Enbridge Inc. (ENB) Earnings Call Transcript & Summary

[Presentation] Good morning, and welcome. I'm Jonathan Morgan, Head of Investor Relations at Enbridge. And it's my pleasure to kick off our 2021 Investor Day. First, I'd like to acknowledge that the land we're meeting on today is the traditional territory of the many indigenous nations that have called this home for centuries. We're pleased to be hosting today's event live in Toronto as well as virtually via video webcast. Thanks to all of you who are joining us in person today as well as those of you that are participating online. Each year, we look forward to this opportunity to update you on our strategic plan and how our leadership is growing the business and positioning it for the future. As you know by now, our practice at Enbridge is always to begin each meeting with a safety moment. And so I'll use this opportunity to cover our evacuation procedures for the building in the event that we need to use them as well as COVID procedures for those of you here in the room. First, should there be a fire, you'll hear an alarm. And if necessary, this will be followed by an announcement to leave or evacuate the building. So please exit via the doors on the right-hand side here or the left for those of you in the room, then turn right and follow the staircase B, which will lead you to an emergency exit and down to Simcoe Park where you can wait for further instruction. Second, I'd like to ask each of you here in the room to continue to wear your mask if you're not eating or drinking. And if you're asking questions during the Q&A session, we ask that you also keep your mask on for that portion of the event. Thank you. In terms of agenda, we'll start with Al Monaco, who will provide an overview of our outlook and strategic priorities, followed by a short Q&A with just Al. Following that, our business unit leaders will walk you through updates on their respective areas of the business. And lastly, Vern Yu will provide an update on our financial outlook. Following this, we'll do another Q&A session with the entire management team. And during those sessions, we'll be taking your questions both here in person as well as via the video webcast. For those of you online, you can submit your questions using the form at the bottom of the screen. And please be sure to include your name and your firm. Lastly, on Slide 3. The legal team would like me to remind you that our comments today may refer to forward-looking statements and non-GAAP measures. And with that, I'll pass it on to Al Monaco.

Thanks, Jonathan. Good morning, everybody. It's great to be here in Toronto with many of you in the room and to connect with a broader virtual audience. And we're looking forward to our meetings tomorrow in New York as well. So our theme today is bridging to a cleaner energy future by capitalizing on the conventional runway we see and lower carbon opportunities that will extend that growth. The world is moving to a lower carbon economy, and our assets are going to play a key role in that transition. The photos you see here illustrate how we're evolving our business, expanding our footprint, modernizing our assets and our net 0 plan, pointing our infrastructure to tidewater to capture export growth and developing renewables and new energy technology. I'm going to start with the broad strokes of this morning's announcement and our value proposition, our approach to the transition and then our priorities and then how we'll grow and allocate capital in the future. The business leaders are going to talk about their conventional and low-carbon opportunities and then Vern will tie things together at the end with his financial review. Before we do that, let me speak to the recent CER decision. Now recall, we proposed the contract offering on our liquids mainline because a large majority of our customers wanted guaranteed access and fixed holes on the system. Given the CER decision, we're now moving forward with either a CTS-like tolling deal or a cost of service. A new CTS would make a lot of sense for us. But either option is attractive to us as well, and here's why. We've been operating under an incentive tolling framework for the last 25 years. That's aligned us really well with our customers because of the value our system brings to them and how we manage that system. We provide critical egress from Western Canada to the best markets with low-cost predictable tools. We're incentivized to maximize capacity and keep operating power cost in check as well as capital cost management. CTS incentivized us to add egress, 700,000 barrels per day of new capacity and debottlenecking another 400,000. Nobody else has been able to do that. Providing us value and managing those risks gives us a chance to earn returns above the cost of service. Customers haven't really been keen on cost of service, given how tolls fluctuate, and they like how we're aligned with them. From our perspective, though, cost of service still offers an attractive return and it does come with lower risk volumes, cost, for example. We're now reengaging the customers with the goal of deciding which option makes the most sense for them and us likely and hopefully by year-end is when we'll decide which route to go. Finally, it's our job to manage variability and we'll do that here. We've incorporated an allowance for a lower toll in our '22 guidance, and 3-year outlook. So let's get to the Enbridge story. First, 2021, as you heard in the video, has been strong. Solid business performance. So we're in very good shape to hit the guidance, and putting $10 billion into the ground. We've nicely accelerated our export in low-carbon strategies and sanctioned $2 billion, including the $1 billion you saw earlier. For 2022, we expect nice upticks in EBITDA and DCF, about 10% DCF per share growth over the midpoint for this year. That will support 5% to 7% expected CAGR through 2024, so we're extending essentially for another year. We're increasing the dividend by 3%. That marks the 27th consecutive increase. And that should land the payout in about the middle of the policy range, roughly 65%. So ratable dividend growth and conservative payout is the game plan here. And we've added a $1.5 billion share buyback program. Our 3-year secured capital program is $9 billion, and there's a large organic inventory we can choose from beyond that. But those projects will now compete against alternatives. The balance sheet is strong. We expect to be at the low end of the 4.5 to 5 range, and that gives us a lot of flexibility. Annual investable capacity will be roughly $5 billion to $6 billion going forward, and we'll be very disciplined in how we put that to work. The $2 billion in new projects illustrates strong organic growth across the businesses. And they're right down the middle of our commercial fairway. We'll get into these and the broader opportunity set through the morning, including our new CCUS JV with Capital Power and a potential $2.5 billion expansion of the T cell system in BC. So let's get going with the value proposition. Now everybody puts up a map, right? But here's what's unique about ours. Gas transmission, distribution and liquids are all demand pull franchises. We serve the best industrial and end use markets. And our scale drives highly competitive tolls to those markets. The assets you see here are going to be needed for a very long time in any transition scenario we can imagine. The commercial underpinning of this map, though, is also a big part of our value proposition. We're diversified with over 40 sources of revenue. The vast majority of EBITDA is contractor cost of service, so cash flows are highly predictable. On top of that, we closely manage financial risk. 90% of our customers are all investment grade, and 80% of EBITDA is inflation protected, and that's really important in this environment. All of this translates in our view to the lowest risk business model in the sector. The stability and predictability of our cash flows really did shine through in the face of COVID. We not only hit our original numbers, but we continue to grow. And at our recent ESG forum here, now moving to the next topic, we laid out the full story. And I encourage everybody to go back and look at the replay. But here is the basic takeaway. ESG has always been and will be part of how we manage our business, and our goal is to lead the industry. On the E, our priority is world-class safety. You can see how our extensive integrity program here on the left-hand chart is translating versus our peers. We set emissions targets and reduced Scope 1 and 2 already by 32% and 14%, and we're tracking Scope 3. Now today, and this is important, every potential new investment that we look at must exceed a carbon-adjusted hurdle rate and have a plan to achieve net 0 or we don't do it. On the S, we've raised the bar on community and indigenous engagement and D&I. And on the G, we've tied ESG targets to compensation, and we have a strong board diversity, oversight and independence. Our ESG capabilities are part of what we call being a differentiated energy provider. So what does that mean? Well, we think the upstream and downstream customers will eventually all insist on top-tier ESG performance from infrastructure providers like us. Line 3 is a good example of what it's going to take. We worked extremely hard to build trust with indigenous groups. That led to a better route and extraordinary environmental measures to minimize right-of-way impact. In other words, their engagement made this project better. And our economic partnerships created $900 million, $900 million in indigenous business opportunities, we are extremely proud of that. Before our Ingleside acquisition, we tested it against a range of transition scenarios. And we committed to net negative emissions by developing a 60-megawatt solar farm on site, much more than what we needed to offset emissions from the facility, and its location and proximity to industrial facilities position it for hydrogen and CCUS in the Gulf Coast. That's what we mean by differentiated approach. Last on this, we pride ourselves on identifying and taking action on surfacing value, and that will continue to be front and center for us. The best way to do that, of course, is by generating 0 or low capital intensity EBITDA. For example, the 400,000 in liquids capacity that we added at minimal capital, which was great for customers when they needed it, and it was good for us. Another example of the alignment. Since 2017, we've captured $1.2 billion in synergies from the Spectra acquisition, lower power costs, numerous efficiency drives and applying digital technology and digital is going to be the next big opportunity for us to apply to our massive asset base. We constantly look at upgrading the portfolio. We sold $9 billion of assets, as you know, at great value. On the right, you can see here we prioritized capital-efficient expansions first. You can tell by the multiples as a proxy for return. And while we're not serial acquirers, we look at tuck-ins where they come with embedded growth, and you saw that in the Ingleside deal. You can see how all that is translating to boosting of ROCE and how we've reduced leverage while growing the business at the same time. In fact, we expect to reach the low end of the target range. Bringing in our sponsored vehicles, that's not news to this group here, but it continues to pay dividends by extending our low cash tax horizon. The ultimate test though, if value is shareholder return. We've grown EBITDA nicely and return capital through dividends of more than $6 billion a year. Even though we're not satisfied the share price today, we have delivered sector-leading TSR. That's history, of course. So the goal now is to continue that track record. So shifting gears to how we'll invest and grow beginning with how we see energy fundamentals. There's a variety of transition scenarios at play here. To be conservative, we've used the IEA's announced pledges case in the charts you see here, which captures all policy intentions to reduce emissions regardless if they're legislated or not. And we know that will be a challenge. Any way we look at it, though, global energy is going up. Demand is rising driven by population, urbanization and developing countries. Supply mix is shifting to biofuels and renewables, we know that and less coal. But oil and gas is going to continue to fuel the global economic engine. And recent events have made that pretty clear not just on demand, but in terms of reliability. Demand for energy in China, India and Southeast Asia is going to continue, but North America is in a great position to gain global market share. Because of the abundant resources in a highly competitive pet chem sector, but we also produce the most ESG-friendly energy in the world. That's a fact, if you look at the scores by country, especially Canada and the United States. An industry is also driving its own emissions lower. All of this means more supply pointed to export markets, especially LNG. There's a long runway for conventional energy because it will remain critical for transportation, heating, cooking, electronics, medical devices, pharmaceuticals, plastics, the list goes on and on. Now the pet chem sector drives much of this, and it's 100% dependent today on conventional feedstock, no ready substitutes. And there's no way that we can maintain energy reliability, cost and meet the demand for growing renewables without natural gas. Now you'll see we're very bullish on hydrogen and RNG, and we're taking action. We're investing. But that will take time to scale up. The point is that conventional energy is essential to meeting the energy demand that everybody agrees on. And that means we need to pull all the emissions levers that we have: efficiency, conservation, new technology, CCUS. The industry, though, is showing it can be effective in reducing its own emissions. We just need to embrace the industry to do that. Our transportation and storage assets will be part of making this happen. Our conservation programs incentivize 4 million utility customers to reduce consumption. We're modernizing assets and adding solar at our pumps and compressors. And we've played a huge part in displacing coal with lower emissions natural gas and through utility scale renewables. Here's how we're approaching the transition. First, to meet energy demand, you need roughly $7 trillion of conventional spending by 2030, which means continued growth in infrastructure. Our assets have longevity because they need -- they feed the best markets. The transmission business, for example, serves 170 million people, not just in the U.S. Northeast, but elsewhere. Our utility, 15 million people served. And our liquids pipes feed $12 million of refining capacity. That is a very big chunk of U.S. capability today. Our systems cannot be replaced. They can't be replicated, so we'll need to expand and modernize them. And the transition accelerates our assets to enable low carbon fuels. Natural gas will need to take over baseload and more intermediate and peaking capability. Our pipes will blend and transport RNG and hydrogen and transportation and storage will drive CCUS. But what's really important strategically is getting the pace of transition right. That means you've got to be aligned with policy and economic signals, not too far ahead, but you can't be behind. Ensuring commercial structures provide a return on and return of capital, not being on the bleeding edge of technology and partnering to supplement capability where you need it. If you think about it, that's exactly the model we used for wind and solar 20 years ago when we started that business. And today, we've got a fully capable renewables platform. Now this slide gets to the 2 parts of how we bridge to the clean energy future. Each business will continue to capture conventional energy growth. And they've developed strategies to capitalize on low carbon. You're going to hear about that. And our renewables business is starting to blossom with numerous onshore and offshore opportunities. So given that, where are we overall in our priorities. Well, the priorities are largely consistent. Safety and reliability number one, extending our industry-leading ESG position and we'll maintain our strong balance sheet. When we're talking about extending growth though, most of the near-term growth will prioritize capital efficient expansions, export infrastructures, modernization and utility rate base. Spending on low carbon will be mostly renewables in the near term, but we are making selective investments in new energy, so RNG, hydrogen, CCUS and those will ramp up more over time. This next slide outlines our expected annual opportunity set. From the $17 billion we have in 2021, our new 3-year secured only capital through 2024 totals $9 billion. So that reflects putting the $10 billion into service this year and adding $2 billion of newly sanctioned projects. But we also see another $6 billion of annual organic potential above that, which can supplement the $9 billion, and it drives growth beyond 2024 outside our planning horizon. How much of that gets sanctioned, though, depends on our capital allocation funnel, and I'll come back to this in a minute. Now compared to last year, you'll notice increased potential in our gas businesses. Up to $2 billion annually in gas transmission and modernization, singles and doubles to support gas-fired generation, and we're really excited about the LNG opportunities and another West Coast system expansion that I mentioned earlier. The utility business continues to generate growth, $1 billion to $1.5 billion of annual regulated capital driving high-quality ratable EBITDA. In liquids, there's about $1 billion of annual opportunity targeting optimizations, Mainline and market access expansion. Colin will get into that later. Ingleside on its own actually drives about $1 billion in growth over the next few years on its own. And in renewables, we think we can deploy about $1 billion annually. Now I want to pause in renewables for a minute here because it's probably on your mind. Right now, we've got 1.5 gigawatts gross in construction that will start cash flow in the end of '22 through 2024. We're also really excited about the floating wind pilot, we're now building offshore France and South of France. The bigger prize here on that one is that working with EDF on another 750 megawatts floating. Matthew is also going to provide our latest thinking on opportunities on renewables around the pipeline footprint. Now there's a lot of exuberance out there in renewables. We seek capital, a lot of capital chasing projects, especially from large new entrants. So we have to be very disciplined and we are. We've turned a lot of projects down in the last 2 to 3 years because of this. Let me just pause for a minute more, though, on the power of our existing businesses in developing low-carbon opportunities. In the utility, we have 4 operating RNG projects, but 50-plus more in development in franchise and outside Ontario. We put our first green hydrogen plant into operation 3 years ago. You saw that on the video. And we're now blending into our utility gas system, making great progress on this. Behind that, Cynthia will get into this one, 10 to 15 projects in development as well in hydrogen. The proximity of our Dawn storage business to Sarnia, the industrial area, positions us as a natural hydrogen and carbon capture hub. Gas Transmission business is developing 8 RNG projects right now with more coming, and we're assessing how our long-haul pipes can move hydrogen in the future. The team is also focused on solar self-powering, compressors and pumps. 3 facilities operating, 10 more in construction. On CCUS, we're partnering with Capital Power, you saw that this morning to develop a carbon capture hub in Alberta. We provide transportation in stores there. That's our expertise for their local CO2 load. And our new Ingleside export terminal is an ideal location for a new hydrogen and CCUS hub in the Gulf. Based on that, we could see capital of roughly $1.5 billion through 2025. It could be more but certainly ramping up from there. Given the positive fundamentals we see and our role that we will play in this area, we've built the capabilities here, and we're continuing to do that. We're also organizing for success. We've now established a dedicated new energy team or NET, NET will coordinate strategy and allocate capital across those businesses and importantly, they develop partnerships that give us access to new technology, complementary assets and skills. That's coming along really well, as you can see on the right here, top quality partnerships with 5 so far. Now to this point, I think it's clear we have a big inventory of organic growth. Now let's talk about how we're going to pick and choose. Our capital allocation priorities haven't changed materially, a strong balance sheet, ratable dividend increases and continued investment to sustain growth. As you can see from our guardrails here on the right, we're where we want to be. Leverage at the bottom of the range, pay out of the middle and our low-risk model intact. We're going to judiciously allocate every dollar of free cash flow and we're not going to shy away from selling or monetizing assets to create more flexibility. We're increasing our dividend, as you saw, by 3%, so another good bump. And even though we're growing at a good clip on DCF per share in '22, a larger increase doesn't make sense in this environment. But we're adding a share repurchase program, which will give us another way to return capital. Just as a reminder, the dividend increases will be up to the level of DCF per share growth outlook, which, again, is 5% to 7% through 2024. Now this slide addresses how we think about allocating capital between businesses. Liquids will generate strong returns and significant free cash. It will continue to grow, but with lower capital intensity versus the larger scale, longer lead projects of the past. As you saw, there's a growing opportunity set in our gas businesses, so they'll consume free cash flow. Our renewables business is in the same category over the next few years. Now just a couple of takeaways on this point. These 4 businesses all generate strong risk-adjusted returns, and they've got embedded growth that we feel very comfortable deploying capital to. Together, they are a strong portfolio that drive our low-risk business model. And there's synergy between free cash flow generation and capital-consuming businesses, not to mention, overhead, operating, financing and tax synergies. So let's look at investable capital -- capacity rather and the capital allocation funnel that we'll use. In '22, we'll generate about $11 billion of free cash flow after maintenance, taxes and financing. We'll give back about $7 billion through dividends, which puts us in the middle of that target range. Inclusive of some of our debt capacity, that gives us $5 billion to $6 billion of investable capital, and that's the same as we described last year. Here's how we think about deploying this big capacity that we have. We'll prioritize $3 billion to $4 billion annually to core investments. That includes system optimization, modernization and rate base growth. Those investments are highly strategic, economic and they drive cash flow. We'll deploy the remaining $2 billion though to the next best alternative. Now in the past, organic growth would have been the slammed up first priority for that $2 billion. But today, it competes for other options. The competition buckets look something like this. And you see that squared out on the right here. Organic growth will continue to be part of the opportunity set as well low carbon projects now. We'll continue to evaluate asset deals, but the threshold for asset acquisitions will continue to be high, needing to be commercially consistent price right and come with embedded growth. And share buybacks will now be part of the equation. Now a point to note on this. We're going to focus on maximizing the aggregate use of that $2 billion. So the actual allocation could involve a combination of these options that you see here, and reducing debt below our range is also possible to provide added flexibility for future opportunities. On the buyback program, how we utilize this will depend on a few factors. First, where we sit in the 4.5 to 5 leverage range, entering '22, the EBITDA from the $10 billion we put into service this year will drive our metrics to the low end of the range. So that's great and gives us confidence in our financial flexibility. And of course, that stems from Line 3 coming into service. It will also depend though on the size and timing of organic and asset acquisition opportunities. And naturally, we'll look at the fundamental value of our shares versus the other 2 options. So this will be, in other words, a dynamic decision process. So this slide translates what I've talked about so far into the 3-year outlook. We expect to achieve 5% to 7% DCF per share growth through '24, driven by strong operating performance, annual revenue inflators and productivity measures, assets we put into service and new investments through this period. After '24, growth will be driven by the same factors, that's the $6 billion bucket $3 billion to $4 billion of that in core investment and deployment of excess capacity to the best opportunity. So there's ample opportunity here to grow in the future. So before we hand it over to the business unit leaders to go through the story in more detail, we're going to pause now for the first Q&A session, and Jon Morgan will kick that off. Jon?

