Enbridge [ENB] Conference call transcript for 2022 q1
2022-05-06 15:24:09
Fiscal: 2022 q1
Operator: Welcome to the Enbridge Inc. First Quarter 2022 Financial Results Conference Call. My name is Justin, and I will be your operator for today's call. Please note that this conference is being recorded. I will now turn the call over to Jonathan Morgan, Senior Vice President, Capital Markets. Jonathan, you may begin.
Jonathan Morgan: Thank you. Good morning and welcome to the Enbridge Inc. first quarter 2022 earnings call. Joining me this morning are Al Monaco, President and Chief Executive Officer; Vern Yu, Executive Vice President and Chief Financial Officer; Colin Gruending, Executive Vice President, Liquids Pipelines; Cynthia Hansen, Executive Vice President, Gas Transmission and Midstream; Michele Harradence, Senior Vice President and President Gas Distribution Storage; and Matthew Akman, Senior Vice President, Strategy, Power and New Energy Technologies. As per usual, this call will be webcast and I encourage those listening on the phone to follow along on the supporting slides. We will try to keep the call to roughly one hour; and in order to answer as many questions as possible, we’ll be limiting the questions to one plus a single follow-up as necessary. We’ll be prioritizing questions from the investment community. So, if you are a member of the media, please direct your inquiries to our communications team, who will be happy to respond. As always, our Investor Relations team will be available following the call for any follow-up questions. And on to slide 2 where I’ll remind you that we will be referring to forward-looking information on today’s presentation and Q&A. By its nature, this information contains forecasts, 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 as summarized below. With that, I’ll turn it over to Al Monaco.
Al Monaco: Good morning, everyone. Well, to start, what you see here is the first of 80 turbines being installed at our 480-megawatt Saint Nazaire wind project off the West Coast, France. Just to give you a sense of the magnitude of this infrastructure, the towers are 170 meters at height, and each blade is about the same as the wingspan of an Airbus 380. So, pretty exciting time in our Renewables business, and more on that later. First of all, recent events are very troubling, and we’re all very concerned for the people in Ukraine. Many of our staffs have connections to the region, and we’re supporting them. What’s happening is also we’re revealing a lot about global energy markets. So, I’ll start off with how we’re thinking about that followed by our business update, and Vern will cover our financial results and outlook. Before that, this slide captures our Q1 highlights. It’s been a good start to the year. All four businesses performed well, operating at or near capacity. That translated into strong Q1 numbers, and we’re on track to achieve ‘22 guidance. The balance sheet’s in good shape. And both, S&P and Fitch reaffirmed our BBB high ratings. We’ve got $10 billion of projects in execution with $4 billion slated for service this year. So far in ‘22, we’ve added another $1 billion to our project backlog that will support post ‘24 growth. And we’ll update you on two carbon capture opportunities we’re very excited about. More broadly, we’re seeing a pickup in customer infrastructure, especially LNG export. Recall, there’s $5 billion to $6 billion a year of conventional and low carbon opportunity enterprise-wide in the hopper. Those will go through our capital allocation filter, which Vern will also cover later on. So, on the energy markets. Coming into the year, we saw growing demand and underinvestment in supply move energy prices higher. The Russia-Ukraine war has worsened the demand-supply gap, obviously, but it’s also put energy back in the spotlight. Energy markets are an inflection point and we’re in an energy crisis. There are three things that come out of this. Any way you look at it, global energy supply will need to increase to address national security risks, affordability, and reliability. That means we’ll now need an energy supply buffer and greater diversity of that supply to manage those risks. Europe’s heavy reliance on Russia is driving this, of course, but the impacts are broader and global, regardless of when this war ends. Second is the energy transition. We’ll need to accelerate low-carbon investments as well to meet demand, achieve emissions goals, and as part of the security buffer. To make that happen, we’ll need to pick up the pace on proven ways to grow low-carbon fields, like RNG, hydrogen and especially carbon capture. And that’ll mean leveraging existing transportation and storage infrastructure more quickly, like ours. It also means much more investment in natural gas to provide reliable, lower carbon base-load power and to enable renewables. Third, North America will play a much larger role in the global energy market, and here’s what. The North American energy advantage that we’ve been talking about is even more evident today, massive low-cost reserves and the technology to produce them with the lowest carbon intensity. And of the 10 largest global producers, Canada and the U.S. are number one and two on sustainability. You can see that with the ESG scores on this chart. North America will be the supplier of choice. You saw that already with the U.S., EU announcement to work together and Asian markets are also looking to secure long-term supply. The biggest opportunity in our view is natural gas exports with the potential for over 30 Bcf a day. That’s more than triple last year. And, of course, crude exports are set to grow by 50%. All of this is very positive for infrastructure pointed at tidewater. Remember as well that the North American grid is integrated. So, growing global demand and export is upside to Canada and the U.S. What you see here is underpinned by strong energy demand. We’re going to need more supply of both conventional and low-carbon energy. And now, that’ll be needed faster. 