation, but we expect a regulatory decision by year-end and plan to enact new rates on January 1, 2024.

Our focus on cost optimization and reliable service has allowed us to consistently achieve above the base ROE, as you can see in the chart on the right. We have a long track record of working under incentive rate mechanisms, providing quality, safe service and predictable rates for our customers while also allowing us to achieve premium returns within the parameters set by the regulators. The Ontario government recently announced and I quote natural gas will continue to play a critical role in providing Ontarians with a reliable and cost-effective fuel supply for space heating, industrial growth and economic prosperity with developments in energy efficiency and low-carbon fuels such as RNG and low carbon hydrogen, the natural gas distribution system will help contribute to the provinces transition from higher carbon fuels in a cost-effective way end quote.

We agree with the Ontario government and believe renewables will also grow rapidly and be critical to meeting global emissions targets. But renewable growth cannot be sustained without being closely intertwined with the natural gas’ intermittency and peak failsafe for consumers. Speaking of renewables, let’s take a look at some of the developments in our renewable business. We’re making good progress on our French offshore wind projects under construction. Over 1 gigawatt of new generation is expected to be online by 2025. As comp, the first turbines have been installed and at Provence Grand Large, all floaters have been secured. We are tracking on time and budget with both projects expected to be fully in service by the first quarter of ’24.

Calvados continues to make good progress and is tracking on time and budget. In North America, we have more than 4.5 gigawatts of onshore projects in development. A portion of these projects will come online by 2025, with some expected to reach FID later this year. All projects have to pass our strict risk return parameters, so don’t expect us to make undisciplined investments just for the sake of growth. Our behind-the-meter strategy is continuing to gain traction. Our first Solar Self-Power project came online in 2021, and we now have 6 in service, 3 of which came online in 2023, with more than 30 megawatts of capacity. With technology improvements, rising renewable energy credits, prices and tax incentives, more of these developments are producing strong returns and help reduce our emissions footprint.

On that note, we published our 22nd annual sustainability report. So let’s move on to that next. The report highlights our long-standing focus on sustainable practices and our industry-leading performance across environmental, social and governance issues. We expanded our methane reporting included more detail on Scope 3 emissions, enhanced our climate lobbying reporting and outlined progress made on our indigenous reconciliation plan. We’re making good progress on the targets we laid out. To date, we have reduced our GHG emissions intensity by 27% compared to a 2030 target of 35% and have achieved 18% of our net zero emissions goal for 2050. In our workforce, diversity and inclusion remain a focus with 31% identifying as women and 25% is racial and ethnic groups.

We’re making good progress on these priorities and remain committed to such improvements. On governance, our Board is more diverse than ever. Our Chair Pamela Carter, and accomplished black women, who brings extensive experience in the sound business judgment. Across the company, we have integrated emission reductions considerations into our day-to-day operations, capital allocation processes and aligned executive compensation to performance against our ESG strategies. Our low-risk business model continues to deliver predictable results in all market cycles. So let’s walk through our First Choice value proposition. Enbridge has an industry-leading cash flow profile, which supports our resilient business model. Our cash flow is diversified across four large businesses and approximately 98% of our expected 2023 EBITDA is underpinned by regulated assets or long-term take-or-pay contracts.

About 51% of that is what we call take-or-pay plus, meaning the assets are underpinned by long-term agreements with inflation protection and cost sharing provisions, including the new mainline tolling settlement, which will now have a call it floor ROE, about 47% of our EBITDA is low risk and utility-like with limited variability. Earnings from these regulated assets have a prescribed rate of return on deemed equity sickness. So our high-quality cash flow profile has little to no commodity exposure and volume risk, while having a high degree of assets earning regulated returns with cost pass-throughs. This underpins our low-risk business model, which is very similar to a utility, allowing us to carry somewhat higher leverage than our pure midstream peers.

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 cash flow predictability supports our strong access to capital and allows us to maintain our strong investment-grade credit rating. Financial conservatism remains a key priority and is a hallmark of how we’ve delivered consistent returns for shareholders. We’ve actually delivered attractive total shareholder returns of approximately 12% per year for more than 20 years, driven by capital appreciation and consistent dividend growth. And as we just highlighted, our diversified low-risk pipeline utility model produces reliable cash flows to support these returns, maintain a strong balance sheet and extend our dividend growth track record.

Over the medium term, we expect to grow EBITDA by about 5% per year by incorporating conventional infrastructure investments as well as finding lower carbon opportunities throughout the business. Sustainably returning capital to shareholders is also a key part of our value proposition, and we expect that to continue in the future. So now let me turn things over to Pat to walk you through our quarterly financial results, our capital allocation priorities and our growth outlook.