Great. Thanks, Al. So this is going to be about 15 minutes with just Al. We'll be taking your questions online as well as here in the room. There's a microphone in the middle of the room here for those that would like to queue up and ask questions. And for those of you on the webcast, please use the question box at the bottom of the form and I'll be reading those on your behalf. So let's begin, feel free to queue up. We'll start with Rob Catellier, CIBC.

Just a couple of quick questions here. First, I'll start with the CER decision on the mainline and understanding such a big decision, nobody's going to agree with everything obviously. But I'm wondering if there's anything in the decision that warrants an appeal?

Well, obviously, we spent a couple of days going through that Rob, over the weekend, I guess, last week now. And we were pretty thorough about it. Certainly, there's always opportunities for that, at least in theory, but our judgment is overall that we're accepting the decision, and we're moving on to the 2 options that I noted there. So I think that's what you should assume.

So that's a good segue to the next question. Given your dual path approach, we're going to explore 2 opportunities, whether it's some version of incentive ratemaking or maybe moving to a cost to service. So I'm wondering in those 2 dual paths, is there anything in there looking into your crystal ball that you think might change how you look at either the 5% to 7% DCF growth rate, how you manage the balance sheet or capital allocation, including the payout ratio?

Well, the short answer is no. And part of it is what I mentioned earlier around the allowance we've made for potential outcomes, let's call them different scenarios that could unfold. So we've put that into the guidance. And I would second that on the balance sheet. I think at this point, any variation that we see in the outcomes in any of those -- out of those 2 options wouldn't really have a material impact on either the growth rate or the balance sheet.

And same for the payout ratio and capital allocation there?

I'm sorry, say that again.

Same thing for capital allocation and the payout ratio?

Correct, correct. Yes. I mean when you really get down to it, roughly, I guess, over $15 billion in EBITDA is what we're looking at for 2022. And any scenario that we can see, we don't really see the variability in that range, affecting growth, capital allocation or anything else that's material to us right now.

Hello. Rob Hope, Scotiabank. I wanted to delve in a little bit further into your comment about 3% dividend increases kind of as much as you want to do in this current environment. When you balance the strong growth in 2022, low leverage, kind of the payout ratio in the middle of the range right there, is that, in essence, kind of signifying at a 7% yield, you do view share repurchases to be a better use of capital versus the dividend?

Well, the way we look at it, Rob, is we see share repurchases potentially supplementing that 3%. And if you go back here, again, sort of reiterate, we see the potential for dividend increases up to the level of that 5% to 7% for this 3-year period. I think what we're saying is this year, and we make these decisions year-to-year as to how far to go in that range, it really made sense to keep it at 3%. The reality is, as you're pointing out, a 7% yield really is telling us that any more than that is really not justified. So I think that's how we look at it. At the same time, I'd have to say I don't see it going below 3%. So I think that's the overall context of the decision. I'm not sure if that answers your question, but that's how we think about it.

And then another follow-up on share repurchases as well because you said you'd balance it between timing of organic opportunities as well as M&A. M&A very difficult determine the size and timing of that. So when you take a look at potential share repurchases, could we see a bias towards the back end of the year just given the flexibility and timing for potential M&A?

That's probably a good observation. I mean if you think about it, we're at the high end of the debt-to-EBITDA range on a trailing 12 basis now because we've spent essentially all of Line 3, but we haven't seen the cash flow in terms of the trailing EBITDA -- debt-to-EBITDA. So probably as we get further into the year, it will become more useful or I guess we could use it more. But certainly, it doesn't preclude using the buyback program earlier in the year. Again, it depends on where our share price is depends on those other opportunities you mentioned. And again, how we progress through the debt-to-EBITDA through the year.

I'm going to jump in here. All with a question from the webcast. So it's from Michael Lapides at Goldman Sachs. How is the company's view on corporate M&A? Do bolt-ons appear attractive here? And are there related businesses, renewable utility that seem attractive? Or would M&A, if any, likely come within the core oil and gas pipeline infrastructure side?

Okay. Well, let me maybe speak to -- well, first of all, large-scale corporate M&A is not on the table. We're not focused on that right now, Michael. As far as the kind of call it the asset tuck-in category, there's lots of opportunities out there, obviously. But the threshold there, as I mentioned in my remarks, is going to be pretty high. If you look at Ingleside, for example, it really came together quite nicely. Strategically, it fit the Gulf Coast. We've got an asset that has unparalleled competitive position. It came with growth, and it came at a good price. So that's a pretty high bar to reach. There are a lot of opportunities out there that we look at, but that's generally how we're going to see the criteria, if I can put it that way. Now you mentioned renewables as potential. Frankly, we're pretty well set with our inventory of opportunity on renewables and we like the fact that we're building that business organically. And as I mentioned, anything that you see in that space right now in terms of M&A is out of range, and we don't think are at reasonable prices. So I think that's the general approach that we're taking here.

Andrew Kuske, Crédit Suisse. Al, maybe if you could give us some perspective on just half the balance sheet is effectively in the Liquids business and then somewhat constrained on growth opportunities. And then you look at the other half of the balance sheet, you're going to grow at an outsized rate. How much of that is effectively in your network, in your corridor where you can have high returns because they're just extensions of assets? And very predictable for the most part versus things that are a little bit reaching out?

Yes. That's a great question, Andrew. So I think the way to conceptualize this, the $3 billion to $4 billion that we identified is right down the middle. It has the combination of very good returns, very strategic to our business. The utility is a good example. And it comes with future growth. So expanding extension of the franchise is the first priority. And I think we have ample opportunity to ensure that, that will continue. In fact, the $6 billion that you saw there in that list, if you go through each item on the chart, they're pretty much right down the fairway. So before they even get into that hopper, they've kind of cleared the strategic and financial hurdles that we look at. So that's the big picture on how we see that -- is that...

It does is helpful. And I guess maybe bigger picture when you think longer term, what's the bias of the balance sheet from a business composition?

Yes. So I think in the chart we saw there, I think will naturally happen given the bigger opportunity set that we see right now in gas transmission and renewables, you'll see those kind of consume a little bit more of the pie. And not that the liquids business isn't growing and not that it doesn't generate great returns and give us a lot of free cash, but that will be the natural, I think, morphing that you'll see over time just given the amount of opportunity that is there capital expenditure wise in the other businesses. So I call it a kind of a slow morph, if you will, on the balance sheet as well.

Great. So we'll take another one from the webcast, Al. This one is from Jeremy Tonet, JPMorgan. So with regard to getting the pace of energy transition right, what do you see as the time line for first CO2 injection around CCUS? And how do you see the pace of CCUS generally unfolding in Canada and the U.S.?

Okay. Well, on the timing, I think the new JV we just set up, if you look at what Capital Power's communications are and our discussions with them, it's probably going to be 2026. And I'll tell you, this is a very exciting project. And at 3 megatons of emissions or CO2 sequestration, it will be one of the biggest projects in the world. So the direct answer is 2026. In terms of the future scale-up of this, when you really get down to it, we went through those buckets that were going to be required for emissions reductions to hit any of the targets out there. CCUS is going to be a necessity. So I think we're going to see a very steep ramp up, an exponential ramp up in CCUS investment I would put United States maybe slightly ahead, just given where they are with their incentive package around 45Q, and that will likely rise. Canada, though, I would say, is close behind. A lot of discussion happening right now between industry and government on what the right structure is for a 45Q like opportunity. And again, we need that to really attract private capital to get moving on CCUS. So I would see this as one of the biggest priorities in terms of energy generally.

Rob?

Great. I've got some questions here just on capital allocation. Now you mentioned it's going to be a dynamic process here. You mentioned that large-scale M&A is out of the question at this point. But you've introduced share buybacks. So as you think about changing the business mix, you said you're not afraid of asset sales or asset rotation. So can you talk about the role of asset rotation to help drive changes in the business mix?

Well, let me start with this, Robert. We're very happy today with the portfolio. I think I went through that as to why that is the case, why we think deploying capital in the existing asset base makes a lot of sense for us. And I think it will be -- I think this really comes down to in terms of allocation as to being opportunistic around what we see. And the comment about not shying away is if we got an extraordinary offer for, say, a piece of an asset, even though it was core to us, we wouldn't hesitate on something like that because it's going to surface value. And so that's something that we always try to do. We try to be dispassionate or agnostic about the assets that we love it, obviously, if you go through the 3 core franchises and now renewables. But we have to be diligent and disciplined about surfacing value where we can. So those are the opportunities that we will look at.

And so then with that answer, would you characterize it as being more responsive to inbounds? Or are you proactively looking to...

Yes. I see the question. It's certainly more proactive. I mean we go through an annual planning exercise. And it's actually we reviewed every quarter with the Board. And we talk about things like this. We look at our assets and we say, what kind of value can these garner in the market if we were to sell, say, a small piece. So I wouldn't say it's responsive. That's usually not a great strategy to make stuff happen. So we'll look at everything, and we'll be proactive if we need to.

And then as you think about some of the new energy spending, CCUS and the like, could be some very large capital deployment. You talked about potentially reducing leverage temporarily to help open up optionality. Would you see leverage going below that 4.5x on the low end just to open up that optionality, especially if you're starting to see some of these longer-term initiatives materialize? Or is 4.5 really the low end?

