Welcome to the Enbridge Inc. Fourth Quarter 2021 Financial Results Conference Call. My name is Amitris, and I will be your operator for today's call. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session for the investment community. During the question-and-answer session, if you have a question, please press star one on your touch-tone phone. Please note that this conference is being recorded. I will now turn the call over to Jonathan Morgan, Vice President, Investor Relations. Jonathan, you may begin.
Thank you, Amitris. Good morning, and welcome to the Enbridge Inc. Fourth Quarter 2021 earnings call. Joining me this morning are Al Monaco, President and Chief Executive Officer, Vern Yu, Executive Vice President, Corporate Development and Chief Financial Officer, Colin Gruending, Executive Vice President, Liquids Pipelines, Bill Yardley, Executive Vice President, Gas Transmission and Midstream, Cynthia Hansen, Executive Vice President, Gas Distribution and Storage, and Matthew Akman, Senior Vice President, Strategy, Power and New Energy Technologies. As per usual, this call will be webcast, and I encourage those listening on the phone to follow along on the supporting slides. We will try to keep the call to roughly one hour, and in order to answer as many questions as possible, we'll be limiting questions to one plus a follow-up as necessary. We'll be prioritizing questions from the investment community.
If you are a member of the media, please direct your inquiries to our communications team, who will be happy to respond. As always, our investor relations team will be available following the call for any follow-ups. On slide two, I'll remind you that we will be referring to forward-looking information on today's call. By its nature, this information contains forecast assumptions and expectations about future outcomes, which are subject to the risks and uncertainties outlined here and discussed more fully in our public disclosure filings. We'll also be referring to the non-GAAP measures summarized below. With that, I'll turn it over to Al Monaco.
Thanks, Jonathan. Hi, everyone. Just as we begin here, the graphic is really just a reminder of how we kicked off Enbridge Day in December with the theme of how Enbridge is a bridge to a cleaner energy future. More on that later. I'm gonna begin with a 2021 recap, our current perspective on the energy markets, followed by our business update and ESG performance, and then Vern will take you through the financial results and outlook. First, though, the closeout of 2021 represents five years since the Spectra Energy acquisition. That deal was obviously transformational for us. It gave us a premier natural gas transmission business and another large gas utility franchise. We're driving a lot of growth and synergies in that business.
We've expanded at the same time the Liquids Pipelines business and acquired the number one crude oil export facility in North America. We built our offshore wind business in Europe, and we have a fulsome low-carbon business. We honed our pipeline utility model by selling assets that didn't fit at great value, by the way, simplified our structure and our financial position has never been stronger. The business is in an excellent position, and we're excited about the future. As you saw this morning, we had another solid quarter, which closes out what's been a catalyst year in that five year journey I was just talking about. We delivered record safety and operating performance. Our systems ran full, which drove DCF per share to the top end of the guidance of $4.96, and that included a further $100 million in cost savings.
We put $14 billion of capital into service, that includes Moda, secured another $2 billion of growth and sold another $1.2 billion in non-core assets at good value. We made big headway on our crude oil and LNG export strategy and low carbon. With Line 3 in service, we'll see record Mainline throughput and strong 2022 EBITDA growth. Now, this couldn't have come at a better time for producers as 400,000 barrels of new egress and improved netbacks is generating tremendous value, particularly at these prices, and it goes to the value of the franchise. Gas transmission utilization was strong as well. Texas Eastern saw 16 of its top 25 peak days over the past decade. We did have warmer weather at utility, but we more than made up for that. Renewables came in well, resource and EBITDA-wise.
This all translated into strong cash flow and dividend growth, which continued with the 27th consecutive increase this year. We're free cash flow positive this year with visible organic growth across the businesses. Now on to energy markets. Just cutting to the chase on this, we're in the middle of an energy crisis. The economic recovery is driving strong global energy demand. Normally, we see a supply response, but not this time, given the significant under-investment in both conventional and renewables. Not surprisingly, that brings energy shortages, higher fuel costs, and of course, inflation, as you're seeing, which challenges competitiveness and economic growth. One example alone, U.S. Northeast electricity prices last month reached over $300 a megawatt hour several times, and that's the same case for heating bills in that area. That's all, of course, due to lack of gas infrastructure.