Pat Murray: Thanks, Greg, and good morning, everyone. I’m excited to walk you through our second quarter results. Strong operational performance resulted in an 8% increase in EBITDA year-over-year. In liquids, the mainline performed well again. We hit a new record for Q2 throughput with export [ph] volumes averaging almost 3 million barrels per day, up over 200,000 from the same quarter in 2022. The Mainline also benefited from the recognition of a lower provision against the interim CTS IGT toll this quarter as compared to the same period last year after we came to agreement in principle on the Mainline tooling and knew the exact impact on the interim toll, we didn’t need to accrue as much of a provision in the second quarter as we had previously.

Finally, in Liquids, contributions from higher ownership in the Gray Oak and Cactus II pipeline increased U.S. Gulf Coast and Mid-Continent results. At GTM, our lower ownership interest in DCP Midstream as a result of the transaction with Phillips 66, impacted our results year-over-year. This was partially offset by the acquisition of the Tres Palacios storage facility and favorable recontracting on our U.S. gas transmission and storage assets. Our Utility business was down in the quarter, but this was primarily due to the timing of storage and transportation margin. As noted in Q1, this is reversing some favorability from earlier in the year and will continue into the back half of this year. Our renewable business benefited from Saint-Nazaire coming into service at the end of last year, but that was partially offset by slightly lower wind resources and lower European power pricing.

At Energy Services, a number of our transportation commitments expired during Q1 and market backwardation has improved compared to the same period in 2022. Below the line, higher interest rates on floating rate debt and timing of maintenance capital, as well as higher controlling interest distributions from our strategic new partnership with the Athabasca Indigenous Investment Group, partially offset the stronger operational performance of the business. Our results are driven by the diversity and scale of our assets and highlight the low-risk nature and predictability of our financial and operational performance. So with a great first half of the year, let’s talk about how we’re tracking to our guidance. I’m pleased to be reaffirming our 2023 financial guidance again this quarter.

We expect strong utilization and operating performance across all of our businesses to continue. However, as we expected, the lower Mainline tool coming in effective July 1 and higher financing costs due to increased interest rates will be minor headwinds, and we expect these to play out primarily in the third quarter. As we think about the rest of the year, let me remind everybody about the seasonality in our business. Q1 and Q4 are typically our strongest financial quarters due to higher gas flows during winter on both our gas transmission and distribution systems. As well, we experienced higher deliveries on our Liquid system outside of turnaround season. In terms of risk management, we’ve hedged almost all of our U.S. dollar DCF exposure at around 137, and our floating rate debt exposure is much less than 5% now.

This increases our confidence in our financial projections for the balance of the year. Now let’s look beyond this year to our medium-term outlook. We’re also happy to reaffirm our medium-term outlook, and there is no change to what we laid out at our Investor Day. The first bucket of growth will be a big focus of our company over the next little while. We recently settled on new tolling frameworks for BC Pipeline and Texas Eastern. We’re in the process of finalizing the main tolling agreement and the utility rebasing is expected to be in place for January 2024. Although these agreements are similar to their predecessors were incentivized through all of them to optimize under each agreement, which will help us to achieve our low capital growth rate.

In the second bucket, we’re advancing opportunities to build out our secured organic growth projects. With next decade, reaching FID on Rio Grande LNG, we added the Rio Bravo Pipeline to our secured backlog. On the open season front, we advanced our FSP in Texas each an open season and are still planning a T-North 1 by year-end. Finally, we continuously look at opportunities for both organic growth and opportunistic tuck-in M&A. We continue to execute the strategy put forward at Enbridge Day and will effectively allocate capital to deliver growth. So let’s talk about those capital allocation priorities. As I step into the CFO role, I want to reiterate that our capital allocation strategy is unchanged. Our number one priority is maintaining a strong flexible balance sheet.

Q2 debt-to-EBITDA was 4.5 times, and we expect to exit 2023 within the lower half of our target range, leaving us room to execute on our secured capital program. We continue to return capital to shareholders through a sustainable and growing dividend and opportunistic share repurchases. Our financial flexibility and predictable cash flow provides us with approximately $6 million a year of investment capacity, and we’ll allocate capital only to the best opportunities in front of us. So let’s turn to that secured growth program. Today, our secured growth program sits at $19 billion. It is diversified across our businesses and the regions that we operate and is expected to be deployed over about the next 5 years, which helps to mitigate against inflationary cost pressures.

New to our backlog this quarter is the addition of the Rio Bravo pipeline with construction expected to begin in 2025. Next decades FID on the first 3 liquefication trains of Rio Grande LNG was the trigger for us to continue construction planning on this project. When we announced this project, our original cost estimate of $1.2 billion was for a 2 train build. We’re currently refining our 3 train engineering estimate and expect to update our capital costs by year-end. We expect to place approximately $3 billion of capital into service for 2023 and already announced $1.1 billion of tuck-in M&A year-to-date, with the final one closing at being Aitken Creek later this year. Now I’ll turn it back to Greg to wrap up.