Yes. That's the tricky part is that obviously, when you're employing share buybacks, for example, that's a use of capital that's hard to attract. So I think the essence here is that we have a very lumpy capital profile. It doesn't all happen ratably and you're not sure exactly what opportunities are going to come along. So we're going to be very careful about assessing when we're ready to deploy share buybacks, for example, or an organic opportunity, what the trade-offs are. And a lot of that has to do with the transparency of the growth opportunity, for example, the timing of it and frankly, the risk around being able to execute. So those are all things that we'll take into account, it's a bit nebulous and it is dynamic. So that's the judgment we'll be making every step of the way.

So one more question from the webcast, then we'll wrap up. So this one is from Patrick Kenny at National Bank. Can you provide a little bit more color on the embedded growth in the business and the role of technology and innovation in driving productivity improvements and how that contributes to the 5% to 7% DCF per share growth outlook?

Well, right now, generally, that possibility is in sort of the 1% to 2% we think about in terms of growing EBITDA with very low or minimal capital. And this is why we raised the point. It's a good question about what the levers are generating cash flow without putting a lot of capital into it. We've started a very significant effort, I would say, launched a couple of years ago with our technology labs, one in Calgary, one in Houston. And basically, this is a group of people, this is very exciting just to listen to them and talk about how they're going to look at opportunities where they're basically given license to apply digital technology, AI and the like, to our assets. And as I said earlier, this is a big opportunity, not just for Enbridge, but any industrial business. And I'm not just talking about putting additional sensors on equipment to assess where they're at in their lives and so forth. This has to do with how to really generate incremental value. We do a lot of this already in how to manage power costs by using algorithms to test what the optimal use of power is, for example. We use a lot of this already in how we manage and -- manage integrity in the business, integrity management and maintenance. And the team is doing a great job to make it more efficient, optimize the timing and when we do intense integrity work along the system. These are all incrementally potentially small. But when you add them all up, you apply this technology, digital technology to such a big asset base, there's a big opportunity. And going back to the beginning, that is the best kind of EBITDA to generate.

Okay. Great, Al. So we're going to move on to the business units, so I think you're going to introduce that.

Okay. So on the business units and their review here, we pride ourselves on having a very deep bench. And part of that is developing leadership at all levels. We rotate people around a lot. In fact, we call it putting people in a position of discomfort. So they gain a wider perspective on the business and broaden their own capabilities. And you'll see that Colin and Vern just switched rolls actually October 1, so they'll be speaking to their new accountabilities today. We're going to start, though, with gas distribution and Cynthia Hansen, who runs that business. So over to you, Cynthia.

Thanks, Al. I am very excited to speak about our great utility this morning and highlight how we are generating reliable growth and actively supporting the energy transition. We continue to safely deliver the energy our customers want to need while also driving synergies with the ongoing amalgamation activities. So let me start with a reminder of what great distribution assets we have. They are absolutely essential to Ontario and Canadian economies and will be needed well into the future. We operate the largest and best situated utility in North America with over 3.8 million meter connections, serving over 300 municipalities across Ontario and Québec. That's over 75% of Ontario residents. So the chart on the bottom left shows our strong customer growth over the last 7 years, translating into very stable organic growth investments of up to $1.5 billion annually. For the past 2 decades, we've been under various incentive rate mechanisms that have supported a strong ROE. For 2021, we should once again exceed our regulated ROE as we continue to add customers, complete reinforcement and growth projects while driving efficiencies. We are also extremely well positioned to continue to support and develop low-carbon growth across our franchise. Again, these are great assets are highly valued now and will be well into the future. 2021 has been a great year for the utility, even as we've continued to support our customers during the pandemic. As Al mentioned, we are committed to our ESG goals. In 2021, we've seen an improvement in our safety performance with an over 30% reduction in incidents. We've continued to directly reduce methane emissions on our system by focusing on small leaks, replacing devices and capturing methane when we're blowing down our system. We also focused on our ED&I goals, including holding stand up for inclusion events, where our team members shared their lived experiences. We've strengthened our base operations with cost and productivity improvements. So since the amalgamation in 2019, we've achieved over $230 million of synergies. We're on track to add another 45,000 customers. We completed over $400 million in growth projects, including over 190 individual projects and began advancing 25 community expansion and 2 economic development projects that were approved by the OEB with funding support from the Ontario government. Our continued focus on our customers has allowed us to advance our demand-side energy programs. We continue to lead in low carbon by placing another 2 RNG projects in service with another 15 currently in development. Our utility is in a great position to support our customers as they develop further R&D opportunities using our existing assets and our leading experience. And in October, we completed North America's first hydrogen blending facility. So as you've heard me say before, our assets are in a great location. With continued immigration into major urban centers, we see 30% population growth out to 2040. Our franchise area is an economic engine for Canada, generating 40% of Canada's GDP. We deliver over 30% of all the energy required in Ontario with a significant cost advantage as shown in the middle of the slide. Our assets are absolutely essential, and we don't see that changing. We've continued to see support from the Ontario and Québec governments including support for our natural gas expansion and new energies. Natural gas delivers about 3x the peak energy capacity compared to electricity in Ontario. And this was recently reinforced by the ISO report, that was released in September, which concluded that even for power generation, natural gas is needed to hit peak electricity demand. Once again confirming that our assets are needed for the foreseeable future. We continue to see strength and additions and expansions in the franchise and we make system improvements to support safe and reliable operations. This is really the core of our organic growth outlook. We expect ratable customer growth around 45,000 customers per year through the plan period. In June, we received the Ontario government's support to expand into 25 new communities and 2 additional economic development projects. In addition to growth, we are continually renewing our assets. In 2021, we advanced a number of projects to modernize our systems. And they have various in-service dates over the next few years. So inclusive of maintenance spending, which goes into rate base, these 3 areas represent about $1 billion or more per year of capital additions that we earn on. Our Dawn storage hub and the related transmission assets are a unique offering and are positioned well for growth. This includes the largest integrated underground storage facilities in Canada and the top trading hub in North America. Our 281 Bcf of storage at Dawn ensures that we can send out 5.5 Bcf per day of peak deliverability. The associated Dawn to Parkway system provides 7.6 Bcf per day of capacity. And we continue to secure growth projects, as outlined on the right including the newly structured or secured Dawn to corona pipeline project that is replacing aging compression that is being retired. As a reminder, our pipeline investments go into rate base and our storage is contracted. Lowering emissions is an essential part of our business. A big focus for us here is the demand side management, the sense, energy efficiency can contribute about 1/3 of GHG emission reductions through 2050. We delivered significant value with our DSM programs, having reduced GHG by 55 megatons of carbon dioxide since 1995. And we have an ongoing regulatory process for a new DSM program through the period of 2023 to 2027. With our DSM program, we can recover our direct costs and also earn an incentive for hitting milestones as we deliver efficiency programs to our customers. The 2021 Integrated Resource Plan decision provides a framework to drive incremental efficiencies and support the energy transition through rate base additions and direct cost recovery for alternative strategies. And this covers efficiencies, hybrid, dual heating, storage, et cetera. The plan will drive the best outcome for ratepayers and provides the right incentives for shareholders. So reducing emissions while providing customers with the right energy solutions. Both DSM and IRP programs fund customer expenses directly and allow us to both recover our costs and provide incentive for our business to earn a return. So one example of our differentiated approach highlighted on the right side of the slide is the hybrid heating pilot that combines both electric and gas heating. So lowering GHG while retaining the resiliency of dual energy sources. So like what we see happening in other jurisdictions, including Québec, peak energy needs, heating and cooling, can be met while optimizing the investment in the energy infrastructure. So as you can see on this slide, there are many areas of the low carbon market where we're investing and working with our customers to develop. So starting on the left, using the renewable energy, you can produce hydrogen and then it can be blended into the gas stream. It can also be used for peak power generation, transportation of heavy haul trucking for industrial processes that are hard to electrify or stored for future use at scale that exceeds battery capabilities. So RNG generation can be used to capture methane that would otherwise be released, and we blend it into our system. This graphic also illustrates that both these opportunities can support our energy efficiency programs as well as the opportunity to work with our industrial customers to capture and sequester carbon. So it's all part of an integrated energy solution that relies on our existing infrastructure and our capabilities. RNG projects continue to expand our natural gas footprint and they green our grid. So as Al said, we now have 4 operating facilities with 3 more in construction. And we have 12 in advanced stages of development. In total, we have line of sight to 55 projects, most of which were submitted with -- along with our customers, and these were projects under the clean fuel funding program. Currently, we have a potential 300 million opportunity set, secured and in VAT stages. We are also positioned outside of our franchise to invest in growth with our strategic partnership with Walker Industries and Comcore Technologies. So this partnership comes with technology and then 40 landfill relationships. And of course, we have our Niagara RNG project in construction. We're also leveraging our expertise by partnering and investing in other RNG sources like wastewater and agriculture. We are targeting to have 5% of our total gas used in our GDS system, be renewable by 2030. So we're working to advance specific supply targets in Ontario, like they currently are in Québec and BC, and this will support long-term investment in the sector. I'm very excited by the RNG potential and aligns well with our existing assets and expertise. So next, looking at hydrogen potential. We do have a strong base to support the build-out. We started building our hydrogen expertise in 2016. Through a pilot project with the ISO and NRcan, Enbridge had the first utility scale power to gas facility in North America at 2.5 megawatts. Now we're also the first to have a hydrogen gas blending facility in North America with 3,600 customers receiving a 2% blend as a pilot project approved by the OEB. We are continuing to build our expertise. We are developing a project in Gatineau that will start with a targeted 15% blend of hydrogen for 43,000 customers and a 15-kilometer hydrogen pipeline. We currently have 10 to 15 projects that we expect to see mature and we have strong growth as the hydrogen infrastructure, including hubs builds out and ties into our existing rate base. So while hydrogen will take time to fully build out, it is so exciting that our assets are well positioned to support the required infrastructure. Finally, we are also well positioned to develop and operate carbon capture and storage infrastructure. Our customers include the industrial corridors in Ontario. The total emissions in Southwestern Ontario is around 20 megatons of carbon dioxide equivalent. Our infrastructure supporting our industrial clients includes both pipeline and storage, as you can see on the map. And saline aquifers are likely suited for carbon storage. And we're currently working to prove out this potential with tests and pilots, along with the study that is underway to identify the full potential. We have both the regulatory and operational expertise to develop the lowest cost, best situated facility backed by relationships with our existing customers. There's a potential for a significant investment opportunity in the longer term into multiple billions. So in summary, you can count on the gas utility to generate ratable cash flows and predictable growth. We are positioned for continued financial strength. The future is very exciting. And as we pursue and deliver the low-carbon opportunities in RNG, hydrogen and CCUS. I am very optimistic about where we're headed, and we have a strong growth outlook, and we're exceptionally well positioned to capitalize on the energy transition based on our strong relationships with our customers. So thank you, and I'll now pass it over to Bill.