80% of world demand comes from hard to abate industrial uses and heavy transport, and of course pet-chem demand is grow. It’s also clear today that natural gas will be essential to meeting demand. Even before the crisis, Europe amended its taxonomy for clean energy to include natural gas. On low-carbon, $25 trillion will need to be invested with renewables, the largest component along with RNG, hydrogen, and again, carbon capture. We are headed in the right direction on the tax credits in the Canadian government budget, incentivized carbon capture, and there are U.S. proposals to expand 45Q. So, what does all this mean for our strategy? This slide recaps, the two-pronged approach we outlined for you at Enbridge Day. Our strategy is to invest in both conventional and low-carbon energy, and that makes even more sense today. On the conventional side, we’ll focus on optimizing throughput and modernizing our systems. On low-carbon, we’ll continue to align with the pace of transition and through ‘25, we’ll see over $4 billion of low-carbon opportunities. Finally, any new investment in conventional or low-carbon will need to meet our investment criteria. So, that will change. When you step back from all of this, we believe the two-pronged strategy approach makes even more sense today where energy security is back in the spotlight and where demands are conventional and low-carbon energy supplies will continue to rise. Now, to the business update and gas transmission. Very strong volumes with Texas Eastern hitting 16 of its top 25 peak days ever. We’re on track to put US$1.2 billion into service this year, that’s on top of the US$2.4 billion last year. The lion’s share spending is on new compression or modernization more generally. And along with our solar self-power projects, we’re lowering emissions. For example, our current modernization program will take out 182,000 tons of CO2 per year. We’re also excited about more organic growth. We’ve got good optionality to support growing domestic demand. And it’s pretty clear more capacity in the U.S. Northeast is needed to manage disruptions and peak demand. We all know what’s happening with global gas prices, but it’s not pretty for U.S. Northeast consumers either with gas prices at roughly 5x Henry Hub. This situation screams for more infrastructure, especially given increased supply variability from offshore wind that’s coming and more displacement of coal, of course. We put phase one of our Appalachia to Market project into service last year and Phase 2 is in pre-construction. Building greenfield is tough sledding, of course, these days, but these expansions are executable and cost effective, and there’s more we can do. LNG exports is a big opportunity with momentum building across the U.S. Gulf and now more so in Western Canada. Our Texas Eastern System feeds LNG along the Gulf Coast. We supply four plants today with about 2 Bcf a day. We’ve locked up capacity agreements with three more LNG projects that could add up to 7 Bcf a day and over $2 billion of new investment. Plaquemines LNG is now fully contracted and likely going ahead, which will drive $400 million on our Venice Extension project, not in the secured category yet, but we expect it to be shortly. Texas LNG and Rio Grande LNG are also progressing at fast pace. In fact, earlier this week, we saw NextDecade granted a 15-year SPA with ENGIE to support Rio Grande, seeing good momentum then here with both projects potentially reaching FID later this year. And by the way, on Rio Grande, that could drive FID on our Rio Bravo Pipeline. Western Canada is another big growth region for us. Shifting fundamentals are bringing Western Canada to the fore once again. You’ve got a world-class liquids-rich resource base that rivals the Marcellus and Haynesville, and operators have done every bit as good job, unlocking reserves. We could see production go 50% for LNG export here and regional demand growth. With growing demand in Europe for U.S. LNG, Western Canada can step into fill the gap. Proximity to Asian markets provides two to four weeks reduced shipping time and lower emissions. LNG breakevens in Canada at roughly $6 to $8 an MMbtu rivals the U.S. Gulf Coast and looks very favorable if you look at these Asian LNG prices, somewhere in the order of $30 an MMbtu in Q1. LNG Canada is in construction, of course, and Woodfibre is advancing early stage construction activity. We’re the main conduit out of the Montney and Deep Basin. So, all of this bodes well for upstream expansion on our B.C. Pipeline System. On that note, we launched a binding open season today for 400 million cubic feet on T-North. That’ll be a $1 billion expansion. Woodfibre LNG is contracted T-South with volumes currently flowing to the Pacific Northwest. Once they reach FID, we’ll need to create new capacity to replace volumes currently moving south. And that expansion would be approximately $2.5 billion. And depending on Woodfibre’s FID timing, we’re targeting a binding open season on T-South for later this year. And by the way, this could also require further upstream expansion on the T-North site. So, all of this is shaping up to be a big opportunity multi-years, which again goes to prove the value of pipe in the ground. Now, longer term, we also hold what could be two valuable pathways to the coast, the Pacific Trails and the Westcoast Connector corridors. We look at these as low-cost options on the future of LNG exports. Now, for either of these to move forward, we’ll need to see a clear path to execution with strong local community support and commercial underpinning. So, we have a way to go for those. Turning to liquids, Q1 Mainline throughput averaged 3 million barrels per day. Seasonally, we’ll see a more concentrated maintenance season in Q2 than we usually do, offset by stronger volumes in the back end of the year. But we remain on track for the full-year average utilization of 2.95 million barrels per day that we guided to in December. On Mainline tolling, healthy dialogue here ongoing with shippers. As you may recall, we shared our cost information, which was the precursor to negotiations. Our sense is that shippers would prefer another incentive tolling deal. Of course, that model worked very well for 27 years and aligned us with the shippers. But, as we’ve said, we’ll need to see an appropriate return, given the risks we manage under that model. Given it’s often challenging to come to consensus, we’re preparing a cost of service filing, which is a very good alternative for us. The schedule is the same as we showed you last time, where we expect to have a new tolling construct in place in 2023. Now, more broadly on liquids and how it fits within the shifting energy landscape I talked about earlier. Our scale and access to the best markets provides a ton of optionality and value for our customers. Our focus is adding highly executable capacity to the Midwest and the Gulf. Expansion options are right size and