Greg Ebel: Thanks, Pat. And as we wrap up here for 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 positions us to withstand market volatility and deliver predictable results. Returning capital to shareholders remains a key focus through sustainable dividend growth and opportunistic share repurchases. We’re confident in our ability to achieve our growth outlook by optimizing the business, adding to our visible growth backlog and executing additional tuck-in M&A. Our premium growth profile, incorporating conventional infrastructure investments and lower carbon opportunities supports dividend growth, long-term shareholder returns and positions us as a first choice investment opportunity. Thank you. And now let’s open the lines for your questions.

Q&A Session

Operator: Thank you. We will now begin the question-and-answer session. [Operator Instructions] And we will take our first question from Jeremy Tonet with JPMorgan Chase. Your line is open.

Jeremy Tonet: Hi, good morning.

Greg Ebel: Morning, Jeremy.

Jeremy Tonet: Just wanted to track, I guess, results this year, it seems like a strong first half where there was about just almost $8.5 billion of EBITDA and want to square that versus the guide of 15.9 to 16.6. Do you see yourselves tracking the high end of the guidance or above? Or should we be thinking about items in the second half that would make the second half lower than the first half. Anything to think about there?

Greg Ebel: Yes. Maybe I’ll start there, Jeremy. Good question. Yes, it was a very strong first half of the year. I think as Pat laid out, we’ve got a few little headwinds for the last half of the year. So I think being right in the middle of that range is the right place for us. Remember, the fourth quarter is a big quarter for us. So whether it’s weather or volumes, those will impact where we finally land. So I don’t want to get ahead of the fourth quarter of mother nature, but feeling good about the quarter where we are for the year, these projects coming in. So I think sticky in the middle of that range is probably the right place to be today. But again, let’s see how the fourth quarter goes, that can be a benefit sometimes.

Jeremy Tonet: Got it. That’s helpful there.

Operator: I apologize. Go ahead.

Jeremy Tonet: Just one more question, if I could. We’ve seen some big moves in the kind of the midstream landscape, strategic action by competitors, consolidation among others. Just wondering if you have any updated strategic views for Enbridge moving forward? Anything to call out there?

Greg Ebel: Well, Jeremy, I think we’re in a great spot. I think what you’re seeing out there is that breadth matters, size matters, the portfolio matters. I think increasingly, you’re starting to see that premier valuation should go to companies that can play all parts of the energy evolution. So we’ve got the Liquids business, we’ve got the gas transmission business and the distribution business and renewables and increasingly some new energy technology. Those are increasingly both vertically and horizontally connected, and we think that’s going to matter more and more. So you think about the renewable business, as we said, it doesn’t survive without a good strong gas business, of which, as you know, we serve 20%, 25% of the volumes.

The Liquids business increasingly connected not only on the export side, but things like ammonia and blue ammonia and CCS, that’s important to have that all together. The LNG export business, you need transmission on that front. And then on the distribution side of things, things like hydrogen and renewable natural gas, not only a benefit on the transmission side, but also for GDS. So I think there may be some companies – there are definitely some companies that do not have that type of portfolio breadth. But when you do, I think you’re in a sweet spot there. So I wouldn’t read too much into some people selling assets and such. I don’t think people have the same type of portfolio setup that we have. And I think the market’s coming to us from that valuation perspective.

Jeremy Tonet: Got it. So just to be clear, no split in the outlook going forward here?

Greg Ebel: Look, we’re always looking at that, but I do not see – again, I’d go back. That doesn’t seem – that seems to be a dissynergy for a company like Enbridge, which actually, again, has that complementary aspects of multiple parts of the business. So again, the Liquids business has elements that are actually connected to things like ammonia and CCS and the gas business. And the distribution business has connections to new energy technologies. So I do not see that. Of course, we’re always looking at making sure that we’ve got things structured to get premium valuation. But I think the market has recognized we deserve a premium valuation because of that vertical and horizontal integration that goes on today. That change, we’d look at it. But I just don’t see that today for a company of our breadth size and diversity and frankly, low-risk diversification as well.

Jeremy Tonet: Got it. Thank you very much.

Greg Ebel: Thanks.

Operator: And we will take our next question from Robert Catellier from CIBC Capital Markets. Your line is open,

Robert Catellier: Hi, good morning and thanks for the presentation. I just wanted to focus on the Liquid side a little bit here and specifically how Ingleside terminal is being leveraged to effectively the pull-through volumes from the rest of the system. And maybe you could just touch on the competitive situation for the export terminals, please?

Greg Ebel: Well, Colin is right here, so I’m just going to turn it over to Colin.

Colin Gruending: Sure. Thanks, Greg. Thanks, Robert. Yes, I think exactly right. So the Ingleside terminal is our kind of our flagship anchor asset for our Permian strategy meant to be differentiated, highly competitive from a number of reasons. As you know, dredge depths distance to blue water loading rate, we’re now dredged and we can load VLCC up to 1.6 million barrels per day. So that all just drops nickels and dimes off the marginal barrel and competitive netback for our customers. And then so we’ve got capacity, as we’ve talked about to expand the storage and the docs there. That’s all in our plan. And then the vertical integration, which Greg just kind of spoke about more broadly, we’ve got that going on in the Permian as well with Gray Oak now.