What we're witnessing today highlights the importance of reliable, affordable energy in our lives. The reality is that North American conventional supply will play a large role in years ahead with long live reserves, low breakevens, and leading ESG performance. Those North American advantages and coastal infrastructure will result in higher exports, which is what's behind our crude and LNG export strategy. Before the crisis, our view was that conventional energy would grow at least through 2035, and what's happening today just reinforces that view. While energy fundamentals are constructive, we'll be very disciplined in deploying free cash and will gradually increase the proportion of low carbon investments. We've got a solid inventory of both conventional and low carbon opportunities totaling about $6 billion per year. That actually aligns with our free cash flow generating capability after dividends and maintenance capital, including debt capacity.
Of the CAD 6 billion in investable capacity, we'll prioritize the CAD 3 billion-CAD 4 billion annually to ratable utility-like projects and low capital intensity growth. We'll put excess capacity to the next best option. More organic growth, potentially midstream-like asset deals, although those are few and far between, and share buybacks. On the conventional side, we'll expand and modernize gas systems, which will displace coal and support renewables growth. We'll continue to build out our LNG and export positions and invest in the gas utility. We'll also pursue capital-efficient Liquids Pipelines optimizations. The nice thing is that these businesses also come with embedded low carbon opportunities, namely RNG, hydrogen, and CCUS infrastructure. Our renewables backlog gives us high visibility to growth as well. Moving to the conventional business update, the utility continues to have 45,000 customers annually of growth, and we're connecting 27 new communities.
We expect to add roughly CAD 1 billion of rate base this year. In Gas Transmission, as you saw, we sanctioned another two projects totaling CAD 700 million. Phase two of our modernization program, which improves the reliability and reduces emissions, and the next phase of our Appalachia to Market, which will add much-needed capacity in the Northeast. In that business on rates, we're now in settlement discussions with Texas Eastern Shippers. In Liquids with Line 3 now fully in the ground, our capacity is roughly 3.1 million barrels per day, and we're running pretty much full. We're looking good on liquids volumes. The priority now is to add more downstream egress to the Gulf on Flanagan Seaway path. These are highly capital-efficient expansions and come with attractive returns. Now on that note, here's how we see the Mainline tolling process unfolding.
As you know, there's a couple of options, either another CTS-like incentive tolling arrangement or cost of service. We're in the consultation and information sharing phase here, and the goal is to land on which option works best for our shippers and makes sense for us. The incentive tolling model has worked very well in the past and aligns us with our shippers, and that's because it provides the toll certainty that they want and need to run their business. It keeps costs in check and incents us to add capacity. Now in that framework, we take on operating capital and FX risk, and of course, volumes move up and down. If we manage all of that well, we can earn a commensurate return above the cost of service return.
To illustrate the win-win here, we added roughly 1 million barrels per day of new low-cost capacity during the last CTS term. That's brought a lot of value to shippers when it's been challenging to add any new egress out of Western Canada. While the value equation has worked well in the past for both parties, we're equally comfortable under a cost of service arrangement going forward because it minimizes the risks I mentioned, and we'd earn a good risk-adjusted return. As we've seen, shipper consensus is tough to achieve, so we are preparing a cost of service application right now. We don't want to presuppose the timing, but we're looking to land on a path by this summer, hopefully, and then file either a settlement agreement or a cost of service after that.
Either way, we don't anticipate a material change in the context of Enbridge's overall EBITDA. Sticking with liquids, we've now integrated, sorry, our Ingleside export terminal and going after expansions. Storage capacity is fully contracted out for term. We're talking to customers right now about adding another 2 million barrels of capacity, which we're targeting to sanction later this year. On the export side of the facility, we're 60% contracted on the 1.6 million barrels per day of capacity. So the goal, of course, is to term that out. We're also seeing early interest in developing LNG, hydrogen, and ammonia exports, and that's driven by global petrochemical feedstock demand. Under any scenario that we can see, the Permian's low cost, abundant supply of natural gas and NGLs are going to be key to meeting that pet chem demand.