Okay. Thanks, Cynthia, and good morning, everyone. So I'm pleased to report that 2021 has been a great year for gas transmission. We're built on many decades of progress with new projects, continued modernization of our facilities and very favorable rate settlements. And we can look to the future and see the pivotal role that gas is going to have in any version of the evolving energy transition. I just can't wait to see what the energy picture looks like, 10, 20, 30 years from now. And one thing I'll bet on big is that natural gas is still going to be playing a central and a critical role. So I hope you heard what Cynthia was describing. And I know you heard the cutting-edge stuff they're doing. But I mean the basic description of the growth in her utility business, 45,000 customers added this year. The gas business all starts with the consumer, which is sometimes overlooked when we're talking transition. You first need to think about who we serve, where are our products used and the strong fundamentals surrounding the industry. You got to consider customer choices and their preferences, affordability and our compatibility with renewables. If you got the essence of the gas distribution story, then my job is easy because we serve that utility, and we serve 100 of the utilities just like it. Consistent growth in every component of what makes -- is what makes our business resilient, it makes us successful and what makes us so convinced of our long-term future. Natural gas is already pretty sticky, substitutes are tough to find, and we're a plentiful, inexpensive, clean, reliable option when the world wants plentiful and expensive, clean, reliable energy. So why are we so confident? Well, location matters. Our footprint is large and it's diverse. If you're a pipeline company that makes a living of selling long-term maximum tariff rate transportation contracts, well, this is where you want to be. In markets that serve 170 million people with A+ utilities as your customers. We're sold out for long terms with the best counterparties. We moved the most versatile fuel in the energy mix. We heat homes. We generate power. We complement intermittent generation. We feel the void left as other energy sources are retired or don't perform. And our customers are our partners, always have been. In the past several years, we've partnered with utilities in New England, Florida, the Midwest to serve increasing heating and electric generation needs. And now we're partnering with these same folks to blend renewable natural gas and hydrogen into our collective systems and to ensure that natural gas will be available globally through LNG export projects. So not only do we have a base business that's growing, but our pipeline and storage expertise is opening up entire new markets as we invest in the energy transition. So let's talk growth. We're not even close to the end of a very long run as the fuel of choice. The right side of this slide shows a few of the highlights from a successful 2021. We're fully contracted on virtually every asset we own. We're on track to have a record-setting year for our combined employee and contractor injury rate, far better than the industry average. Customer usage continues to set records. This year on Texas Eastern, we saw 16 of the top 25 days in its history. We've completed another strong year of investing in the integrity and the modernization of our system, and we continue to have very constructive rate settlements. And we completed multiple expansion projects in every corner of our system to meet the growth needs of our customers. A great year with many more to come. So what I'd like to do today is just to summarize in 4 stories of demand for our services, how we're doing. Residential and commercial loads, electric generation, LNG exports, and finally, the energy transition. Each one of these stories begins with an enduring foundation and it ends with growth, growth that continues to follow our capital investment principles and generate solid returns. So on to the first story, residential and commercial demand. So as I mentioned, we serve some of the largest utilities in North America. I think you'll find that the vast majority of our capacity is held and paid for by these utilities that serve residential and commercial load. That's a rock-solid base, essentially 100% reservation charges. And when those terms expire, we see consistent recontracting, contract renewal rates averaged 97% over the past decade, and this year around -- we're around 98%. Well, why is that? Simply put, this loads not going anywhere. It's actually increasing. It's extremely challenging to electrify residential and commercial heating needs, is one reason, cost. The average New England residential heating bill is just over $1,000 for gas. It's nearly 3x that in New England for electric heat. Then you layer on technology and consumer preference. No component of the energy mix is a silver bullet, but gas has significant advantages. It's a big benefit when your product is both desired and is far less expensive. Our customers, the utilities, they know this. As they look to the future, taking into account all the incentives being offered to electrify, all the goals for curbing or banning the use of natural gas, what do they project declines? No. Our largest LDC customers project 1% to 2% annual peak day growth in their Public Utility Commission filed resource reports. Our largest LDC, National Grid is predicting a 1.5% annual growth through the middle of the next decade. When they grow, we grow, and we're making capital-efficient investments in our system to keep reliability high and our carbon footprint low. We're investing between $500 million and $1 billion on these efforts each year. On Texas Eastern alone this year, we filed to earn on the $1.8 billion in capital investments we've made over the past 2 years, and we continue to make these investments wisely, balancing the customers' need for both reliable and economical transportation. This latest rate filing is a continuation of the framework we've outlined before, timely rate proceedings to ensure we earn appropriate returns on the investment of the system -- investments into the system. And through this work, we're seeing emission reduction benefits in line with our ESG targets. As we modernize and replace compressor stations in Pennsylvania, for example, we'll reduce emissions there by more than 25%. And even as we earn on these investments, natural gas remains the affordable option for homeowners and businesses. So that's a good start, a growing group of utility customers. Okay. Let's move to electric generation, which is Story #2 in our demand growth discussion. About 40% of the electricity in the U.S. is generated by natural gas, and that percentage is growing. Other baseload sources are dwindling coal slowly going out of favor, yet it's been easily displaced by gas over the last decade. Nuclear regrettably, reactors have been shut down over public pressure or expensive relicensing processes. Solar and wind are increasing, yet they're still single-digit market shares. And as we know, they only operate at certain times in the day of the week. So let's put a little math to retiring and replacing generation. Over the past few years, 3 nuclear plants were retired. All within 200 miles of each other in the Northeast U.S. So Vermont Yankee, Pilgrim, which is in Massachusetts and Indian Point in New York. That's 3,300 megawatts of baseload generation. What's making up for that for now and for the foreseeable future, it's natural gas. At a kind of average load factor, adjusting for load factor, it would take 8,000 megawatts of installed wind capacity to fill that void. That's on average. On peak, it will be closer to 25,000 megawatts, just making up for 3 decommissioned nuclear facilities, natural gas-fired generation is the logical choice. And it's widely known. It's a chart here last month, the U.S. Federal Energy Regulatory Commission produced their winter outlook report. And in 3 of the electric reliability areas that we serve, the amount of gas-fired generation is expected to be significantly higher this winter than the average of the previous 5 winters. So in PJM, on average, it's been 31%. This winter, 34%. In New England, 45% on average, this winter 52%. And in New York, it's been 37% on average and this winter, natural gas is expected to be 47%. We're seeing the increase in coal retirement and corresponding increase in gas usage continue across our system. And to create super opportunities for us, like in Tennessee with our Ridgeline project. And here, we're working with our long-time customer, TVA as they're looking to replace a coal-fired power plant in Northeast Tennessee, converting from coal to gas will result in about 60% lower emissions for them. And just as TVA considers future emissions goals in their planning we're actively designing new projects with a net 0 target in mind. On a Ridgeline, we're scoping electric horsepower, and we're designing in solar self power to offset nearly half the power at one of those compressor sites, further reducing our project scope 2 emissions. So this project is a great example of our approach to efficiently deploy capital towards traditional growth projects with emission-reducing elements, all the while achieving very strong returns, a clean baseload, reliable power solution. There are plenty of opportunities to do this up and down our footprint. Okay. So let's shift gears and talk about our third component of increasing demand, which is LNG exports. In 2016, just 5 years ago, Sabine's -- Cheniere Sabine Pass, began LNG export operations. It was gas delivered by way of the Texas Eastern pipeline that made its way onto that first cargo. Since then, we've pursued a strategy to connect as many proposed export facilities to our network as possible, and it's working. In 2018, we began deliveries on long-term agreements with 3 shippers to supply Sempra's Cameron facility. In 2019, we followed that up by buying the Brazoria Interconnect pipeline and making capital improvements in the Texas Eastern system to serve shippers for Freeport LNG. Now we currently serve these facilities with up to 1.5 Bcf a day. We've contracted with Venture Global and just completed our Cameron project for them for another 750,000 a day to their Calcasieu Pass facility, which will go into service next year. And now the fundamentals of LNG are contributing to another round of growth opportunities. The recent shortages in Europe and Asia have sent natural gas prices skyrocketing there. And the world needs LNG to displace coal as we clean the global power grids. Buyers in several countries have indicated significant interest and we're beginning to see offtake contracts signed at U.S. Gulf Coast LNG export projects. Final investment decisions now appear a lot more likely, and we're in a great position to capture and serve these facilities for the long term. We've got agreements in place with Venture Global's Plaquemines facility, NextDecades, Rio Grande and Texas LNG for over $2 billion in new pipeline and pipeline expansions, representing about 3.5 Bcf a day. Now we're also seeing a trend towards differentiated LNG and our carbon emission reduction programs position us really well to be the green transporter of choice. Nicely complementing these LNG exports have got our efforts to serve the growing industrial complex in the Gulf. And we're expecting to see around 1.5 Bcf a day of Gulf Coast industrial demand growth through 2040 and for perspective, that's about a 17% increase over today's numbers. Now our opportunities related to LNG and their export, they're not restricted to the U.S. Gulf Coast. British Columbia, plentiful gas reserves and a great proximity to Asian markets. It makes it an obvious player in the world LNG market. As these LNG projects come to fruition, our backbone in British Columbia, the BC pipeline will need to be expanded. Now we've got quite a franchise here. The Pacific Northwest and Southern BC electric and gas utilities basically keep our pipe fully contracted. And just this past year, we completed a $1 billion expansion of T South and $0.5 billion expansion of T North to accommodate increased flows on the pipeline. So as Northern BC production ultimately finds its way to the coast, expansions to the BC pipe will be a necessity. LNG should certainly be exported from British Columbia. The supply resources are massive. And with the hydroelectric power availability, it's expected that Western Canadian LNG projects will be some of the lowest emitting projects in the world. Our entire BC system stands to benefit, whether from a major new export project moving gas west like LNG Canada, or a more bite-sized project, like the wood fiber LNG at Squamish. Just this smaller project would likely necessitate a $2 billion expansion of our BC pipeline. And again, on the industrial front, recent announcements out of Alberta for planned expansion of petrochemical complex has really caught our eye. So just like in the Gulf Coast, these opportunities fit our asset footprint very nicely. All right. So these first 3 stories were covering more traditional growth. Supercharging these opportunities are the new demand areas associated with the energy transition. We talk about the transition like it's something new. But we've been here before. Pre-1950, East Coast local distribution companies used synthetic gas made from coal to serve their customers. They switched to natural gas when a pipeline originally built to take oil to East Coast refineries during World War II was converted to natural gas in the late 1940s. That pipeline was our Texas Eastern Pipeline. So fast forward to today and similar transitions and plans for repurposing are taking place. And we're in a great position to capitalize on our footprint and our expertise in building and operating pipelines and storage. This time, the transformation is about incorporating more renewable natural gas and hydrogen into the current infrastructure. Specific to RNG, our recent work with Vanguard Renewables to get more methane from farm and food waste, cleaned up and injected into the pipeline system is much closer to reality. We've got 8 sites under evaluation and many more to come. It's a ready-now opportunity. There's a ton of growth potential in this to the tune of $0.5 billion in the next 5 years alone. Our existing customers are also increasingly talking to us about hydrogen projects. Potential here is an opportunity to deploy hundreds of millions of dollars in the near term. And our MOU with Shell contemplated across North America. We're part of major blending studies to keep our pipes used and useful, including the high blend study, which was selected and awarded funds the U.S. Department of Energy in November of 2020. We believe hydrogen blending and stand-alone new hydrogen pipeline in storage is a multi-billion dollar opportunity for us just this decade. And we're also evaluating carbon capture opportunities along key areas of our footprint, including the U.S. Gulf Coast, leveraging our customer relationships. Now as you might imagine, opportunities for carbon capture are very similar to industrial demand growth in very close proximity to our footprint. Our assets reach every top 10 emitting state, with the exception of California, and about 20% of the source of emissions in the U.S. are within just 10 miles of our existing transmission rights of way. CCS allows us to leverage what we're good at, constructing, maintaining and operating pipelines and storage. As we pursue complementary fuels, we're also actively reducing our emissions across the gas system with the latest technology, blowdown capture and operational practices, we prioritize reducing methane releases, through reporting as part of our one future commitments, we're well below the 1% methane reduction targets. And with regards to our power needs, we're employing solar self power at existing as well as that new compressor sites. In fact, our second solar cell power project, only the second one operating in the U.S., is now in service in Hidersburg, Pennsylvania, and 3 more are approved. Pennsylvania -- one in Pennsylvania, one in Ohio, one in Kentucky. That's another 30 megawatts to be put into service on our system, offsetting some of our Scope 2 emissions. And we're doing this -- we're doing all of this in the same way we've grown the pipeline traditionally, working with the customers, getting on the same page and striving for the same targets and ESG goals. So 4 stories, 4 demand-driven opportunities and a clear strategy to capitalize on what are great fundamentals for the natural gas industry as part of the energy transition. There's no one story here that's more important than the others. They've all got a firm base business and good prospects for growth. So I'll leave you with one last observation. And that's that our North American gas industry has been changing every decade. It's what makes our industry fascinating. In the 1980s, we had regulatory upheaval, things like gas supply realignment and FERC order 636. Then we had gas shortages with only 15 or 20 years of supply left. What are we going to do? That was followed by LNG, an LNG import build-out in the early '90s and 2000s to ensure that we had access to global gas reserves. And then famously, the 180 in the mid-2000s with the shale revolution, the replumbing of the entire gas system and correspondingly now, LNG exports to share our abundance with the world. My point here is that this industry is not afraid of what's next. RNG, hydrogen, bring it on. This is logically the next transition. I hope you can see our industry and the prospects for it as I do simply put natural gas as the cornerstone of the next several decades of the global energy story. And we're well positioned to capture $1 billion to $2 billion a year on investment potential, no matter what demand story you believe. So thanks very much. Back to Jonathan.

Great. Thanks, Bill, and thanks, Cynthia. So we're going to take a short break now. We'll take 10 minutes, and we'll be back at 10:10. I'll give you a 1-minute warning and then we'll get started with the second half. Thank you. [Break]

Okay. So we're going to get started again. If everybody could please take their seats. A quick reminder that we'll have a Q&A panel with all 4 of our leaders -- or, sorry, all of our leaders following the presentation. And now I'd like to a kick off the second half of the event here with Liquids Pipelines, and please welcome Colin Gruending, our Executive Vice President of Liquids Pipelines.