We’ve taken operation of a gap [ph] We’ve expanded a little bit. We’ve got – we’re going to have offerings in the market here in Q3 at both Ingleside and Gray Oak for expansions, watch for those and got our eye out for further tuck-ins along the value chain. So I think during the quarter, Ingleside exported a quarter of U.S. oil and record volumes. So it’s all trending favorably, Robert.

Robert Catellier: So Colin, just to clarify, I’m curious to the extent to which the possible offerings in the market for Ingleside in the second half are contingent on a successful one again South open season?

Colin Gruending: No, they’re disconnected.

Robert Catellier: Okay. Thank you…

Greg Ebel: Ingleside largely being driven by the Permian right and fine again largely by the Canadian crude. So…

Colin Gruending: You might be thinking about EHA, Robert, which we’re we’ve sanctioned, we’re going to build that at the terminus of Seaway, which we interact with planning and sales in Seaway.

Robert Catellier: All right. Thank you.

Operator: And we will take our next question from Linda Ezergailis with TD Securities. Your line is open.

Linda Ezergailis: Thank you. Just looking forward to the second half of the year and thinking about your investment capacity, you’ve announced about $1.1 billion of M&A and then now the Rio Bravo pipeline, do you expect to announce approximately $6 billion of new secured capital opportunities this year? And if not, might that inform what level of opportunistic share buybacks? Or do you expect those capital commitments to be a little bit lumpy year-over-year, some years more over $6 billion versus less?

Greg Ebel: Yes. I think the way to think about that, Linda and Pat can chime in here, too, is you’re right, we got the $6 billion of capacity on the balance sheet each year. Half of that is going to already the secured projects. So think about that in future years, that go to Rio. That doesn’t go against the $3 billion of capacity we have to do things like opportunistic share buybacks, which we did a little bit of that in the second quarter or acquisitions like the $1 billion we’ve done year-to-date. But inevitably, the first $3 billion unsecured projects is going to be a little bit lumpy, but I’d separated out more in that sense. So think about $6 billion, 3 for secured projects and 3 for other opportunistic pieces. Pat, I don’t know if you’d add anything to that.

Pat Murray: Yes. I think the only thing I’d add to that is that in that kind of second bucket of $3 billion, those will be a little bit lumpy, opportunistic as we go through them, and we’re not going to do anything just to fill that bucket. We’re going to make sure we pick the best project. You think of Rio Bravo, which we just added, that spend will be a couple of years out primarily. So it’s not really impacting our capacity in the current year. And so we’ll continue to look at various capital allocation purposes to see where we can spend some of that in some of those dollars. But it can be a little lumpy, Linda. Just what are the opportunities out there and what’s the timing of spend as we go forward.

Linda Ezergailis: Okay. Thank you. Just as a follow-up quickly. What are you seeing in terms of opportunistic tuck-in acquisitions in terms of volume, quality, pricing nature, where they are in the value chain and geography? Any observations in terms of how things are trending on that front would be appreciated.

Greg Ebel: Yes. Well, fortunately, given our size and Brad and his to talked about this balanced portfolio, we get to see everything. I mean, people come to us and show us assets all the time, which allows us to be really picky and make sure that anything we do actually fits right down that fairway of low risk pipeline, utility-like cash flows and solid returns and accretion. So we’re seeing everything. Now you saw in the first half of the year picking up pieces from joint venture partnerships, things like Gray Oak and Cactus II, we picked up pieces. And then the 2 storage assets are very complementary as well. Some of those are being sold by corporate. Some of them are being sold by PEs that maybe need a monetization or liquidity events.

And we’ve got that, as you mentioned, that $3 billion of capacity to be able to execute on those. So I’d say they’re right across the board. I don’t think there’s any part of the energy value chain where people aren’t trying to think through how to trade out assets. Sometimes they need to do that. That’s opportunistic for us as well from a pricing perspective. And then, of course, as long as it fits into that value proposition that we have, low risk utility pipeline side, we feel we’ve got the ability to go out next Q.

Linda Ezergailis: Thank you.

Operator: We will take our next question from Robert Kwan with RBC Capital Markets. Your line is open.

Robert Kwan: Good morning. So just if I can start with capital allocation. So you pushed back previously on the need for and desire for large sale deals. But just on the tuck-in M&A, and you have executed on that this year. Do you see the tuck-in acquisitions solely being linked to that $3 billion of discretionary annual capital allocation? Or could you see that those tuck-ins in aggregate being at a level that would require external equity?

Greg Ebel: Yes. Well, I guess I’d say I don’t think that’s been our focus to date. Look, we’ve got that $6 billion in investment capital a year and some of which can be used for acquisition. And that gives us a lot of flexibility to do the transactions that we’ve seen to date that meet that low-risk accretive pipeline utility-like deals. I don’t see us doing big corporate-to-corporate deals, but — and I guess we’re always open to things. But that’s — I think the tuck-in route to date has been the right one for us.