can be called on as production grows. In total, we’ve got roughly 400,000 barrels per day of egress opportunity on the Mainline and Express. We’re also developing a new Gulf Coast path by Pony Express that will link up the Seaway. Downstream, we’re continuing to develop the Houston terminal opportunities. And since we acquired Ingleside, we’ve seen increasing interest on several fronts, which is already proving out the upside. On conventional, we’re progressing a 2 million-barrel storage expansion. The terminal is already permitted for 5 actually, so we can move that one along once we get commitments. There’s also potential emerging for NGL exports, and stay tuned for more on that over the next while. As you saw today, we’re also now developing an integrated solution for blue hydrogen and ammonia production with Humble Oil. Now, the key to this concept is the integrated value chain through to exports. Texas Eastern runs just north of Ingleside, so it nicely is positioned to provide feedstock for hydrogen. And it looks like the geology in this region is suited for carbon caption storage. The hydrogen and ammonia production would be destined to meet local demand and the export market, which, of course, is booming. So, multiple upsides at Ingleside. Now to carbon capture in Alberta. In March, we were awarded the right to move forward on our Wabamun storage hub. So, we’re now validating the geology. Another positive was the federal government’s investment tax credit, 50% on capture and 37.5% on transportation and storage. This will go a long way to help make the numbers work. At 4 megatons per year captured with upside to that over time, this project will be one of the largest globally. We have given you a preliminary time line here, which could see the project in service as early as 2026. On our utility, population growth will drive new gas connections and expansion of transmission and storage. In fact, we just FIDed an expansion of our Panhandle system. It’s a $300 million investment to support growing greenhouse and power demand market in Ontario. So, the utility continues to generate about $1 billion to $1.5 billion of ratable annual investment, so it’s a great business and a real gem in our portfolio. Moving to renewables. We had a strong quarter, exceeding our resource target, so that’s good to see. What we have in execution will drive visible EBITDA growth through 2024. In France, we have four offshore projects in construction, including our first floating facility. As you saw earlier, we’re installing turbines at Saint Nazaire, and we’re in the fabrication phase at Fécamp and preconstruction at Calvados and Provence Grand Large. In North America, we have 10 self-power projects in progress, 7 of those should enter this year. And remember, we can build these quicker, given their inside the fence. We’re also moving along about 3 gigawatts of opportunity for the next phase of growth post 2024. Before I pass it over to Vern, as you heard, we’re seeing lots of positive fundamentals right now, and I’ve covered a variety of opportunities on both, the conventional and low-carbon front. So, he’s going to remind you about our framework and discipline around putting free cash flow to work and maximizing value. Over to you, Vern.
Vern Yu: Thank you, Al, and good morning, everyone. Our first quarter results were up significantly over 2021 on solid operational performance across all of our businesses. And we saw the benefit of $14 billion of capital that we put to work last year. In liquids, the Mainline moved about 3 million barrels per day in Q1, up 9% year-over-year, taking advantage of the additional capacity from Line 3. As a reminder, until we finalize the tolling for the Mainline, we’ll be including a provision in our results for that segment. Our Ingleside facility with its highly contracted cash flow is performing as expected, and it should remain strong through the balance of the year. Gas transmission utilization was solid, and the $1.4 billion of expansion added to our B.C. Pipeline System last year are driving growth in EBITDA. It’s business as usual at the utility with customer growth and colder weather making positive contributions in the first quarter. In the quarter, our Renewables business benefited from higher wind resources. Energy Services continued to experience narrow basis differentials and backwardation in the quarter, so below expectations here. Finally, lower capitalization of interest expense associated with Line 3 replacement has resulted in higher financing costs. So, it’s been a very solid start to the year. Let’s move over to our outlook. With the strong first quarter, we’re confident we’re on track to achieve full year guidance. Our systems are expected to continue to be highly utilized, including the Mainline, which is on track for 2.95 million barrels per day on average for the year. As always, this factors in a seasonal drop in throughput in the second and third quarters due to upstream and downstream maintenance activity. Our exposure to rising commodity prices remains limited, but we expect some modest upside on in Aux Sable and DCP. Gas Distribution and new Renewables on track to meet their annual guidance. We’re expecting Energy Services results in Q2 to be comparable to Q1, a slight headwind for the year. Energy Services outlook improves through 2023 and beyond as we have transportation and storage contracts expiring at the end of this year and early in 2023. We’re well protected against inflation. As a reminder, 80% of our revenue has some form of inflation protection through our various tolling mechanisms. Revenues are adjusted through regular rate filings or directly through embedded contractual inflation escalators. Our secured capital has been largely contracted for 2022, which provides good protection against capital cost increases, and we continue to manage our capital programs through active supply chain procurement and fixed price EPC contracts. Our financing costs are also well protected. Although 90% of our debt is fixed rate debt, minimizing our near-term exposure to rising interest rates, and we continue to optimize our financings. We’re generating a lot of cash flow and more investment capacity. So, let’s move on to our capital allocation framework. Our priorities remain unchanged, and we’re making good progress in all fronts. Our balance sheet is in great shape. And we’re on track for debt-to-EBITDA to be at the low end of our target range by the end of the year. S&P and