We're also co-locating up to 60 MW of solar power at Ingleside. The graphic here you see shows this will more than achieve net zero with the excess contributing to Scope 3 reductions. Essentially, net negative at Ingleside. It's a great example actually of how we look at all new investment opportunities. Outside of Corpus Christi, we're continuing to develop the Houston oil and spot terminals, and that's the catalyst for expanding upstream heavy access to the Gulf and exports through our systems. We also have great momentum on LNG exports. With no end in sight to high LNG prices after a little bit of a pause there's strong buyer interest in contracting up U.S. Gulf capacity. We just brought on our Cameron Extension project connecting to the Calcasieu Pass facility, our fourth transport deal.
We've got several projects in development as well, and we just locked up the PA with Texas LNG to expand Valley Crossing. We're now seeing interest in Western Canada LNG, plus local market demand is picking up, so that should drive expansion on our West Coast system. In fact, we're now working on a CAD 2.5 billion expansion of T-South, and we're targeting an open season hopefully by mid-year. Now, the demand pull for that one is Woodfibre LNG, which we understand is progressing well to FID. All in, we've got CAD 6 billion of LNG opportunity in the hopper, which bodes well for post-2024 growth. So you can see here that our conventional businesses have a long growth runway. We know that energy transition is gaining momentum. As you can see with the investment outlook here, capital is flowing.
We see the transition as a great opportunity for us to extend our growth because the fact is our transportation and storage assets are essential to unlocking low carbon energy for the economy, and our franchises feed the best North American markets. The transition is gonna take time, as we all know, so we're focused on investing capital where there's a clear path now to execution and with attractive returns. To assess the pace of transition, we look at a number of signposts. We put some of them down here on the slide. The conditions are actually already right for renewables, and we've been building that business for decades. We're starting to see the policy framework and investment flow for hydrogen and CCUS, but they're not where they need to be to accelerate and scale investment.
Global carbon markets are starting to form, but that'll take time to mature as well. In our view, the importance of regulatory and permitting clarity is underestimated. We need more certainty and shorter timeline to permit projects. Through 2025, we see about $4 billion of a potential investment, including offshore wind and construction, and we expect that to ramp up in the second half of the decade as RNG and CCUS and H2 and hydrogen accelerates. Let's run through the key low-carbon areas. We've got 14 renewables projects in construction right now, including solar self-power in North America and offshore wind in France, totaling 1.5 GW. On offshore, over half of the 80 foundations are now in at Saint-Nazaire, and it's on schedule for late this year. Fécamp and Calvados are tracking well to 2023 and 2024 ISDs.
We're well underway on our first floating offshore pilot at Provence Grand Large, and we see upwards of 750 MW of floating potential in France with EDF. As you can see, we're busy with our current backlog, so we don't need to chase new projects during this period of frothiness. In North America, we're making great progress on solar self-power, three projects in service, 10 in construction. That's about $300 million of capital. By leveraging our own land position and load, we've identified another 1.5 GW for development. On CCUS, we're working on several early-stage developments across the franchise. Now as context here, the key drivers of success in CCUS in our view are storage proximity, scale and efficiency, and full path integrated solutions, which fits with our capabilities.
Our Wabamun Carbon Hub development is positioned to capture emissions from a variety of emissions in the circle that you see on the map. In December, we signed an MOU with Capital Power, and last month, another anchor Wabamun, which would make it one of the largest globally. Timing-wise, we could see a phase in service between 2025 the project that could get the CCUS very quickly. Important to that project, last week, we landed on a great partnership with five indigenous groups that we hope will be full equity partners in the hub, and we're excited about moving forward with them on this project. With those pieces all in place, we've just filed our application for pore space through the CER. On RNG, the technology, economics, and commercial support, as you know, are already established. At the gas utility, three RNG and there's over 50.
The goal here, by the way, in the utility is 5% of our two TCF annual send-out to be RNG by 2030. In gas transmission, there are eight projects in development and a significant opportunity across the entire map. Hydrogen is at an earlier stage, but with probably much larger investment potential longer term. At this point, the key here is to prove out the technology and scalability. The Markham project pilots blending green hydrogen into our gas network, those facilities which went operational in Q4. We're developing a similar but larger one in Quebec with Evolugen. Finally, let's cover our ESG scorecard and how we're moving the ball forward further. We're doing well against our emissions targets so far.