Thanks, Jon. It was good to connect with you during the break. I'm excited to be leading Liquids Pipelines. I support it for 20-plus years, and I'm thrilled to be leading it at present. In short, I see a long, bright future for Liquids Pipelines. It's a world-class franchise that we've built up over time, and we're blessed with an enviable strategic position. We also play an important role within Enbridge, too, with stable and growing free cash flow that supports our financial position, dividend growth and ultimately, energy transition. We also have unique positioning to site and anchor renewable power load and support the build-out of carbon capture. We've got positive momentum within liquids with multiple recent accomplishments, including bringing Line 3 into service, the Moda acquisition and record Mainline throughput. November's in the books, and at the pump, we're moving 3.1 million barrels per day, a new high watermark. Yes, there's still more work to do on Mainline tolling, and I'll cover that, now has briefly already. But today, I'm going to focus on how we're going to grow free cash flow by prudently investing in service of value creation for both our customers and our capital providers. In our business, footprint matters, and we have the best in the business. It's this footprint that gives me confidence that we'll be highly relevant for decades to come. We've built up strong positions that feed all the major refining markets, and now with Ingleside, we further extend to reach globally. And of course, we tap the best continental production markets, Western Canada, the Bakken and now the Permian. And our scale gives us competitive advantage. As you know, the portfolio generates highly predictable cash flows, underpinned by long-term contracts and cost of service arrangements. So let's discuss the Mainline. Al has touched on it already, but for context, this slide decomposes the geographic and commercial layers of the Mainline system tool, reflecting expansion agreements over time. The key point here is, though, that 2/3 of our tolls is essentially locked down through long-term contracts or cost of service rates. The bottom layers on the Lakehead System are a mix of cost of service and negotiated settlements. With the completion of Line 3 replacement, the $0.935 per barrel surcharge came into effect October 1 and is a 15-year separate and surviving layer of its own. What's left is the base Canadian system, which makes up only about 1/3 of the Mainline toll, which is what we're focused on today with our customers and the CER. We have 2 attractive and achievable commercial paths on the Canadian layer. As always, the path will be highly informed by our shippers' preferences. As Al referenced, we have a great history of operating in alignment with our shippers. We've managed to strike the right risk/return balance over many tranches of those arrangements. Maybe to help frame the commercial equation in play here. Recall there are multiple large levers to create value for shippers in the midstream path. The toll is one of them, but there are many other important levers as well. We've helped organize them here in 2 buckets: maximizing the barrels delivered every day and maximizing the value per barrel for producers and refiners. Some of these are huge levers, just considering each barrel's revenue value. I'll pick one to make the point. Incremental egress. It actually has a dual effect: both getting more barrels to premium refining markets and minimizing the regional discount in Alberta. Over the decade, we've been motivated under these arrangements, motivated to both optimize daily throughput and add over 1 million barrels per day of egress. So big value on both sides of the equation, I think you get the picture. Under the incentive tolling settlement, any of these value drivers can be included, creating alignment and win-win. But consensus can be hard to reach, so we're also developing a cost of service option that would reinforce our utility-like business model and earn an attractive risk-adjusted return. We're comfortable with either. At the end of the day, it's the risk-adjusted return that matters most. Time line-wise, this is illustrative, we'll effectively be starting down the paths here immediately in December. As always, we'll consult with the broad range of customers and stakeholders. If there is industry alignment, we would draft and file a settlement agreement with the regulator next year, with the goal of implementing the solution by mid-2023 or potentially even sooner. In parallel, if there is no consensus, we'll be in a position to pivot and file a cost of service application. The regulatory process for that contested case could take a little longer. In any event, we'll continue to operate under the existing interim framework until a new framework is in place. Okay. So now I'm going to widen the aperture a little bit from toll making to the fundamental drivers of our business. it's important to deeply understand the global and continental fundamentals given our breadth and, frankly, big role we play in the value chain. The myth, though, I wanted to dispel off the top is that crude oil is some sort of discretionary or disappearing energy source any time soon. It's essential to the quality of life we all enjoy, and it's embedded in everything we do. Now passenger vehicles get all the headlines. EVs will grow. However, over 80% of demand is driven by other sectors. A big driver will be the pet chem industry, pet chem demand. Nobody talks about this. Even in the most conservative outlooks we've shown here, pet chem demand grows materially, driven by population growth and economic progress around the planet. And it underpins every component in so many day-to-day items. It's 100% dependent on conventional feedstock with no ready substitutes or those that are affordable, at least. So clearly, oil has a meaningful role in the transition for decades to come. North American supply will be key in meeting domestic and global demand, which fortifies volumes on our pipeline systems for the long term. Canadian production is dominated by long-lived, low-decline oil sands projects, which are more like manufacturing facilities. Recall the production resilience in mid-2020, see in contrast to some of the shale basins. We expect continued measured Canadian growth in the near term from existing, debottlenecking and brownfield expansions. Yes, capital disciplined but still growing. There is a roster of brownfield projects building up behind it, queuing up, if you like, but we'll need more clarity on emissions and decarbonization policy for more of that to move forward. We see carbon capture as enabling further growth. Remember, we're looking for less emissions, not less energy. But our producers aren't waiting around. For example, the oil sands pathways initiative representing 95% of production in the oil sands has already developed a vision to reach net zero by 2050 and in step with government targets. And I should say, it's not just the E in ESG that will differentiate North American production. The S and the G are also world-leading. Nobody does this better. On the demand side, our North American footprint serves the most complex and profitable refineries on the continent. This means our refinery customers in the Upper Midwest and the Gulf will have a long-term role in meeting global demand, even if it begins to contract in local markets. And that's where exports come into play. The light and heavy Gulf Coast fundamentals are stronger than ever. On the heavy side, there's over 2.5 million barrels per day of coking capacity at the Gulf, which has historically been satisfied with foreign imports. But as imports have fallen off, it has opened a big window for Canadian heavy to gain market share. And our pipeline capacity has helped make that happen. The good news is there's room for more Canadian crude, which means additional need for connected heavy oil infrastructure like tanks and terminals. On the light oil side, the Gulf refining market is well served by U.S. domestic production. The Permian is one of the largest and lowest-cost basins globally. But as domestic demand wanes and Permian production grows, exports will be the critical relief valve to balance that market. We expect exports will increase back to 50% over the coming years to serve global markets particularly in Asia. Okay. Given the fundamental backdrop, this slide here shows how we're thinking about growth opportunities. And it will really kind of serve as the outline for the rest of my presentation. For context, when Line 3 R came into service in October, it filled up day 1. Therefore, hitting egress is still constrained. Barrels need to get 2 markets in the Gulf and to tidewater for more optionality and to maximize price. Given our footprint and our low-cost expandability and the complexity of the system, this is a big opportunity for us. First, we'll maximize operating leverage to capture growing supply. We'll fill our systems where there's capacity and optimize to move more barrels. Second, we'll pursue capital-efficient projects using DRA and increased pumping. Given the challenges with greenfield, we get that, and we're going to look to our existing footprint where it's a big advantage. Third, we're looking at logical value chain extensions. The current focus is in the U.S., southbound from Chicago to the Gulf and exports of both light and heavy. And we can efficiently expand our Ingleside facility and are building out our Houston presence, and I'll share our thoughts on that in a minute. It's pretty exciting. Finally, the fourth layer, consistent with what Bill was talking about and Cynthia, we've got low-carbon opportunities embedded in the business. We have a large appetite and capability set to offer self-power, CCUS as well as hydrogen potential. I think our messages on all these growth strategies are going to be efficient, executable and disciplined. So let's walk through the maps. I'll start with the specific growth potential from north to south in our system. In the oil sands, we currently have some prebuilt capacity that producers can grow into. That's incremental revenue without any additional capital investment, the best kind. Beyond that, we can use DRA and some minor pump additions to bring another 150,000 barrels per day, along the Athabasca Pipeline corridor. In terms of ex-Canada egress, Line 3 has unlocked the potential for more optimization and expansions in the near term and -- through DRA and ultimately pumping capacity. On our Express system, we've already implemented a DRA program, and now we're working with partners and customers on an interesting initiative to open up a new flow path to Cushing then down to the U.S. Gulf Coast on Seaway. Just think of the optionality and strategic value of another flow path. Overall, we see up to $1 billion of efficient near-term capital opportunities on these parts of the system, all with attractive build multiples. To be clear, in this business, I'm far more focused on the EBITDA contribution and not the big CapEx number. All right. Within the core Chicago area market, this market is now well served through expansions we've made, the Line 3 project, Southern Access Extension and more incremental barrels on the Mainline are now looking for egress beyond here into downstream markets. We've quietly already added a 90,000 barrel per day DRA program on Flanagan South this past quarter, which provides shippers greater flexibility and access to the Gulf. This is a great example of being both executable and efficient. The next high-value ad investment is more horsepower on FSP to push up to another 160,000 barrels a day into PADD III. The strategic linchpin here, though, is having the downstream tank terminal and export infrastructure in place as the Gulf becomes a larger and more liquid hub for Canadian heavy. Perhaps it's another incentive tolling idea. We have some of this in place today already at docks at Freeport and Texas City, which are accessible off our Seaway system that can load heavy cargoes, but it's limited in its current facility. We see our proposed Houston heavy hub, EHOT, playing a key role here, providing significant heavy oil storage and connections to the local infrastructure and refining and export outlets. We also see it becoming an important hub for the Canadian heavy barrel, improving liquidity and optionality for shippers. We often at this point get asked whether acquiring Ingleside lessens our interest in spot. The answer to this question is no. We see the complementary value of spot loading heavy and light barrels here, so it's complementary to Ingleside. We expect more news on these projects in 2022. Our light oil strategy is complementary, again, to our heavy business, now anchored by Ingleside. On this, we patiently picked our spot here, waiting for the right scale, strategic opportunity and the right price. And we're thrilled to have closed this quickly in October, and we love the valuation on this. Loading volumes, as you can see here, are ramping up nicely, in line with our economic model. And of course, it's contracted to boot. This facility, along with the Cactus II and Gray Oak pipelines, gives us much greater leverage to the growth opportunity in the Permian Basin. As shown here, we have lots of operating leverage at Ingleside, and there's ample room for cost expansions as well. I think, as we've mentioned, it's competitive in every dimension because it was purpose-fit designed. It's got a deep dock, 54 feet dredged, vessel capabilities that are better than others and quick distance to Bluewater, et cetera, et cetera. We're also actively exploring expansions into LPG and purity product export opportunities. And as mentioned earlier, this asset has a clear path to growth in a lower-carbon economy exports. As mentioned, we're also going to produce more solar power, then the facility consumes to make it net zero are really net minus. As mentioned, this is a -- the playbook that we're going to use for all of our growth projects going forward. And lastly, we're exploring the potential for this facility to participate in the long-term build-out of the Corpus Christi carbon hub, given its local geology and its proximity to large industrial emitters. I think it's been mentioned but I'll say it again, this tuck-in acquisition checks all the boxes and is a good example of how smaller asset acquisitions can prudently enhance the business. I should also mention the much smaller Cushing terminal acquisition we made last year from Blueknight, which is another good example in synergistic. Okay. The first priority in our low carbon strategy is to reduce emissions from our own business. We have specific pathways in LP to achieve renewable self-power of our pump stations that will play an important part in this objective. We have lots of land along the right of way. Matthew and I are collaborating, and our teams are working to make this happen. The second key plank of the strategy is to support the decarbonization ambitions of our customers and other large emitters. CCUS will be a big piece of the puzzle, and we believe we are well positioned to support the build-out. We are approaching this strategically and listening carefully to our customers. But for sure, we are going to bring something to the table given the transportation and storage capabilities. We've entered into 3 excellent partnerships in just 3 months, they are part of the strategy, one with industry leader Svante to help technically with the capture piece. And we have strong capabilities in the rest of the carbon value chain, carbon pipelines and storage. The U.S. tax credit and new U.S. infrastructure bill are positive in this regard and moving it forward. But as Al mentioned, we need similar policies in Canada. Lastly, given the scale and positioning of our system, we're looking at opportunities to repurpose some of our existing pipeline assets in service of these low-carbon opportunities. Think carbon dioxide, hydrogen and ammonia. We've been working closely with our renewables team and announced the first 2 phases of our Mainline self-powering or repowering. The first phase is focused on the Mainline just south of Superior. The second phase is focused a little bit upstream in Minnesota where we're looking to repower 3 more pump stations. Now we can't repower every station on this system. We need the right combination of utility greening and price signals, but there is clearly upwards of $0.5 billion of opportunity here investment-wise, which will lower our power costs and drive our emissions down. On CCUS, we've been very active over the past year as industry partnerships and project planning begins for the future build-out. We've formed a team actually in liquids to actively pursue this, primarily focused on our operating backyards in Alberta and Texas where each have significant emissions abatement potential. For example, in Alberta last week, we signed an MOU with Capital Power to partner on carbon capture storage initiatives in the Wabamun area, near Edmonton. This will be an important regional hub, and we've registered an expression of interest with the government of Alberta to be part of the process on awarding pore space next year. In Texas, beyond the Ingleside opportunity, we're engaged in discussions with a number of key emitters in the region. We see low-carbon infrastructure as an important piece of the liquid strategy and a future growth platform with upwards of $0.5 billion to be deployed through 2025 and ramping up materially from there. I think, clearly, we're still in the early innings of CCUS. So it's a good longer-term fit with the conventional opportunity set we have in front of us today. So that concludes my prepared remarks for today. I think the 3 key messages overall would be that, first, I believe, we'll find a good solution with customers in 2022 on Mainline tolling framework. We have 2 equally attractive paths here. Second, we have an annual $1 billion of efficient capital investment opportunity in front of us each year in service again of both customers and capital providers. And third, I'm confident that liquids can and will fulfill its role within Enbridge, its dual roles, growing free cash flow and providing low-carbon optionality. So again, I'm pretty excited about this role and liquids' long-term future. We have 2,100 LP employees that are highly skilled and engaged and passionate about our business. So thank you, and I'll now turn things over to Matthew Akman who leads our Strategy and Renewables business. Matthew?