Robert Kwan: Got it. If I can turn to guidance and you’re highlighting that the lower Mainline toll is a headwind. But then you also noted in the results that you took a lower provision against the Mainline IJT in the second quarter. Can you just talk about the dynamic there and if the lower toll was a headwind for Q3, why is it not for Q4 and for that matter into 2024?

Pat Murray: So I think maybe I can take that, Robert. It’s Pat. So on the provision side of things, if you think about the timing of when the agreement principle kind of came to be in that April end of April time frame, we’ve got more clarity on kind of what the interim toll amount would be. And as a result of that, we were pretty well provided by the end of Q1. So I didn’t have to book as big a provision for Q2 here before the toll goes down a little bit in — on July 1. So that was really just getting us kind of trued up to what that difference would be in relation to the interim tool. And then as you talk about going forward, if you step back to when we announced the actual transaction, it was well within where we were looking for this year.

We kind of laid out a waterfall to help understand how we get to the level we have. It will be a little bit lumpy this year like you’re noting in that the totals were down a bit for Q3, Q4. Really, probably all we’re noting in Q3 specifically that Q3 tends to be a little bit of a lower volume period as well. But Q4 will usually pop back up. And then the agreement was right in line with what our views were of ’24 and ’25 when we guided back in, I guess, it was early December last year.

Robert Kwan: Okay. That’s great. Maybe I’ll take some of that offline. Thank you.

Operator: And we will take our next question from Theresa Chen with Barclays. Your line is open.

Theresa Chen: Good morning. Wanted to touch on your Tres Palacios expansion. And just generally, your long-term outlook for natural gas storage, especially in the U.S. Gulf Coast, how much can you other expand by how do you see yourself positioning in this interval in a portion of the value chain as we go forward? And do you see more tuck-in opportunities here?

Greg Ebel: Yes. We’re big storage fans for sure. So good question. And Cynthia, do you want to take that?

Cynthia Hansen: Sure. Thanks, Theresa. We, of course, are very excited about the opportunities. We have the ability currently to expand Tres Palacios by 6.5 Bcf. There is an expansion, one of the cabins that’s coming into service this fall, so that positions us well. As you mentioned, in that Southern Texas area, these assets, this is the southernmost salt [ph] storage dome in that area. The other thing we really liked about the Tres Palacios assets was the header system that ties in and the interconnectivity that, that gives us into that market. When it comes to that ability to continue to expand, we are looking at that. We’re also looking at how we can optimize with the rest of our assets and how we’ll operate the Tres Palacios asset.

So how can we do wheeling, how do we do parking [ph] loans, that kind of thing as we look to optimize the operations there. And we’ll continue to look at whether we can do some small upgrades to the existing infrastructure there to increase our storage capacity as well. So the other thing that, as we’ve noted before, we’ve seen is that the pricing has started to be a little bit more positive in storage. So we’re continuing to monitor that. And we think in the long term, there will be incremental opportunities to invest in incremental storage in Texas, in particular.

Greg Ebel: Yes. I think that big ambient temperature swing that the LNG players have to manage is really starting to show the value of storage there, too. So if you talk to the Chenieres [ph] and folks like that, I think they verify just the thesis that Cynthia just laid out. So good time to have bought those assets in, good to have the flexibility to do that. And I think it’s going to match up really nice with a lot of Cynthia’s [ph] assets. The other thing, I think, when you think about storage assets, as we move to forward with carbon caption and sequestration, that’s going to put premium valuation on storage as well, too. So like the assets that we have in the several hundred Bcf of storage that we’ve got right across North America.

Theresa Chen: Thank you. And then turning to the Liquid side. Can you talk about the timeframe for the Gray Oak expansions that you’re running open season in the fall? And I believe it’s primarily pump work. How quickly can the 200,000 barrels per day come online? And are you still contemplating a further extension from Sweden to the Houston area?

Colin Gruending: Yes, Theresa, Colin here. Yes. So I think you’re right. We’ve been sounding the market on quantum and destination. Recall Gray Oak is a bit unique. It’s not a [indiscernible] and the Houston Sweden area. So it’s kind of unique that way. We plan to launch that officially here in Q3. So it’s still on track. And up to, I think, 200,000 barrel a day expansion. And we’re looking at in-service dates in early 2025.

Theresa Chen: Thank you.

Operator: We will take our next question from Patrick Kenny with National Bank Financial. Your line is open.

Patrick Kenny: Yes, good morning. Wondering if you could provide any comments on Alberta’s announcement here to pump the brakes on improving renewable power projects and whether or not you’re seeing a growing trend of political and regulatory pushback across some of the other jurisdictions in which you operate. And if this heightened focus on affordability and grid of reliability might cause any slowdown in reaching FID on your renewable backlog or on the flip side, increase your desire to own natural gas-fired generation assets going forward?