Fitch just reaffirmed our BBB high stable credit ratings. We have increased our dividend 3% in 2022. That’s our 27th consecutive annual increase. And we initiated our share buyback program. That’s the model going forward, ratable dividend growth supplemented where it makes sense with share buybacks. Our cash flow and balance sheet leave us with about $5 billion to $6 billion of annual investment capacity. We expect between $3 billion to $4 billion will be deployed to low multiple organic expansions and system optimizations, along with utility rate base and modernization capital in gas transmission. That leaves about $2 billion per year available for more organic growth, asset acquisitions, share buybacks or debt repayment. While we review all of these options as we go through the year to ensure that we continue to maximize shareholder returns, all of these options will need to meet our low-risk business model, exceed risk-adjusted hurdle rates, have a strong strategic fit and align with our emission reduction goals. As always, we will continuously evaluate options to recycle capital where appropriate, to supplement the $5 billion to $6 billion of annual investment capacity. Our secured capital bucket continues to grow. So, let’s move to that. Today, our secured capital program sits at just over $10 billion. These projects will support our 5% to 7% DCF per share growth outlook over our over our three-year planning horizon. The $10 billion in secured capital include $1 billion that we announced so far in 2022. All of this secured capital is highly contracted or rate regulated which fits our low-risk commercial model. And as you just heard now, we’re advancing a number of exciting opportunities across all of our businesses. This will drive growth in 2024 for and beyond. Before I turn it back to Al, let me spend a minute on how we’re advancing our ESG priorities. As you know, ESG is foundational to our business. And our goal is to maintain and enhance our ESG leading position. We are betting our ESG priorities into our compensation and how we finance our business. Our strategic plans and annual budgets also incorporate strategies and the capital expenditures that are needed to meet our emissions goals. We believe this differentiates us in our sector and better aligns us to all of our stakeholders, customers, investors, communities and many more. We’re making good progress on the emission targets we set in late 2020, and we continue to challenge ourselves to do better. In addition to our 2020 emission targets, earlier this year, we made some additional commitments. These include working with organizations to support the development of emissions reduction guidelines for our sector, engaging with our suppliers to generate further Scope 3 emission reductions, and provide more reporting on different net-zero scenarios. Our sustainability report, which will be issued in June, will provide more information on how emission reduction targets are factored into all of our capital investment decisions. It will provide further detail on our biodiversity programs, provide more transparencies on our path to net-zero provide, and update on our approach to indigenous reconciliation. So, in a nutshell, we continue to raise the bar how we approach ESG. With that, I’m going to turn it back to Al.
Al Monaco: Thanks, Vern. A few takeaways to close. The energy crisis demonstrates once again that all sources of energy are needed to ensure affordable, reliable and secure energy, while achieving climate goals. North America is an ideal spot to be part of the solution, and Enbridge plays a key role. Our footprint, access to the best markets combined with being ahead of the curve on low-carbon, puts us in excellent position. Our strong balance sheet and differentiated approach to sustainability means we’re a natural midstream partner to upstream and the downstream customers. Finally, we’ll continue to take a disciplined approach and not compromise our low-risk business model. And taken together, we think this provides a great opportunity to grow the business and a solid value proposition for our investors. I’ll now turn it back over to the operator for Q&A.
Operator: Thank you. We will now begin the question-and-answer session. Robert Kwan from RBC Capital Markets is on the line with the question.
Robert Kwan: If I can ask first about the capital allocation priorities for that $2 billion and clearly in the first quarter and you showed that there’s -- it’s not either or, and there’s a number of things going on. But I’m just wondering with some of the changes in the environment, whether that’s the energy security opportunities, energy transition, as well as the higher share price. Can you just talk through some things have just moved around since you last spoke about this on the last quarterly call?
Al Monaco: Yes. It’s a good question to start, Robert. Well, first of all, as you heard through those remarks, I think there’s been definitely a positive shift in the fundamentals. We certainly will see more on the hopper for sure. I think it’s probably too early to tell whether that changes the broader outlook. And you heard the comments that Vern made around capital allocation discipline. I think the way we’re looking at it at this point is there’s really no change to how we’re looking at allocation. Discipline’s going to remain around the balance sheet, the dividend growth, and we’re going to continue to really make sure that we invest wisely. So, in a nutshell, I guess, a lot more opportunity, but we’ll continue to put a pretty strong filter on what we’re doing, and comparing opportunities that we have to invest capital with each other. And so, that’s really how we look at it, Robert, no major change right now, but certainly more opportunity ahead.
Robert Kwan: Got it. I just was wondering as part of that, is there maybe a bit more of a bias to reducing debt effectively just for bringing up balance sheet capacity for new projects and a specific project, like interested to get your comment on. It’s just, there’s a lot of stuff going on in B.C., as you highlighted, and especially that T-South expansion’s pretty big. So, if Woodfibre goes ahead and just with growth in the LBC, do you have a sense, or can you provide some color as to whether you think supplies diversity is one of their goals, and therefore how’s your project positioned versus say something along the Southern crossing line, or do you see the potential for both, of those projects to go ahead?