Thanks, Colin. Good morning. it's great to see familiar faces in-person this morning. I'll be speaking to our renewable power business, but many of my comments in terms of the approach we take and how we create value will also apply to other forms of new low-carbon energy. You've heard a lot today about our strong pipeline and utility businesses. Renewable power is smaller than those, but it's growing in prominence, and it's on the move. We've expanded it quietly and built an attractive development backlog that you'll hear more about this morning. As you've heard, renewables, along with other low-carbon energy infrastructure, will play an increasingly important role in the Enbridge mix and strategy going forward. Active participation and leadership in growthy energy infrastructure at relatively low risk has always been our hallmark at Enbridge. No doubt, our lead over our midstream peers in renewable power as well as renewable gas, hydrogen and the like improve and support our business profile. But that's not our main driver. The bottom line as to why we're involved here is we feel we can generate a lot of value. In all these low-carbon investment activities, our lens at Enbridge is about how we can create value for shareholders and contribute to per share growth of the company. Our low-carbon infrastructure business will become significantly larger along the way. But again, value is the main driver, not size. We'll continue taking a relatively low-risk approach, avoiding big technology bets and sticking with contracted infrastructure assets with high-quality counterparties and double-digit investment returns. How we can succeed in the increasingly crowded field is a question that's probably on your minds. The answer boils down to our competitive advantages, our skills, resources, assets and capabilities. We've been in the business of developing and operating low-carbon infrastructure for a long time. We've got extensive renewable power industry experience, and our utility and pipeline assets are a logical platform for all new forms of low-carbon energy. Here are a few proof points to illustrate our competitive position and some highlights of what's new in our growth program. Today, we're announcing the sanctioning of 7 new renewable power projects, 6 of those are behind-the-meter solar self-power, bringing our total to 13 in operation, construction and development. The seventh one is a floating wind project off the coast of France. It has a long-term offtake contract and is the first of its kind globally to complete a proper project financing. There's a new development pipeline in onshore front-of-meter projects over 1 gigawatt I'll be speaking about. So we're pleased with how we've conducted -- constructed the commercial backing to minimize risk, which serves as a model for how Enbridge will pursue renewable and also all new energy. In terms of priorities, we'll focus on executing these projects as well as advancing our offshore footprint. Renewable power has become a very competitive business with many different participants and so will other low-carbon energy forms because capital is flooding into all of them. The renewable industry is maturing. A lot of the low-hanging fruit has already been picked. Supply chains can get backed up. Projects will become larger and more complex. Some are in very remote and challenging onshore and offshore locations. As the scale and complexity of renewable project increases, so do the challenges in permitting, construction and operations. But no matter these challenges, the world needs a lot more renewable power, and big opportunities will be there for those with the skills to navigate risks. We've proven at Enbridge we have what it takes when it comes to complex and challenging infrastructure situations. We're bringing all our expertise to the table in terms of permitting, stakeholder relations, lands, construction management, world-class health and safety, asset maintenance and integrity. On the commercial side, our own electricity load can anchor projects. We spend over $1 billion a year on electricity across our pipeline systems, and our shippers are now looking to us for green energy solutions. We've also got some prime renewable development lands, and I'll talk about how we're capitalizing on our position in a few minutes. First, a little more on our operations. The importance of operating capabilities is itself an increasingly valuable competitive advantage in the renewable business. Many of our competitors are private equity players that don't have operating capabilities at all. By operating our own assets, we avoid paying third-party fees, we control health and safety using best practices, and we achieve efficiency gains. We still have some assets that were acquired from developers with operating contracts in place. We're moving to self operations on most of these and are seeing significant improvement in our availability and cost metrics. Typically, we see efficiencies of 5% to 10% by operating ourselves. The renewable business is young, but as assets age, there will be more and more heavy maintenance and replacement programs. Think blade monitoring, intense asset integrity, the use of heavy equipment and cranes often in rugged terrain and remote areas, all these activities require sophisticated training, programs and practices, which we at Enbridge have honed for decades. The proof is really in the pudding. Our capabilities were on full display earlier this year during the Texas winter storm. We've got 3 wind farms down there, and our teams worked effectively to ensure our assets were among the first back online. Time was money after Storm Uri hit. And we avoided the big impacts some others experienced in that challenging situation. Now on to our growing construction and development programs. We have several large offshore wind projects under construction today. This slide illustrates some of the visible offshore growth that will drive increased renewable EBITDA over the next few years for us. We've got 1.5 gigawatts in construction in France. Foundations are now being installed at Saint Nazaire. We're building massive 15-story tall, gravity-based foundations for Fécamp and producing cables at Calvados. All of these are tracking on time and budget, and they've got fixed price EPC contracts for extra belts and suspenders, protection against inflation. The offshore wind industry is accelerating every year as the realization has sunken that large-scale renewable projects will be critical to achieving the world's emission reduction targets. Installed offshore wind globally is now expected to reach 220 gigawatts by 2030 and then almost 400 gigawatts by 2040. Europe, which is our core market, will be a big chunk of that at about 40% of the global total. It's not always easy and we're facing 2 challenges in particular as we look to capitalize on this huge opportunity. One is that many of the markets have gone to market pricing, instead of long-term contracts backed by government, which places a lot of these, frankly, just outside our risk profile altogether. The other is that strong capital flows in the sector have compressed returns on investment. You've heard about that. Fortunately, we were relatively early into entry into this industry, and so we've got a good stable of secured projects and a strong platform to win new ones. Moving to offshore wind development and our program there. Our team in Europe is highly expert and well established now. We can still compete and win projects with attractive risk/return profiles, but we'll have to be nimble and we'll be selective. What I mean by that is several things. First, we'll participate earlier in the development process where returns are still attractive. Acquiring later development or operating projects just doesn't meet our hurdle rates. Second, we'll focus only on jurisdictions where we can still get a long-term offtake contract. And third, we're avoiding these highest-bidder-wins lease auctions and instead focusing on what are known as points-based competitions where our expertise and qualifications are the determining factor, not the size of the upfront check we're willing to write. We see solid select opportunities that meet these criteria, and they can be large. For example, we've participated in the recent 4 gigawatts, ScotWind process you see here on the map. And while it's going to be very competitive, we've got a compelling proposal. Our Dunkirk project in France has been awarded a contract already, and that one is progressing toward FID. We're also working on a major expansion of our Rampion project in the U.K., and the fact that we're already there gives us an edge over the competition. That one could be over 1 gigawatt. My point is, we'll compete hard, but we'll maintain our discipline, and so we know going in that we'll win some and we'll lose some. In the meantime, our visible pipeline of construction and development opportunities provides a clear runway for growth over the next 3 to 5 years. I mentioned earlier that we're early off the mark on a huge global floating offshore wind opportunity. Our first project is now well underway and slated to be online by 2023. In addition to reaching FID on this project, we've already prequalified with EDF on the first large-scale auction for floating wind in France at Brittany. Together with EDF, we're currently working on a 750-megawatt early-stage floating offshore wind development pipeline. Behind that, there's a 9-gigawatt European opportunity for floating, and we're optimistic we'll be able to participate on a highly profitable basis. Again, under long-term contracts. Moving back onshore from offshore, our behind-the-meter solar self-power program is gaining momentum, and we've proven out the concept and economics now. As mentioned, we've announced 6 new projects today, 3 on GTM and 3 on liquids pipelines. That brings us to a total of 3 in service and another 10 in construction. These projects have good investment returns. We'll reduce power costs across our system and improve the emission footprint of our pipelines. With over 1 gigawatt of potential here, there's much more growth available. And while we don't expect to replace all of our requirements, the opportunity set is large. We've identified $0.5 billion of investment over the next few years alone. And with all the potential, that opportunity should double by mid-decade. You've heard a fair bit about our offshore wind developments and self-power efforts in recent years, and those are ramping up nicely, as you can see. While building that portfolio, we've been working quietly on a North American onshore front-of-meter development portfolio that looks more promising every day. We're currently working on over 1 gigawatt of onshore front-of-meter renewable power projects at various stages. Only those with strong contractual underpinning and solid returns will be brought to an FID, final investment decision. Early signs are very encouraging, though, because we control tens of thousands of acres of prime renewable lands with transmission interconnection. We've got our own electricity load to anchor a lot of these, and we're seeing very strong third-party customer interest. A great example of that is at the Ingleside export terminal. We've got hundreds of acres there, and there's a 138 KV line running right through the site. The solar and wind resources down there are best-in-class. And we have some very large power customers right next door that are looking to reduce their own emissions. Another good example is our Plummer pump station where we own almost 1,000 acres of prime solar power lands. This is in Minnesota. That alone could be a 100-megawatt project. The project will take time, as all developments do, but we plan to have some chunky new assets in service mid-decade. So to wrap up, we have momentum in all 3 of our development areas: offshore wind including floating, behind-the-meter solar self-power and front-of-meter onshore projects. With the first of our large French offshore wind projects slated to come on later next year, we're looking forward to visible contracted cash flow growth from investments that will deliver excellent returns for decades to come. We're well positioned to keep that momentum up as our development and construction backlog of about 2.5 gigawatts now exceeds the size of our base business. We have enough in the hopper to deploy capital of about $1 billion a year to attractive renewable power growth. We'll always maintain our capital discipline, and we're positioned nicely to win and execute on accretive low-risk projects. As we bring more of these to later development stages and into operations, there will be more capital-recycling opportunities to further boost investment returns, if we choose to do so. Our renewables business is definitely on the move, gaining momentum. We're optimistic it will become a bigger part of the company and a significant growth driver for many years to come. Thank you very much. Now I'll pass it to Vern Yu, our Chief Financial Officer, to discuss our financial outlook.

Thanks, Matthew. Good morning, everyone. I'm very excited to be here this morning as our chief financial officer. It's really exciting because I think we're in really good shape financially. Our balance sheet is rapidly strengthening now that we have line throughput into service. And we benefited from strong operational and financial performance across all of our businesses. This balance sheet strength is really going to open up a lot of optionality for us next year and beyond. But before I get into that, let's take a minute and reflect on 2021. So the best news is that our systems have been full all year. This really reflects the demand-pull nature of our assets and the strength of the markets that we serve. We've placed $10 billion of new capital into service this year. This is well diversified across all of our businesses and drives significant EBITDA and cash flow growth going into 2022. Today, we announced another $1 billion of new projects, which brings us to $2 billion for the year. We've unveiled some new opportunities for growth across all of our businesses, some conventional, some low carbon, so that's a really good mix. This adds to our project backlog, which really supports our long-term DCF per share growth. So next, I'm going to move to our financial dashboard for 2022. Over the last couple of years, we've seen some really incredible swings in commodity prices. And despite these swings, we've delivered on all of our financial commitments. This really highlights the predictability and resiliency of our cash flows. Our diversified asset mix and our low-risk commercial framework provides us with really great stability. Our large-scale end market reach ensures that we have robust opportunities to grow our business, our secured capital program, along with toll escalators, and our continued focus on reducing costs really provides us with highly visible growth, 5% to 7% DCF CAGR through 2024. In 2022, we'll have about $6 billion of investment capacity to continue to grow the business, and a portion of that will be used to fund our secured capital program. We'll have this investment capacity after paying our dividend, which will be around $7 billion next year. So we have a strong balance sheet, coupled with strong free cash flow. This gives us a lot of optionality on how we deploy capital in the future to maximize shareholder value. We continue to drive ESG performance across our businesses. and to ensure that we hit the targets on ESG that we set out last year. The independent agencies that assess ESG rank as the leader. Okay. Let's move on to the balance sheet. There's no change in how we're thinking about the balance sheet. We're going to continue to run our business conservatively. We'll keep the balance sheet strong at the low end of our debt-to-EBITDA range and have our dividend payout be in the middle of the range next year. The cash flow from the $10 billion of assets we placed into service this year, along with the Moda acquisition, will drive debt-to-EBITDA to the bottom end of our range next year. We believe that this flexibility is very powerful. As we move from the lower end of the range to the middle of the range, this gives us an extra $2 billion of incremental capital that we can invest in high-value opportunities. We'll continue to be self-funded for all of our equity needs. And finally, I think it's really important to point out, we're not going to sacrifice our commercial model just for the sake of more growth. We think that this approach to the business makes us a leader in this sector and will really drive our long-term value creation. But generating value isn't just about the model. It's about how you surface and deploy capital to grow your cash flows. So on the next slide, I'm going to talk a little bit about our track record on this front. Since 2017, after the merger, we've taken a number of actions to strengthen the balance sheet while still growing our business. We've sold about $9 billion of assets, and these assets predominantly had some exposure to commodity prices. So we even reduced our risk profile while selling assets. Today, our direct exposure to commodities is very small, only about 2% of our cash flows. We've also recycled a bunch of capital into new growth projects, about $40 billion in total, and these projects are now contributing about $5 billion of incremental EBITDA. We selectively executed accretive tuck-in M&A where the new assets have been on strategy and have had their own embedded growth profile. And we've returned a significant amount of capital to shareholders through a stable and growing dividend. We continue to optimize our assets to ensure we're best positioned for both today and to grow in the future. So it's not just about capital deployment. It's also about how you run the business. So over the last 5 years or so, we've been really focused on taking costs out of the business. In fact, we've taken about $1.2 billion per year of costs out. We've done that by unlocking the synergies in the merger and by amalgamating our 2 utilities in Ontario. We focused on process efficiencies, how we can do more with less. We've invested in technologies. I think Al talked about this a little bit earlier. Our technology labs in Calgary and Houston are really focused on how we apply artificial intelligence, machine learning and other technologies to reduce our costs. Here's a good example. We've been really focused over the last year on how do we optimize the energy use at our pump stations and compressor stations. This has 2 real benefits. We lower our power usage, and along with that, we lower our emissions as well. We've enhanced our tax pools. And as a result, we've extended our tax cash horizon beyond the current planning period. So next, I'm going to talk about how we're going to deploy this financial capacity that we've built up. Our capital investment priorities haven't changed. Protecting the balance sheet remains our #1 focus. We'll stay in the lower half of our target debt-to-EBITDA range, and we believe this maximizes our flexibility going forward. We'll continue to return capital to shareholders through a sustainable and growing dividend, which remains core to our value proposition. And our approach to the dividend is unchanged. We'll grow the dividend up to the medium-term DCF per share growth rate. And for next year, we expect our payout ratio to move to the middle of the range. In addition, today, we announced a share buyback program for up to $1.5 billion of share repurchases next year, and that really provides us with incremental flexibility on how we return more capital back to our shareholders. I should say that share buybacks will need to compete with our organic growth and other capital allocation priorities. And all of our capital allocation options need to achieve solid returns along to continue to have a low-risk profile to go ahead. So next, we'll go on to 2022 and beyond. In 2022, we're going to generate about $11 billion of distributable cash flow, and we expect that to continue to grow over time. With today's announced dividend increase for 2022, we expect to return about 65% of that cash flow back to shareholders as a dividend or about $7 billion. After considering our incremental debt capacity, if we move from the bottom end of the range to, say, 4.7x, we'll have about $6 billion of investment capacity for the year. We'll prioritize about $4 billion of that for low-capital, high-return growth, such as the things that Bill and Cynthia have talked about in the gas business. Modernization and normal core utility growth. The next $2 billion of excess capital will go to our next best capital allocation alternative. And we have a few options here. Let's -- so let's go into a little bit more granularity next on how we do capital allocation. So if we start with what we call the core allocation bucket, we'll prioritize 0 growth -- 0 capital growth first. Really, it's the best kind. It uses no financing capacity, and we have lots of these opportunities embedded throughout our company. Then we'll invest in highly capital-efficient projects. These will generate robust returns and are in our primarily in liquids and gas transmission. This should total to about $1 billion per year, and we expect these projects to generate mid-teens returns. After that, we'll invest in the gas utility, which we think has up to $1.5 billion for customer adds and community expansions annually. Next is our modernization program in gas transmission, which is another $1 billion per year. So that's $3 billion to $4 billion of ratable growth in our core investment bucket. So in normal circumstances, that will leave us about $2 billion in the excess bucket. And this is how we're thinking about deploying it. We have 4 choices here: more longer lead time organic growth, low-carbon infrastructure investments, tuck-in M&A, potentially further deleveraging the balance sheet. All of these will need to compete with share buybacks going forward to move ahead. We'll look at the equity returns on each of these and the accretion, and only the best of these opportunities will go ahead. This excess investment capacity has the ability to drive further upside to our base plan, and that's how we get to our 5% to 7% growth outlook through 2024. So we have a great record of capital discipline, and that's really rooted in how we look at investments. Our size, our asset footprint and financial strength provide us with a lot of opportunities. We're not going to compromise the value proposition just for the sake of growth. Projects have to be on strategy, demonstrate executability, aligned with our low-risk commercial mode and meet our new ESG goals to make it through our screens. After that, each opportunity has to compete against other opportunities in the portfolio. From there, only the best projects will advance. Each project is given an individual project-specific hurdle rate that considers the unique risks that come with that project. We factor in premiums for capital cost risk, schedule risk, regulatory and permitting risk, factoring carbon pricing and many other ESG factors. Then we add a premium over that hurdle rate to ensure that we generate clear value over our cost of capital. So on average, our return expectations have increased over the last few years. And that's particularly true for greenfield projects where project execution is a big consideration. And as a result, our focus is now shifting to brownfield expansions and optimizations where capital efficiency can drive robust returns and in a much better line of sight to execution. The next slide talks about how we're going to -- what we're thinking about share repurchases. I think, as Al mentioned in his remarks, we're going to be really disciplined about this, just like we are with the rest of the business. Our priority is always to maximize the value of each dollar invested, and our allocation framework is designed to achieve this. So here's how we're thinking about buybacks with that context. They can generate attractive equity returns and support near-term growth in both EPS and DCF per share. So we think, on a long-term basis, our assets will drive strong cash flow growth. So investing more in ourselves is really a no-brainer. And finally, share buybacks are obviously very executable. But it's important to know that we have to balance that against the role of organic growth and how that can advance strategic priorities and generate new cash flow and finally enhance tax pools. It's important to note that we're not going to stretch our balance sheet just to buy back shares. Our balance sheet currently is still carrying the full cost of Line 3 replacement and the Moda acquisition. These assets will generate some strong cash flows next year and bring our leverage down over the year. We'll also look at the fundamental value of our shares as we evaluate share buybacks. But at current prices, obviously, we think our shares are undervalued. Ultimately, we still have a strong hopper of organic growth opportunities. So really, we think there's options here for both in our portfolio. Okay. I think now we're going to move to our outlook for 2022. Before I get into the numbers, I'll provide some of the assumptions that drive our plan. I think, as Colin mentioned, we've put in an allowance for lower tolls on the Mainline. But the big driver for 2022 is the $10 billion of capital that we put into service this year, along with the Moda acquisition. Our plan for 2022 includes $4.5 billion of secured capital deployment, so that leaves us for 2022 excess investment capacity of $1.5 billion. We plan to be at the low end of the range. And the next slide, I'll show you how does that translate into growth trajectory over the last few years. I think as we announced this morning, we expect EBITDA for 2022 to be between $15 billion and $15.6 billion for the year and DCF per share to be between $5.20 and $5.50. That represents a 7% CAGR over the last couple of years. Our dividend announcement fits squarely within our dividend guidance, and I'll walk you through some more of those details on the next slide. In liquids, we assume a full year cash flows from Line 3 and contributions from the Ingleside terminal. As I just mentioned, the Mainline includes a provision for tolls, but we do expect strong crude oil supply from Western Canada. So we're forecasting the Mainline to average around 2.95 million barrels per day for the year. Gas transmission benefits from new assets placed into the service, including the $1.5 billion expansion of the BC Pipeline. At the utility, we expect to add another 45,000 customers and to have normal weather. Power will be flat year-over-year with projects that are under construction now to start contributing in 2023. Energy service is expected to improve, but loses are still expected to continue next year. I should remind everybody that our Energy Services group is not a speculative trading show. This business historically has generated about $100 million per year by capitalizing on locational and quality basis spreads as well as contango in the market. Currently, we have some committed contracts where this basis is working against us, but we expect the business to return to profitability after 2022 and be along the lines of its historical results. Our FX hedging program will be incorporated in our Eliminations and Other segment. So moving on to EBITDA. We're going to have significant EBITDA growth, which will drive cash flow growth. Our maintenance capital on 2022 will be slightly higher driven by some of the work that was delayed from this year in the utility, which will move to the next year. Cash taxes are expected to continue to be around the run rate of about $500 million a year. Our commodity exposures will remain minimal, and about 95% of our exposure to the U.S. dollar on a DCF basis is hedged at about USD 1.28 per CAD 1. So some of the sensitivities we have, a $0.01 movement in FX will result in about $1 million per month movement as in a swing in EBITDA, less so on DCF, and a 25 basis point movement in interest rates would lead to about a $40 million change in interest expense for the year. Seasonally, we expect the trend to be as it was this year where winter months are stronger than summer months. And with capital coming into service next year, the second half will be stronger than the first half. So we continue to try to strengthen our business. We do this by progressing regulatory strategies to ensure we receive a fair return on the capital that we employ. We filed the Section 4 rate case on Texas Eastern to reflect the significant capital we've deployed in modernizing the system. And as Colin talked about, we're going to expeditiously engage with shippers on the Mainline. Settlement discussions, in fact, are underway on the Lakehead System regarding our cost of service filing that we made with the FERC earlier this year. And obviously, we've done that to ensure we're earning an appropriate return on the capital we've employed there. About 80% of the EBITDA has some inflation protection embedded in it, either through cost, contractual cost escalators or other regulatory levers. And we continue to be focused on driving efficiencies within our business. We've talked about deploying technology to lower cost in all areas, and we expect to continue to capture from these actions. In our planning period, we expect this to contribute about 1% per year of growth. Let's move on to the secured growth inventory. In total, from 2021 through 2024, we have $19 billion of secured capital, reflecting another year of modernization and utility capital. These are multiyear programs, and we've added the newly sanctioned projects we talked about earlier. The program is well diversified across all of our business and really demonstrates how all of our business contributes to our organic growth capital program. After considering capital that we placed into service this year, we're left with a $9 billion secured hopper, and we have a strong development pipeline behind us. This provides us with great confidence that more attractive opportunities are on their way. And importantly, this secured backlog supports our 5% to 7% growth outlook through 2024. Let's move to the funding plan. We expect about $4.5 billion of growth capital spending in 2022. That's well within our $6 billion of investment capacity for the year, which has already factored in maintenance capital expenditures and the payment of our dividend. The majority of our needs will be met through internally generated cash flows and the remaining debt requirements are very manageable. We've been a regular contact with the credit rating agencies, and they've seen the details of their plan. So I'm just going to wrap up now with a summary of our 3-year outlook. Our secured capital program, along with ongoing cost efficiencies, rate escalators, delivers our 3-year outlook of 5% to 7% DCF per share growth through 2024. Our balance sheet flexibility and excess capacity provides the opportunity to booster our growth -- bolster our growth to the top end of the range through further investments or share repurchases. So in summary, we're very excited about Enbridge's outlook. Our systems are full. Our balance sheet is in the best shape it's been in many, many years. Our financial metrics are really dialed in, and we have visible growth in front of us. We'll be disciplined on how we deploy that capital. So really, that's it for us, and we're going to turn it over to Jonathan for the Q&A.