Greg Ebel: Yes, definitely. And Matthew is on the phone, so I’ll get them to respond, but I think you’ve kind of just made a thesis yourself or why you want to have all aspects of this energy value chain. And also, why governments are really giving a thoughtful approach about how are they going to be able to manage this transition. So I believe Matthew, you’re right here. So why don’t you take that one?

Matthew Akman: Pat, thanks for the question. Yes, we don’t have anything in Alberta under lake development that gets held back by this. And so it doesn’t affect the FIDs. Those would be in the U.S. where we have a very robust late development program and the next up there would be in the ERCOT area. But bigger picture, I think, for the renewable business, you’re right. I think some of the reclamation and time lines issues aren’t just in Alberta, I mean, other places. So I think there’s going to be a real advantage for larger companies with scale and financial strength, which is what we’ve got — and so I think that positions us well. I think reliability is another theme. And yes, I mean, we’re going to need more battery storage, but also gas-fired power.

We don’t have any intentions to invest in that, but you can’t take gas-fired power out of the equation. You need it for backup and reliability for a long time. And I think just more generally, this just shows the pace of transition is not unconstrained. So that’s why we love our renewable business. But obviously, like Greg said, it’s great to be diversified across conventional, which has a very long life and the renewable stuff.

Greg Ebel: The only other thing I’d add is in Colins business is one of the largest power users and just about any jurisdiction we operate in. So this focus on affordability is really important to us and makes our liquids lines increasingly competitive. And even where there’s elements, which things like the mainline, there’s elements of pass-through on power, we want to make sure that whatever that power is, however, it comes that it’s cost competitive across jurisdiction in North America. So I think this balanced approach of governments and starting to focus on affordability, security and reliability makes sense. And again, I just want to reiterate, that’s exactly how we’ve structured the company for a long time to be able to react to those pieces and create value right across that value chain.

Colin Gruending: Pat, it’s Colin. A couple of examples. So Liquids Pipelines interact with 75 utilities across a bunch of provinces and states and we see this tension everywhere, right, affordability competitiveness, but we also want to green the grid. So yes, we get a front row seat to that everywhere.

Patrick Kenny: Okay. That’s great. Thanks for all those comments. And then just a quick one for Pat here just on the rising financing costs. Curious how you’re thinking about your rate reset pref shares within your capital stack, if there might be any refinancing opportunities coming up or perhaps other levers you might be able to pull to help mitigate the headwinds on distributable cash flow.

Pat Murray: Yes. I mean it’s a fair question with rates continuing to go up. It’s something we look at, the optimization of our overall capital structure, our overall interest costs. We have a pretty disciplined hedging program that we use to make sure that we’re risk managing what the out years of our plan looks like. We’ll continue to do that. We’ll look for opportunistic times to hedge like we saw a bit in Q1 when there was a bit of an upset in the banking market in the U.S. It was a great time to put some hedges on it but probably at a lower rate than we had expected. But we’ll look at the whole paths to see what the most opportunistic and most efficient way of managing our capital is and the press will play into that or the hybrids.

Greg Ebel: And Pat, just to remind you that right across most of our businesses, definitely in things like the gas pipelines in West Coast, gas transmission or gas distribution, Collins business, many places we have interest pass-throughs, right? So yes, there’s always a little bit on that front, but we’ve got a lot of coverage. There may be a little timing lag. But ultimately, it goes into that regulated rate of return that’s so prominent across the portfolio.

Patrick Kenny: Thanks, everybody. I’ll leave it there.

Operator: We will take our next question from Rob Hope with Scotiabank. Your line is open.

Rob Hope: Good morning, everyone. Just one for me. In the prepared remarks, you mentioned expansion of Texas starting through Appalachia to meet demand in all regions. As you take a look at the increasing LNG demand off the Gulf Coast as well as increasingly congested pipelines, how would you view your pipeline’s ability to continue to draw volumes from kind of the Northeast all the way down to the Gulf Coast? And kind of what expansions are you looking for?

Cynthia Hansen: Yes. Thanks for the question, Rob. Our assets, they’re in a great location, and we are supporting both the U.S. Northeast as well as the Gulf Coast. We continue to look at how we can optimize that infrastructure. Greg pointed out the Appalachiamarket two that we’re currently doing to optimize in Pennsylvania. We had an open season that we’re still working with the customers on Appalachia market 3. So that whole idea of continuing to look at these brownfield opportunities where you can optimize the system with a little bit of looking, some changing of the compression, that kind of opportunity. And we’re always working with our customers when it comes to how do we make sure the infrastructure that we have is optimized.