Al Monaco: Yes. I think our project is definitely in great position there, Robert, for a bunch of reasons, the main one has to do with imperativeness of the coal, and that stems in large part from the scale of the system. So, the other part is, if you recall, I mean, the Westcoast system is more or less a north-south header. And that gives us opportunity to expand to the Westcoast, but also to continue volumes down south. As to the capital allocation implications there and the size of those projects, if you think about it, we’re throwing off, as Vern said, a lot of free cash flow right now, and we will continue to do that over the next 2 to 3 years. So, the projects that we’re talking about are certainly not cash consuming, and let’s just say, in the next couple of years in any material way. So, in a way to get back to your original point, you’re sort of building up some excess capacity here while those projects will come to fruition in the next two, three, four years, capital spending-wise. As far as the balance sheet, Vern can expand on this, but essentially, we’re in very good shape right now. I think, we’ve been pretty clear about the 4.5 to 5. And as we said, we’ll be near the bottom of the range by the end of this year. And going back to what I just said, it’s possible that with free cash flow, the way it is that we could pop below that 4.5 in the next little while. As you point out, these larger projects come to fruition. So, in effect, we’ll be building up some capacity for that.
Operator: Jeremy Tonet from JP Morgan is on the line with the question.
Jeremy Tonet: Just want to start off with the new Ingleside hydrogen ammonia initiative, as you outlined there. Just wondering if you could peel in a bit more, I guess, on what some of the drivers are that could help you reach a positive FID. Who are the end customers that you’re looking to service here? What type of contractual support are you expecting here? What type of time line? Just more color on this would be helpful.
Al Monaco: Okay. Well, I’m going to start and then we’ll get Colin to provide some more details. This is a great example of how pipe and facilities that are in place gives you an advantage. And just broadly speaking in this region, Jeremy, we’ve got a big gas header along the Gulf. We’ve got Seaway. We’ve got Ingleside now and a bunch of projects in development. And as we went through, pretty strong fundamental support here, export-wise, obviously, gas is critical. CCUS is critical. So, this has really a bunch of attributes to it that go to that value chain I was talking about. And we’ve got essentially a brownfield industrial complex here with some very big players. So, it’s naturally helpful for us to grow from this area. And the business model should be fit quite well with what’s going on. So, that’s sort of the big picture here. These are sizable opportunities that can really move the needle. So, that’s the background in context of how we’re thinking about the region generally. But maybe Colin can provide some context around customers and markets specific to this opportunity, and the partner.
Colin Gruending: Yes. Hey. Thanks, Al. Good morning, Jeremy. Yes. So, think about this project probably with a capital cost of $2 billion to $3 billion. We’re JV-ing, so we have half of that. In terms of commercial construct, of course, we’d like to term this out under a take-or-pay type arrangement. And we’ll be jointly marketing the facilities with our partner, I think, European fertilizer companies, domestic and European power gen with respect to hydrogen. So, the concept is pretty novel, exporting decarbonized fossil fuels. I think you’ll see more of these. And of course, the Ingleside facility has 54-foot dredge depth now, ample space to build facilities and is close to open water. So, that’s the formula and model we’re looking for here.
Jeremy Tonet: Got it. Thank you for that. I want to pivot to the WCSB here and the takeaway situation. Just we see a few different gives and takes here as far as egress is concerned. Trans Mountain, there’s delays. The Canadian government financing support is changing. They still need to build through sensitive population areas. So, there’s headwinds there, uncertainty there. But, at the same time, even with oil at $100, we haven’t really seen material FIDs out of the WCSB. So, do you see much growth out of the basin and shipper demand for more capacity that might underpin a new CTS if there’s more demand takeaway -- takeaway demand than CPS seems like maybe it’s a better option to incentivize that? Or do you not see this demand materializing and base doesn’t have much growth, and that feeds into cost of service being more likely outcome?
Al Monaco: Okay. I’ll start again, Jeremy. So, maybe I’ll start this way. The fundamentals here for the oil sands basin, and the basins generally in Western Canada are pretty positive. I think, we all know about the attributes around the size of reserves, the surety of getting those to market. And of course, the upstream group has done a tremendous job, both in terms of lowering cash costs but also on the emissions front. So, I think fundamentally, we’re very positive on that part. The signals, I think that they probably need to see going forward. Obviously, we’ve got very high prices right now. So, that’s positive. But they’re going to want to see some stability in that long term. We don’t need $100 oil for that to happen, but certainly, clarity on where it’s going longer term. They’re going to be looking at capital efficient solutions, debottlenecking first. Everybody is concerned about supply chains, and of course, as you referred to, egress of the basin. And that’s where we come in, which, as we alluded to in the remarks, the Mainline is extremely well positioned for this. The Mainline tolling agreement actually will be important in that we need to see clarity on the commercial underpinning for those projects that we have in the queue here, which Colin can get to, but we need some clarity on that in order for us to continue to incrementally expand. And again, in this environment, incremental expansion, optimizations on the system are ideally suited, I think, for where the basin is and what these producers need to see in order to invest additional capital. So, the basin generally will be probably behind in its ability to react to increasing prices here as we’ve seen compared to, say, the Permian just because of the nature of what we’re talking about in the oil sands, longer-dated investment profiles. So that’s the bigger picture. Colin, do you want to give some specifics around where we are on the expansion opportunities and the timing?