Great. Okay. Thank you, Vern. I think I'll invite everybody to come up to the stage here and take your seats. So we've got about 30 minutes for Q&A here. Again, we'll have the mic in the middle of the room here for those that want to ask questions in person and then the same approach for the webcast, add your questions to the form, and I'll be reading those to the group here. It looks like we got the first question from Andrew Kuske. So go ahead.

Andrew Kuske, Crédit Suisse. I guess it's an intertwined question for Vern and also for Colin. And just when you think about the outlook for the mainline, whether you go cost of service or some new negotiated incentive mechanism. I mean how do you think about the dynamic from a financial planning perspective? And then just really getting some kind of new incentive mechanism or contracted iterative process out of the shippers. These cost of service, arguably, a lot of the things that you do for the shippers, you could peel back and not do on a batching basis. And what would that mean from capital outlook? Like that has a lot of layers into it because if you stop batching to a certain degree and had deliverability, you pulled back, you'd earn less, but you could put more steel on the ground just theoretically. So I guess I know it's a complicated intertwined question, but how do you really think about the dynamics in your businesses on the financial planning side and then just the operational side of the main line?

Colin, do you want to go first on the operational side?

Yes. Sure. It's a great question, Andrew. And it's one we'll be discussing with our customer base here, and we already have started it. I think most would agree that what we've done over the last 25 years has kind of worked for everyone, right? Amazing alignment. It's taken some time to get there for sure. But as you've heard me mentioned earlier today, we're at the pump, 3.1 million barrels per day through the pipe. That matters more than pretty much anything else in the conversation. And we're motivated to do that day to day, the culture of our company has, I think, migrated to that over this 25 years to have that day-to-day hustle, managing safety and risk and customer interest. So that's where we're at today. These elements will be central to the conversation. We haven't really heard industry look for through the hearing process or recently a change in that environment. So we're looking forward to that conversation.

Well, I think, as Colin mentioned, I think having alignment with our customers is critical and some type of incentive tolling framework probably makes the most sense for everyone. But if we do move to cost of service, I think the focus of the company will change a little bit or the business unit, where we'll be obviously more focused on putting more capital in that business to grow rate base. But I think when we've looked at this financially, Andrew, we don't think the delta between being an incentive or cost of service is going to have a material impact on how we look at the company as a whole. We have obviously offsets in our other businesses that would mitigate any modest -- very modest decline in cash flows.

Okay. Great. And as a follow-up, it's a different kind of alignment question and maybe it's more directed at Al. How do you foster alignment on things like carbon capture and storage, which really spans a lot of the different business units that you have?

Well, I think it was alluded to a couple of times here, Andrew, and it probably comes down mostly to the capital allocation model. We know that the fundamentals support the move to lower carbon. The good news is that we've got 2 angles of attack here. We know that conventional runway is there based on the fundamentals and every one of the businesses, call it, in transmission, distribution and liquids has that opportunity set. So we're going to capitalize on that. We're going to keep doing that, and we see that probably for the next 10 or 20 years minimum. So that's sort of the conventional runway. And as you heard, I think, quite rightly, they all are pursuing opportunities to grow low carbon. So it's really this 2-angle approach to how we grow the business and transition it, frankly, over time to lower carbon economy. But it still comes down to the funnel. And it still comes down to making sure that each project that we bring forward, as you saw with Vern's slide goes through that process of determining what's the right hurdle rate for that project? What's the right risk premium? And then what's the margin that we need above that to make sure that we're really generating value in excess of the cost of capital? So I think that's the framework that we use going forward. But make -- there's no doubt about the fact that we're going to be moving more to low-carbon investments. And the good news is we've got a very good opportunity set to do that. So it's -- I won't say it's a jump ball between the businesses. But in a way, the framework allows us to make sure that we're putting capital to the best opportunities.

Great. Maybe I'll jump in with a question from the webcast here, and then we'll go to them. This is from Matt Taylor at Tudor, Pickering. Vern, I think, this is probably for you. On leverage, you're at the low end of the range already. On one of your slides, you indicated that your $2 billion of debt capacity or so you had $2 billion of debt capacity. Can you address why it isn't a higher priority in terms of how you kind of sequenced the slide later on around capital allocation and why it wasn't in the best options category.

Well, I think -- we think there's lots of attractive opportunities coming from more organic growth, potentially tuck-in M&A, obviously, low-carbon investments and share buybacks. We think, overall, if we find good opportunities there, that should drive higher equity returns for shareholders and then paying down more debt. Obviously, as we go through our allocation process, if we don't find attractive opportunities, the default will be just to pay down more debt.

Could I make one more comment? So it kind of goes back to the slide that Vern put up in the end in terms of the equity IRRs that are driven out by all of these options. And so there's going to be a trade-off in some cases. But generally, we want to make sure that we're heading to increase the overall return of the business. And I think that right-hand category that it had between acquisitions, potential asset acquisitions, organic growth, share buybacks, they're all in the same category. They all generate very strong returns. So it really will be a TBD at that point in time. Now leverage, if you look at that same chart, bringing it down further below the bottom of the range, that will have a consequence in terms of returns and that, obviously, you're not generating a big return by paying back debt right now. But it will be an option for flexibility, if the timing doesn't work out such that we can't redeploy the capital to the other means for whatever reason.

Thank you. Ben?

Thanks. Great content and thanks for hosting us physically. It's great to see a lot of familiar faces. A couple of questions on Alberta CCS. You use your $1 billion benchmark, huge opportunity for you and peers. So my question is, how do you see the competitive landscape shaking out next few years? Is it mostly incumbents that take a growing market share? You can be selective with how you deploy capital? Or do you think this will get quite heated private equity stepping in international players that maybe being first mover could be advantaged for you and peers?

Yes. I can take that, Ben, thanks for your comments. So we're certainly looking at CCS opportunity is in Alberta, but just want to make sure everybody recognize we're looking at it continentally, right? The immediate kind of opportunity in Canada being talked about is Alberta, but the appetite is continental. In Alberta, I think we see the Canadian incumbents competing here. It's probably a mix of cost of capital and capabilities, right? We're talking about a business model here that is targeted at cost avoidance. So inherently, we're looking at solutions that are going to be cost effective, including financing, design, to pair with the capabilities, right? The last point I'll make here, I think, that you're going to see some partnerships form, right? This is new ground, new technologies, where I think you're going to see technology companies pair with infrastructure companies, maybe even with emitters or indigenous groups. I mean I think we've seen the formula play out in other parts of the world, and I think it can work here, too.

And maybe a follow-up question to that. You're announcing Capital Power. They did mention last week Investor Day that they could look at a partner for the carbon capture facility. So is that something you could be interested in, maybe not specifically that particular project, but just the value chain? Would you move more upstream and invest in the more the CCS facility itself?

The answer to that is yes, under the right commercial model. All of this is prefaced by that. But the whole value chain could be in scope here.

Thanks, Ben. Maybe before we go to Linda, I'll take another one from the webcast. This is from Praneeth Satish at Wells Fargo. And Cynthia, I think this one is for you. How has feedback been so far on the hydrogen blending pilot, both from customers and regulators? And where do you see the blend rate going over time?

Okay. So for the pilot that we have ongoing right now with the 2% blend, we did a lot of work to make sure there would be no customer impacts. So right now, we're continuing to test that out and make sure that our customers are well served by that blend. What we see over time is gathering the information and trying to see where it makes sense to do so in our system to increase the renewable content. So of course, renewable natural gas is easy. Hydrogen, we have to make sure we can accommodate that within our system, I'd mention the Gassafair Gatineau project which is doing studies up to a 15% blend. So it's going to be specific to the locations. And as I mentioned, total renewable content, we want to have that focus of 5% of our total gas for GDS by 2030. So lots of opportunity and lots of exciting things, but we need to make sure we do the hard work and protect our customers.

Great. Thank you. Linda, over to you.

Thanks, Jon. This is probably a question also for Cynthia and maybe Bill, maybe both or anyone. Looking forward to an ongoing to a discussion on what might be possible in terms of the future of natural gas. There's obviously technical and economic constraints to the amount of hydrogen and renewable natural gas that can be blended. But what about responsible natural gas? And what sort of role might that play? We've seen some demand from European LNG consumption. Might it remain niche? Might it be expanded to also be a more significant component of distribution utility mix in North America? And what role might Enbridge play in that?

Bill, do you want to start?

Sure. I'll start. I think, for us, responsible natural gas. I think it means it's going to mean something good in the future. So Linda, when you start measuring any type of methane emissions or any type of combustion emissions from source to use and you've got the focus on that, I just feel as though buyers are going to start being held accountable for what they're buying. And that represents an opportunity both for us as pipeline companies. And so we're part of this one future reporting coalition. And it goes right from production through gathering and processing through transmission, distribution and end use. And the more you can audit that and account for that. And then we're held responsible for that. And we're doing as much as anybody on this front, then I think it's an opportunity for us, especially as you mention for LNG exporters because it feels like globally, it's taking hold earlier than perhaps it is domestically.

Yes. I would just add, building on what Bill said that there is that opportunity even at our Dawn storage and trading hub to facilitate the development of that market. So it is the right thing to do, and we're excited that we'll get to be a part of it.