And there will be opportunities to look at how we can put those incremental volumes in. At some point, we will see both with the increased demand for LNG export, a need for new pipe infrastructure. Fortunately, in that area in Louisiana and Texas, there will be opportunities that you can type that infrastructure in. In the U.S. Northeast, we’ll continue to look at how we can optimize the overall capacity when it comes to providing that flexibility, particularly through PC. So there are opportunities for the winter storage with small projects there. So a lot of work to look at how we can optimize our infrastructure and add more capacity.

Rob Hope: Thank you.

Operator: We will take our next question from Praneeth Satish with Wells Fargo. Your line is open.

Praneeth Satish: Thanks, good morning. If I look at the CapEx backlog, I mean, clearly, the focus here is on natural gas and renewables CapEx. There’s kind of less spending earmarked for mainline. So I guess just how do you think about conceptually the desire to maintain rate base at mainline versus letting it decline and spending that capital elsewhere. I know you have the ROE collar that protects you, but just curious how you think about that.

Colin Gruending: Yes, Praneeth, it’s Colin. Yes. So I think there’s ongoing rate base investments. We probably haven’t built a all lot in this chart per se. But I mean, a good example would be the Line 5 reroutes that we talked about earlier in Wisconsin and Michigan also be included in rate base. And I think we disclosed that as part of the mainline tolling agreement. So that’s a pretty good example. So there’ll be continued investment along the way, maintenance capital and growth capital in that regard. And I think there’s also opportunity to expand the main line here again. We withdrew those from the mainline negotiation, but we’ll bring those back to the 4 here once we’ve approved the – or the regulators approve the mainline deal.

I think whether you think about it as an insurance grass or just actual egress [ph] Other systems could go down, and we’ve seen what happens to netbacks in the base and when that happens. So that’s still very much a strategy we have, and our customers are interested in that as well.

Greg Ebel: We’re still strong believers that through the end of the decade, you’re going to see 500,000 barrels a day, call it, in growth out of Western Canada. Our pipeline has points out, travels by 75% of all the refineries, we can get people to the Gulf Coast. I think there’s going to be plenty of opportunity. And obviously, we’re going to do those in the most capital-efficient way that serves the customer. But I have no doubt we’re going to continue to see that growth, particularly when the alternatives, they don’t have as competitive a toll structure; and b, have a lot more difficulty in adding incremental volumes versus what we can do with that system.

Praneeth Satish: That’s helpful. And then as my follow-up, when you look at your Permian strategy, you mentioned a couple of times the potential for tuck-ins. I guess what gaps do you see in your strategy at this point where you feel like you need to do additional M&A? And what would acquiring an asset do for you versus contracting for space on third-party lines and saving on that CapEx? I guess maybe if you could just talk through the benefits of acquiring versus leasing capacity at this point?

Greg Ebel: Yes. I think both can work. I think we generally like operatorship, I’ll tell you Obviously, you see that in things like picking up pieces of Gray Oak and taking on the operatorship. I think that allows us to optimize across the value chain, both for our investors, but even equally important, if not more important for our customers. So I think we prefer to do that. You could see — I mean, generally, we like large diameter pipe. And I guess you could get back — we don’t have as much gathering, but we’re pretty careful on that type of investment on the Permian side. We could also look at can you do more out of Ingleside — could you do some on the NGL side or other products from an export perspective? Again, making sure we don’t get caught up in any commodity risk and we can structure this pipeline. But — and that would be my initial take, Colin?

Colin Gruending: Yes, you got it. And the lease option is very much on the table. We could lease our way into the Houston market. We’re currently still thinking about connecting Gray over to EHA. But yes, I think you’re right. We’re not held bent to spend capital. We’re interested in returns on capital. So there are any gaps per se, but we’re going to optimize the system and grow and protect the franchise…

Operator: We will take our next question from Ben Pham with BMO. Your line is open.

Ben Pham: Good morning. Just start off maybe start off on funding and maybe you can potentially rank order the sources of topped, if you do hypothetically exceed that $6 billion investment opportunity. Speaker 2

Greg Ebel: Sure. I’ll start. First, obviously, organic growth along our system is probably our best return. If we can add ways to increase the volume that they’re putting a ton of capital to work right across our entire system, whether it’s on the liquid side, the gas transmission side or even on distribution or renewables repower cess. And I would say that’s the first call because that’s got the greatest return. Then if you — then our major projects that you’ve got the large secure projects, now they take a longer time to go from investment to cash flow, so we want to balance those. And then you look at the type of M&A we’ve done to date, stuff that is complementary, additive and that we can do in a value-enhancing price and mix it into our system in the way that we’ve been able to do with a lot of assets.

And I would point to everything going back to Ingleside to the Permian pipelines to trace and Aitken Creek. We’ve got a long history of being able to do that. And then if we can’t find those or the values are compelling. We look at things like buying back stock. So that’s kind of the kind of hierarchy and way I would look at it. And it all starts with where do we think we can get the biggest bang for our buck in terms of return on capital and growing the business and extending out and enhancing that low-risk utility-like pipeline like asset base. So — that’s the way we look at it. That’s the way everything gets filtered through, and I think it’s been pretty successful in attracting that premium valuation. Pat, I don’t know if you want to add more.