Colin Gruending: Yes. Thanks, Al. So, we’re keeping our Mainline expansion opportunities, ready to go here and advancing long-lead items, enable them to be there. We believe industry will continue to want some egress or some insurance egress having not had any for decades, and we’ll potentially leave that into any commercial arrangement we negotiate here. The timing of those will have to be TBD, but we’re keeping the warm, Jeremy.
Al Monaco: I’ll just add one more thing here. Colin, you were mentioning TMX, Jeremy. In the bigger picture here, again, if you think about it, we’ve got what would be two nice pathways through to the Gulf Coast, and that will continue to be an extremely strong market. The thing that’s happened recently here in terms of the security buffer that we’ve been talking about is the export position that we have relative to those two paths, I think it’s going to be ideal in terms of the longer-term future of heavy oil coming out of Western Canada. We know that the Gulf Coast is a great destination for that and will continue to be. But now we’ve got this additional opportunity to really generate greater exports out of that region, too. So, that bodes well for us, I think.
Operator: Rob Hope from Scotiabank is on the line with the question.
Rob Hope: I want to circle back on the B.C. expansion projects. When you take a look at T-North, I guess, the first phase of the expansion as well as the second phase of the expansion, specifically in the first phase, is that dependent on the T-South expansion and Woodfibre? Or could we see that progress independently just to serve LNG Canada demand?
Al Monaco: I’ll go quickly, and then Cynthia will chime in. So on T-North, that goes ahead regardless. So, that’s the binding open season we’re talking about. On T-South, I think that is most probably dependent on Woodfibre LNG sanctioning. So that’s the short answer. Cynthia, do you have anything to add there?
Cynthia Hansen: Yes. Thanks, Al. I think you covered it in your earlier remarks. We see the volumes that are currently going to be assigned to Woodfibre serving the U.S. Pacific Northeast. So, when those 300 million cubes a day move to Woodfibre, then we’re going to need to come in with some additional supplies. So, that’s why we’ll really have that opportunity to expand T-South when that happens.
Rob Hope: Right. Thanks for that. And then, B.C. can be a challenging place to build pipe at coastal and Trans Mountain are learning. How do you secure the supply chains and the development pipeline to give you confidence in these large investments?
Al Monaco: Well, I think, again, I’ll go first. On the west, I mean, this is really the crux of the advantage, I think here in this particular case, whether you look at the community aspects of building your infrastructure and obviously the indigenous groups that are along the right of way. The fact that we’ve been there for so long, the fact that we have good relationships and the fact that in this particular situation we’re not doing a lot of looping or twining of pipelines here. So, I think in this case, we’re in pretty good position to expand the T-South system, certainly that goes for T-North as well. Supply chain wise that’s something we’re going to have to manage. Everybody is I think exposed to increasing costs here, inflation and so forth. So, it’s something we can manage. We’ve got pretty in depth supply chain group here that looks at this strategically and can really bring the size of our company to bear in terms of base-loading particular contractor. So, I think we’re in reasonable shape these days, as far as you can be in a tough environment, permitting wise and in an inflationary setting. So, I don’t know, do you want to add anything, Cynthia?
Cynthia Hansen: We have had, obviously, as Al said, a long history of operating very successfully in B.C. The challenges that everyone is facing, it’s not just in B.C., as we know. We need to continue to focus on our customers and our stakeholders. We’re doing a lot of work. We continue to want to progress these projects, but we do need that stakeholder support and customer support. So, if we focus on those fundamentals as we have in the past and really allow us to continue to be successful.
Operator: Praneeth Satish from Wells Fargo is on the line with question.
Praneeth Satish: Thanks. Good morning. On the Ingleside facility, I just wanted to get an update in terms of the interest you’re seeing from customers to potentially export NGLs from this facility. It sounds like you’re getting some traction there. And if you did export NGLs, would you be looking to export LPGs or other NGL products? How much would you export and where would you source the NGLs from?
Al Monaco: Colin, do you want to take that?
Colin Gruending: We’re looking at various forms of purity, NGL export out of Ingleside. Won’t be too specific, but we’d be sourcing them locally obviously. And these are under development. So, I think I’ll just leave it there for now.
Praneeth Satish : Okay. Got it. And then, just staying in the U.S. So, gas production is increasing both in the Northeast and in the Haynesville and both regions have some egress constraints. And recognizing that you have pipelines in both areas, are you evaluating any potential projects to improve takeaway? And do you have the ability to do any brownfield expansions, or would they need to be Greenfield at this point?
Al Monaco: Cynthia?
Cynthia Hansen: Yes. Thanks. We obviously have our Texas Eastern system that leads us in unique position to serve Haynesville production and get to the Golf Coast markets with our existing infrastructure. So, there are some opportunities and -- for both brownfield and obviously greenfield, in this space. So, we’re continuing to have those conversations with the key players or key customers to figure out the best path forward to serve the incremental needs.
Operator: Robert Catellier from CIBC is on the line with the question.
Robert Catellier : A lot has changed since we last spoke. I’m wondering, if you can discuss, if there’s been, if you feel there’s an understanding by policy makers, especially in the U.S. for the need to get permitting, moving in order to build the infrastructure that’s required to deal with this energy crisis.