If I can have a follow-up question as it relates to aspirations around what might be possible in the future. And this is a question maybe for Matthew. I was interested to hear you didn't really talk substantially about battery storage or pumped hydro. Have you put thought to coupling your renewable power with some form of more ratable storage or something as a value proposition to customers, to yourselves internally? And what might be possible there? Or have you already kind of precluded participating in that significantly?

Yes. Thanks, Linda. You're right on the money there. So stay tuned, but we are looking at battery solutions, especially at some of the behind-the-meter solar cell power because if you think about it, what we really require at our pump stations or compressors is very stable power. And so right now, with those behind-the-meter projects, we're still pulling off the grid periodically. So we're looking at battery and those as a starting point in order to smooth out the supply that we get from those. And I think the returns on those projects could then -- I mean they can just be further enhanced with that. And they also provide additional potential capital investment opportunities. We're not spending a lot of time on kind of utility scale battery right now. We're focused more on our actual renewable generation projects. But over time, that will probably be a natural part of the evolution.

Okay. On a related note, I'll ask another one from the webcast. This comes from Tyler Reardon at Peters & Co. Al, I think this one is probably for you.

Okay.

With renewables being about 4% of EBITDA in 2022, how do you see this changing over, say, the next 5 years? And then moving to hydrogen, RNG and CCUS, do you have targets there and is acquisition part of that?

Yes, that's a great question, Tyler. So you mentioned 4% and it's a small number today. I think you'll notice from the slide that we put up. We see that one migrating, in other words, becoming a bigger part of the pie as we see the gas businesses. Again, not because the liquids necessarily doesn't grow, but because those other 2 have more opportunities. We are very hesitant to put a target on it other than a directional target, simply because the second you do that, you start feeling like you need to invest in order to reach an arbitrary target. So our principle is and I think, Vern outlined this very well in terms of the discipline is let's make sure these projects work economically. We know they do strategically and long term, but we're going to do that at a pace that makes sense while making sure the returns are there. So not a target per se, but certainly moving in a bigger portion of that pie that you saw there, Tyler.

Great. Thanks, Al. Bill, I think the next one here is from you -- or for you. It's from Michael Lapides at Goldman Sachs. The first major LNG project in Canada, Shell Canada. What has that meant for your gas system and potential expansions or at least volumes? And how do you see further growth in that system and the ability to compete with Coastal GasLink?

Well, so I would say that anything that happens in the West Coast really benefits our BC Pipeline system. And the first project going off, we put on a project called Silverstar not too long ago, that really facilitates gas moving into LNG Canada from our BC system. And that's a great start. We feel as though the BC Pipeline, as I mentioned, full today and full -- basically a contract -- fully contracted for basically by utilities in the South. So that low is not going anywhere. So anything that happens within proximity to the coast is going to need some fairly significant expansion. And we're seeing that with early projects that we might see in wood fiber with Squamish, even a small of potential offtake like 300 a day facilitates a $2 billion expansion of that system. And that's from T-North down to T-South. So regardless of which of these pipelines end up happening, the BC Pipeline stands to benefit. And that's our wheelhouse.

Just a quick comment, Bill, to add to what you said. The wood fiber project, I think, is emblematic though, of what's happening on the West Coast. Smaller project, modulized and very good participation from First Nations. That's a very key part of this. And it will be very cost effective. So I think we're going to start seeing potentially more opportunities here now that the LNG market is moving forward in a much quicker pace. And that project is a good example of how things could quicken up.

Great. Thank you. I encourage those in the room to queue up at the mic if you've got questions. Rob?

First off, you talked about the risk premium that you're attaching to the base return. Can you just quantify what some of the bigger drivers, bigger numbers? You talked about greenfield being one of them. So how much of a premium would be there. And then as you think about the different business segments, are there greater premiums attached to, say, the liquid side of things? Or put differently, either a lesser premium or a bigger discount for green energy or lower carbon initiatives?

Well, I'll take the first shot, and then I'm sure Vern will have something to say. I -- really, this is going to get down to individual projects. And I don't really see any discrimination between any of the businesses that we have up here. And the reason is the criteria are Vern mentioned permitting and regulatory. The schedule in any project these days is something that we really have to nail down. And those can expand as we've seen. Capital cost management and how much of that risk can be borne by contractors versus retaining it ourselves or customers. Those are just some of the examples of the risk that we have to make sure we're managing and quantifying in the hurdle rate. I don't know if we can get too specific about how much of an adder it is, it really depends on the situation, depending on the degree of execution risk we have in the project. So I think that's the general perspective. But if you have anything else, Vern.

Well, I think, Robert, we go through project by project and individually model, like how much could capital cost move on a particular project, how difficult the permits are going to be in a certain jurisdiction. That gives us a real sense of the variability of cash flows that we might see and the variability of returns. So I think that's how we drive our process. As Al said, it's going to be very individually explicit. So an example would be there's going to be great variability between liquids projects. So if you see something that's getting done in the Midwest, it's going to look very different than a project being done in Texas.

I guess, maybe without getting into a specific name of a project, if you think about something that was brought forward in the past year. What was the biggest premium that was attached to the base return, the basis points or hundreds of basis points?

Well, it's hundreds of basis points on certain projects.

Okay. And then the last question, if you think about the funnel that you've got, again, I don't know whether it's the last year or so, what percentage of projects are not making it through the funnel? And within the business units, is there any kind of business unit that has been more successful in getting the projects through? I guess the other way of looking at it, had more projects projected in the funnel?

I think we're equal opportunity rejectors of projects across all our businesses. So I think all of the business unit leaders up here will have war stories about projects that didn't make it through that they felt very strongly about. But I think it's important as a management team that we screen out projects that have just too much risk for us. And we've seen, by retaining, not going after every opportunity that left us in good shape this year where we did see a great opportunity like Ingleside show up, and we have the financial capacity to go ahead and do it. So I think that discipline has really served us well in 2021.

Great. Thanks. I'll take another one from the webcast here. Matthew, I think this one is for you. Given the influx of cheap capital into the renewable space, can you speak about the potential to partner with financial players here and the ability to leverage our expertise?

Yes, sure. That's something we've been quite successful at so far with our partner, CPPIB. When they came into our projects, they paid promotes to come into those. And that's a model that we can actually use going forward. As I said, in particular, most of the private equity players don't have the expertise that we do in development, construction and operations. And that's got tremendous value these days in the business. So we'll look at that as a model going forward. Obviously, you also have to look at the right timing to do that. And where do you maximize that promote and then maximize your return. But certainly, as I mentioned in my presentation, we'll be looking at potential recycling of capital or partners over time in order to continue to maintain very strong returns in the renewables business.

Great. Thanks, Matthew.

Yes. Robert Hope, Scotiabank. I was just hoping you could add a little bit of color on conceptually how you're thinking about a mainline cost of service filing. You have the Line 3 with the approved $0.935 surcharge there. So would the understanding then be that you kind of hive off Line 3, and then the focus would be on the rest of the mainline, so you earn a strong return on Line 3 and then worry about cost of service for the rest of it?

Yes, Rob, it's Colin. I can take that. I think you're right on it, and that's why we set out the visual of that toll stack. So Line 3 survives. It's toll sensitive in a good way and it survives for 15 years. So if we were in the cost of service filing or contested hearing, we would be focusing on that tranche in this slide and arguing for the typical appropriate risk-adjusted return there.

All right. And then the follow-up question would be the appropriate risk-adjusted return there. You have TC Energy with relatively low returns on their cost of service system there. However, if you take a look south of the border, you're in kind of like the low teens in terms of the cost of service there. So -- when you look at the world changing, what do you view to be kind of an appropriate low-risk return on a liquid system?

Yes. I mean I think you could reference our recent filings. We would revisit those potentially. The Lakehead FERC ROE that's, I think, was negotiated within the last year with industry was 13%. It's probably a good place to start. It's basically same asset just in a different state. So that's where our mind has been on rate of return, and I think there's good arguments given the risks in the industry going forward that should be an appropriate risk-adjusted return there.

Okay. Thanks, Rob. Colin, maybe another one for you here from Matt Taylor, Tudor, Pickering. How are you thinking about the additional mainline system expansions while the regulatory process is ongoing?

Yes. Thanks, Matt. So the -- The expansions that we have on tap here are needed irrespective of the commercial frameworks that we're negotiating. I think we've made all of our commercial frameworks adaptable, if you like, to these over time, and I expect this one would as well. I think the principle is basically that the egress should exceed supply, not be equal to it or below it, which has been the case for 2 decades and a number of industry players, I think, carry that same view here. So we'll be advancing those in parallel, Matt.

Great. Thanks, Colin. Bill, this one is probably for you. Praneeth Satish at Wells Fargo. How do you balance the huge growth opportunity from planned coal retirements along the gas system with the relatively hostile environment for permitting? And what can the industry do to make that more streamlined?

Wow. Great question with probably not a great answer. First of all, I think the huge opportunity that we have, fortunately, is right along our footprint. So the more you can minimize greenfield and improve your current system or systems, the better off you are. And when you look at where these opportunities are for us, and I highlighted the opportunity off of East Tennessee with TVA, but really all through the central part of our system, whether it's Texas Eastern and East Tennessee or down into the Southeast. We've got or even in the Midwest, we've got a lot of plans that are in proximity and repowering near those areas is logical, right, for gas -- coal to gas. So I'd say that's the good part. The challenge, though, is that if you do need a material greenfield, the permitting process is very difficult. I'm not sure I have any great solutions to how to make things easier, how to convince everyone that we should be building larger greenfield projects.

Well, I do think though that, Bill, you'd probably agree over the last, what, 6 months, I think the message is getting through around reliability.

No doubt about it.

And obviously, you've seen impacts on price. So now that doesn't work all that perfectly yet, but certainly, over time, maybe that message gets through louder.

Go ahead, Alex.

Great. One thing that has been interesting is seeing the capabilities of export on the Gulf Coast between EHOT, SPOT and now Ingleside as well. This may be a little bit further out on the forecast period. But to the extent that those facilities are all built out and expanded as you like, what does that mean maybe for more upstream infrastructure? Are there any other further needs that you might require on the pipeline side of things, either Gray Oak or Seaway or whatnot?

Yes. Thanks, Alex. Well, I like how you're thinking about this, very bullish. We are, too. So we do think it's an [ and ] outcome here, especially given the fundamentals and global thirst for this. So we think that's a pretty likely outlook actually. The time line will depend. But yes, EHOT is right in the center of that. There's a good chance we'll pair that offering with some upstream capacity from Chicago and create that hub. And there's lots of plumbing down there already that connects all this. But what we're missing right now is kind of a Canadian heavy hub for all the reasons that those normally make sense, connectivity, liquidity, optionality and a little bit greater bargaining power for the producers moving it down there. So that's how we're thinking about it right now is kind of an [ and ] strategy. It's much like Bill's LNG strategy, really, the number of options to tidewater.

Great. And then on the renewable side, floating offshore wind still seems relatively nascent in terms of technology right now. How has the development gone so far with the, I guess, the Vermont site, is it going as expected? Any twist or turns that we'd be aware of?

Yes. I think it's going well. Thanks for the question. It is new technology. But in a way, what we're doing is we're levering off of very established technology because a lot of this stuff comes from the offshore oil and gas business that was in existence and the floating platform. So this particular one uses what's called the tension leg platform, which is actually an established technology in oil and gas. It's basically 3 cables that are anchored to the seafloor. And there's 3 8-megawatt turbines. The turbines are Siemens and those turbines are established in the marketplace today. So I mean it's going real well. We're not done yet, obviously. But one of the things that went particularly well is actually the project financing. And it just shows you how much confidence the financial community has in these types of things. So I mean we saw terms on those that are -- that look a lot like a traditional contracted wind farm in terms of the types of fees and rates that are embedded in it. So knock on wood, it's still a little bit early, but there's a lot of established technology there. A lot behind it and very strong financial backing.

And if I could ask just one quick guidance question. Just on the $300 million of elimination is another. Is that really driven by like FX hedges and that sort of thing for 2022? Are there any things to call out, just to keep in our mind.

Well, probably the biggest thing is the FX.

Great. Thank you. And I think we'll just do one last question, and then we'll wrap up. This one is from Patrick Kenny at National Bank and Colin, I think it's for you. With the mainline moving to cost of service protect shareholders from Line 5 in terms of the risk in Michigan as well as provide recovery for the tunnel. And then maybe you can also talk about how the incentive tolling arrangement could also provide protection.

Yes, it's a great question, Pat, and I'm sure some of you painfully read through or participated in some of our hearings where all of this kind of evidence was put forward and we, as a basis for the toll that we had proposed, we had included allowances for a number of these capital projects, the tunnel being, I think, one that Pat's asking about. So I think in the natural pathway here, we're going to include or provide allowances for some of these capital projects and modernizations in that envelope, so to speak. Of course, they would also be apparent and probably more explicitly visible in the cost of service filing. But either way, I think it's a good observation, Pat, that we're going to include that, that CapEx and try to find that right trade-off between risk and reward to benefit both customers and shareholders. Yes.

Okay. Well, great. That concludes our Q&A and thanks, everyone, for joining me up here. Just a reminder to those of you in the room here, we do have a lunch planned afterwards. So we're looking forward to networking with as many of you as we can. And now I'll hand it back to Al, and the rest of us can step down.

Okay. Well, I guess it's appropriate to return to where we started. We think we offer a great value proposition and a very resilient and proven business model. The fundamentals and our unparalleled competitive position drive longevity of cash flow, and I know that's on everybody's mind. Our leading ESG capability, though, means we can provide a differentiated service to customer. Our strong balance sheet, as Vern outlined, and growing free cash flow allow us to capitalize on attractive opportunities. Again, a good runway to grow our conventional business and those assets provide a low-carbon opportunity set that's second to none in our view. The capital allocation framework and track record of recycling demonstrate our commitment to servicing value. And the combination of all of that should drive strong TSR for our shareholders. Finally, I just want to thank everybody for being here today. It's great to be in front of you as I said earlier. And hopefully, the excitement and exuberance we feel about the Enbridge story has come through. I think if you listen on to each one of our business leaders, they are certainly excited and keen to move forward. Yes, this is a challenging industry these days, but we've got great assets and great people and a very long runway to grow going forward. So I thank everybody for being here today, and we welcome you to stay for lunch. Thank you.