Pat Murray: Well, I think from a funding perspective, one thing I think, Ben, we can think about it is that it could be a little lumpy, a little bit higher in 1 year, a little lower in another year. We’re right at the bottom of our debt-to-EBITDA range, which gives us the capacity to do some things. So that mix that Greg is talking about helps the funding as well because we’ve got some that will be drag out over a few years, maybe back end of our plan. We can do some things earlier in the year through these kind of tuck-in acquisitions. So we feel really good about the funding plan we’ve got and the optionality, and we’ll be selective in what we do to make sure that we’re doing the highest return, most strategic projects to us as an organization as we move forward.

Ben Pham: And can you comment the follow-up? Is capital recycling? I know it’s not been a huge, huge focus for you guys. I mean the defense opportunistic ones. Is that an effective way to fund projects. And if there is a year where you may be exceeding that $6 billion?

Greg Ebel: Yes. We’ve got a list we’re always looking at, Ben. And I think since ’18, we’ve done $10 billion of that, for things like ROCCAT [ph] not only provide a funding element, but perhaps, first and foremost, help us to make sure we’re that first choice partner for various stakeholders. And in that regard, things like ROCCAT for indigenous communities. So that’s definitely always something on the list. And if someone else is going to value an asset at a higher valuation that we look at, we think nothing about pulling that trigger. That’s the benefit of being a very large wide breadth, wide portfolio entity, you’ve got multiple levers to pull on, and you’re not forced to pun any one. And so that’s why we’re focused on not only growing the earnings of the company and the distributable cash flow, keeping the balance sheet in that 4.5% to 5% range.

And as Pat says, we’re at the low end and also making sure that when we need to, we can pull the trigger on divestitures.

Operator: We will take our final question from Brian Reynolds with UBS. Your line is open.

Brian Reynolds: One. Maybe just a quick follow-up on some of the peer strategic announcements. There’s a big focus on costs to help remain more competitive on tolling and to bring some value to the bottom line. So curious if you could just talk about how Enbridge is looking at its broader cost base to remain competitive and perhaps the mainline pooling agreement was done in a way to remain competitive with pure pipes.

Greg Ebel: Yes, that’s definitely a constant focus here. Whether it’s in the distribution business, even though that cost structure ends up flowing through to rate payers, we think there is — you cannot go wrong by being the lowest cost provider, and we sure or arrogant to think that we’re that on every single day, but definitely something that we’re looking at right across the business. And I think we’re actually things like the mainline tool actually incentive to make sure that we do that so that we are in a most competitive position from a cost and service offering perspective, GTM as well. And as we get these assets and we tuck them in and integrate them, they may be coming from a PE or a smaller player that has less ability to get those synergistic benefits.

It’s not a huge element. But when you think of our 4% or 5% growth focus, we often put that chart out that shows the first 1% of that growth comes from optimizing our costs and volumes and rate structures and regulatory side of things. So it’s a big element for us, and we constantly need to look at it and make sure that we’re ready for the next 75 years to be quite honest. Next year is the company’s 75th anniversary of Enbridge. And so making sure that we’re even better positioned for the next 75 is very much a focus of the company right now.

Brian Reynolds: Greg, maybe I just offer a double click on a couple of examples within the cost P&L. Enbridge has a mature supply chain function. We’ve had one for many years across all our businesses. I think that’s been helpful on quality and price. Power costs, right, get our power use down through optimizing flows, modernizing pumps through some rate base growth working with – we talked about earlier, electric utilities to find that right tension around affordability, reliability and grid in the grid. We’ve got a mature – major projects organization, right, that allows us, again, to optimize quality and price of our capital program. So just a couple of examples there, Brian, on the details around maintaining and improving our cost structure across all 4 businesses.

Greg Ebel: I think it’s important not just to focus — we focus on cost a lot, but also the revenue side, which is helpful not only for our shareholder and bottom line with also our customers to optimize the amount of volume Colin can get to the liquids line, the availability of the gas system, especially at peak periods and Cynthia’s business, the availability of our wind assets to make sure that they’re up and running on the wind and solar is blowing. So we focus on both the cost and the revenue optimization side as an enterprise on a daily basis.

Brian Reynolds: Great. Appreciate all that color. And then as my follow-up, just yesterday evening, we saw updated commentary around TMX infill in August. So just kind of curious if you could just update us with your view of whether this is included in your current guidance or expectations. And then just an updated view on time line and when you expect volumes to migrate from rail back onto your system?

Greg Ebel: Yes. That’s all built into our forecasts. We’ve been respecting TMX’s public disclosures all the way along. If it is delayed, that’s probably a little upside to our plan in ’23, maybe ’24.

Operator: And ladies and gentlemen, this concludes the question-and-answer session. I will now turn the call over to Rebecca Morley for final remarks.

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

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