Al Monaco: Well, let me put it this way, Rob. I think we’re certainly hearing the right things. And how would I put this? They certainly get it. And as you can imagine, impact on consumers, all the way from home heating cost to prices at the pump, I think everybody understands the situation really well. I’m not convinced yet that we’re going to see quick action to provide additional clarity on regulatory and permitting. And just being honest there, there’s a myriad of issues, of course. General policy issues related to acceleration of lower carbon opportunities. You’ve got federal versus state jurisdictions, and quite a complex array of permitting agencies and approvals that are required. So, I think, we all know what needs to be done here, no doubt. I think we’re going to need a little bit of time for this to unfold. But certainly, if there ever was a time in terms of the signals that are being sent around the impact and the consumers, this is it. And so, we’re hopeful. And we continue to do a lot of work on this. As you know, these roles change over time that we have. And a big part of the role these days and all the people around this table is engaging with governments and explaining what’s happening and what we need to see in order to put capital to work. We have that capital. We’ve got the capability to work through these regulatory processes and permitting issues. But certainly, we need more policy support at a very high level. And hopefully that will come through. I will add too though that you really have to be skilled in this area these days, regardless of the policy issues that you’re alluding to. In terms of the ground campaign, if I can put it that way, Cynthia alluded to this, engaging communities, the work we do with indigenous groups. These are the things that really help get projects moving. So, those are the general thoughts.
Operator: Theresa Chen from Barclays is on the line with the question.
Theresa Chen: First, I wanted to ask about the Mainline System. In the context of changes in global flows of crude and the Russian production and exports on the crude side currently seems to be rerouted, but certainly some long term uncertainty there, coupled with Mexico’s publicly expressed intention to consume more and more of their domestic production, which is heavy sour in nature. There does seem to be an incremental bid in the marketplace for that sour barrel. And I was wondering, are these structural themes a factor into your discussion with shippers about the rate? And how do you view these themes in light of you know, the value and competitive advantage of your system? Not just mainline, but really Mid-Con all the way to the Gulf Coast?
Al Monaco: Yes. This is a great question, Theresa. I think the short answer is -- and Colin can chime in too. We’re probably in the spot where it’s too early to tell. There’s no doubt that there’s a price change and that’s been driven by different signals on supply. And how Russian volumes get reabsorbed and how flows realign and change, I think that’s yet to be determined. But as I alluded to in the remarks, it’s pretty clear that -- and I’m going to say North America here because well, Canada and the U.S. because of the integrated nature of our systems here in North America, really are in position to fill this gap. And we went through that. The reserves are low cost. We’ve got reliability on our side. Security obviously is something we bring to the table, so. And you’re seeing this right now. Europe and Asia are going to be competing for natural gas. I know you didn’t mention gas, but that’s part of it as well. We’ve seen that with some of the LNG contracts that have just been signed up. So, we’re probably a little bit early to figure out exactly where the flows get realigned. But for sure, we’re in pretty good position. Now, on the Mainline, maybe, Colin you can just comment on what you think about that.
Colin Gruending: Yes. Thanks for the question, Theresa. I’ll give you a number here. So, 40 -- 45% is the market share position presently for Canadian crude in the Gulf, in the markets it competes with. So, the point you’re making is being alive and well for a while. And I think the points you’re making now even accentuate competitiveness of Canadian crude, and that you didn’t mention Venezuela, but that’s been a structural factor in decline as well into the Gulf. So, yes, the Mainline feeds all that. And as Al mentioned, we’re looking at another path down through Cushing as well, all feeding the same phenomenon. So, the Mainline toll acts as that foundational toll. It’s going to be an open access system. We’re taking contracting, our firm service off the table. So, all shippers will have access to that path.
Theresa Chen: Thank you. And would you mind commenting on what is the latest cost estimate on the Line 5 tunnel, please?
Al Monaco: Colin?
Colin Gruending: Yes, I could take that. Yes, sure. So, I think we’re probably looking there at about $750 million, Theresa, and probably trending up.
Theresa Chen: Got it. Thank you very much.
Colin Gruending: The cost for the both reroutes in Wisconsin and Michigan will be factored into any toll DOE we arrive with, with industry.
Operator: Linda Ezergailis from TD Securities is on the line with the question.
Linda Ezergailis: Thank you. Just further with respect to Line 5, I guess, one of the questions I would have is how do various policy makers and regulators and governments understand the importance of keeping existing energy infrastructure used and useful? Can you give us a sense of timeline to resolve various challenges along there and what some of the solutions might be to meet the needs of all holders?
Al Monaco: Colin, do you want to take that?
Colin Gruending: Sure. Good morning, Linda. So, I agree with your point. I think, Al mentioned this more broadly earlier, I think policymakers all around, certain both sides of the boarder, fully get the importance of keeping existing infrastructure flowing, especially in light of recent events globally. The Canadian government has shown up loud and supportive on all elements of Line 5 here in both, Michigan and Wisconsin, comments made -- in-house comments this week with respect to that. So, that’s all encouraging. The time lines on both reroutes are multiyear. And we’re working through the permitting process fees on both and try to be along as prudently and as thoroughly as we can. So, that’s the latest there, Linda.
Al Monaco: And just a quick comment on that, Linda. It’s -- Colin is right about the Canadian government’s activity and involvement here, which has been very strong. But, it’s also state governments in the surrounding region of both, Michigan and Wisconsin, who certainly get the criticality of this infrastructure to their states and consumers in the region. So, that’s helped, too.
Linda Ezergailis: Thank you. And just sticking in the region, there’s an Ontario provincial election coming up. Can you comment quickly on any sort of potential implications for your presence in the province, and assuming more positive than any sort of challenges, but especially for your utility?
Al Monaco: Michelle’s here. So, she you can answer that.
Michele Harradence: Sure, and thanks, Linda. We’ve been working with the government on a number of initiatives, whether that says we’re looking at funding in RNG or hydrogen. But if I pull back, we have a very long history of working with a range of governments. And we know that we’re a critical asset to the local economy. The infrastructure we have in place is very valuable. And we really just don’t see that changing in any material way.
Operator: Ben Pham from BMO is on the line with the question.
Ben Pham: Looking through your slides, so there’s a number of chunky projects, $1 billion to $2 billion, and you guide in the B.C. LNG to -- it could be even more than that. I’m wondering is it -- are you at a point in time where that $5 billion to $6 billion of CapEx you mentioned previously that there’s potential upside momentum to that, maybe not the $10 billion range? But, it just sounds like there’s just a lot of pent-up demand to organically grow your business?
Al Monaco: Yes. I’m going to get Vern to comment. But just generally from my point of view, Ben. There may be -- yes, I mean, it’s always possible that that number rises, but on the other hand, I think that the important thing is how we filter the number and ensure that we maintain the discipline that we have been focused on here over the last number of years. So, yes, the hopper may be larger, but we’re going to be very careful about how much we deploy, which has generally been constrained to the amount of free cash availability that we have to invest. But, I don’t know, Vern, do you want to comment?
Vern Yu: Sure, Al. I think we talked about this very -- quite a bit at our Investor Day in December, and there’s really no change. The balance sheet is our number one priority. Having the flexibility in all markets is critical to us. Our free cash flow generation and some room that we have on our balance sheet provides $5 billion to $6 billion a year investment capacity. So, we’re going to go through and make sure that the highest and most attractive projects get done first. And then, if we have too many opportunities, that’s fortunate some of these won’t just proceed.
Ben Pham: And what about the Ridgeline project? Could you provide a commercial update on that project?
Cynthia Hansen: Yes. Thanks. So, Ridgeline, we’re continuing to progress with that. There will be an opportunity as we move forward. We’re still awaiting FID. So, again, that project, as we currently plan to go forward, if we get the FID, that would be a Q4 2026 in servicing.
Operator: Brian Reynolds from UBS is on the line with the question.
Brian Reynolds: Maybe just a follow-up to some of the questions on the heavy oil coming out of Western Canada. It seems here that Mainline is progressing towards the tolling agreement in ‘23. And I was just curious of how we should think about the potential tolling agreement and the expansion of Mainline? And whether they’re interrelated or whether the expansion ultimately could be announced before the resolution? Thanks.
Al Monaco: Okay. Colin, do you want to deal with that?
Colin Gruending: Yes. Thanks, Al. Thanks, Brian. Yes. It’s a good question. We talked a little bit, but to be clear, they basically need to sequence together. I think, Al mentioned this. We need clarity on the tolling agreement to understand how any expansions would work within that framework. So, I think that’s the order that needs to happen.
Al Monaco: Yes, just to put a point on it, too, Brian. I mean, this is -- one of the things we’re talking about with the customers, Colin and his team are in that. We need to have an underpinning. Like you said, we’re ready to go on these. And I think it will be really important to provide some additional capacity here given the opportunity that’s in front of the basin in terms of where we’re at fundamentally, which is what we’ve been talking about a lot on the call, very positive. But -- so hopefully, we can move the tolling agreement along, so we can get moving on those.
Brian Reynolds: That’s great. And in terms of just sequencing of events, could that also impact the Flanagan South and potential Seaway expansion in ‘24? Or are those kind of separate events in your view?
Colin Gruending: Brian, it’s Colin again. Yes. So, those are likely in that same mix. I think, as we just talked about and Theresa asked earlier, full path egress to the Gulf is the prize here. And so, it’s likely those would be considered or concluded together. The downstream legs of that path would be contracted though, maybe that’s your question, whereas the capacity on the Mainline would potentially be more open access, so, but likely to come together all at once.
Brian Reynolds: Makes sense. And then just quickly as my final question. Understanding the NGL and more details to come on that. But just curious if you could just talk about how the relationships with DCP and PSX and in addition to the new cracker in the region could ultimately drive success for the projects and ultimately, whether Enbridge were considering JV-ing with the project around NGL…
Al Monaco: I think, this is back to you, Colin.
Colin Gruending: Yes. Thanks, Al. I don’t have specifics here, but yes, we do have obviously a great relationship with the parties you mentioned, and they’ll be in the mix here, Brian.
Operator: We have reached our time limit and are not able to take any further questions at this time. I will now turn the call over to Jonathan Morgan for final remarks.
Jonathan Morgan: Okay, great. Thank you, everyone, for joining us this morning. We appreciate your ongoing interest in Enbridge. As always, our Investor Relations team is available following the call to address any additional questions you may have. So, once again, thank you, and have a great day.
Operator: This concludes today’s conference call. Thank you for participating. You may now disconnect. Thank you.