Intensity is down 21% since 2018 towards our 2030 emissions goal, and absolute emissions are down as well. For example, our three operating solar self-power facilities will reduce about 20,000 tons of CO₂ equivalent in the first full year of operation. In GTM, for example, investments to modernize compressors term power contract with local as 45% emissions reductions by 2030 for seven of our pump stations. Of course, on diversity, we've seen great progress at all levels of our organization, including at the board. The key to achieving these goals is three actions we've taken. Establishing concrete plans within each of our businesses, linking targets to compensation, and aligning those goals with capital providers. Namely, that's CAD 3 billion of sustainability-linked financing that we've done over the past while.
Just to illustrate the set and met emissions targets in the past. 21% down on our Canadian operations. Taking out 55 metric tons of CO₂ equivalent with our conservation programs. We've set four new goals with zero. We've now added Scope 3 metrics, including a contribution to Scope 3 reductions by investing in renewables, low carbon fuels, and conservation. Here's how we're building on this foundation. We're going to work with our supply chain to get after Scope 3 emissions. We'll work with third parties to help develop science-based guidelines for the midstream sector. We're enhancing our TCFD disclosures to include a net zero scenario in our next sustainability report. That's coming out in Q2, by the way. We're developing our new low-carbon partnerships to drive innovation across the business. We're also integrating ESG further into our capital allocation framework.
Here's what that looks like. First, every new investment we consider includes an ESG lens and aligns with our interim and long-term targets. Our investment models factor in our emissions targets, so we plan for future investments. Our hurdle rate accounts for regulatory and permitting risk, and we test new investments against a range of transition scenarios. Our recent Ingleside acquisition, as you heard, is a great example of how we apply this ESG lens in allocating capital. With that, I'll pass it over to Vern for the financial review.
Thanks, Al, and good morning, everyone. Our fourth quarter results were up strongly over 2020 based on solid operational performance across our businesses, along with partial year cash flow contributions from the $14 billion of capital that we put to work last year. This translates into adjusted EBITDA and DCF being up 15% year-over-year, and EPS is 20% higher. Full year DCF per share came in at the top end of our range, and our DCF, our EBITDA was well within guidance. This is our 16th year in a row where we've hit guidance. Mainline volumes were about 3 million barrels per day in Q4, reflecting the benefit of the additional capacity from Line 3. Ingleside is performing in line with expectations, and cash flows are expected to ramp up in 2022 as more contracts kick in.
These operational results were partially offset by an interim toll provision recorded for the second half of 2021 following the expiry of our CTS agreement. We have included this full-year provision in our 2022 guidance and throughout our three-year financial outlook. Gas transmission utilization was very solid, with additional contributions coming from the capital we placed into service in the fourth quarter, including the CAD 1.5 billion BC Pipeline expansion. As Al mentioned, the utility's annual results were affected by CAD 31 million due to warmer than normal weather. We've had a cold start to 2022, so this is a little bit of a tailwind for us this year. Wind and solar resources in our renewables business met our expectations. In energy services, challenging marketing conditions continued to persist through the quarter.
However, as a reminder, most of our committed contracts expire late this year or early next year, which improves our outlook for 2023 and beyond. Operating results in our U.S. businesses were impacted by a weaker Canadian dollar, but our FX hedging program offsets much of this. You can see our hedge gains in eliminations and other. Finally, earnings reflect increased depreciation associated with the $14 billion of capital that we spoke about. Another solid year in the books, and that sets us up nicely for 2022. Let's move to that outlook now. Our 2022 guidance that we issued in December remains unchanged, and it represents a 9% increase in EBITDA over 2021. This includes the interim toll provision that I spoke about.
Mainline volumes are off to a good start in the first quarter of this year, supporting our forecast of just under 3 million barrels per day on average for the year. This factors in seasonally lower volumes in Q2 and Q3 due to upstream and downstream maintenance activities. In our gas businesses, systems are running near full capacity, so good performance in the early part of this year. There's been a lot of focus in the market on inflation, interest rates, and foreign exchange. Let's recap how we're positioned on these items heading into this year. On inflation, about 80% of our EBITDA has inflation protection built in through contractual escalators and other regulatory mechanisms. We're well-protected on the top line.
We continue to be highly focused on managing costs, and as Al mentioned, since 2017, we've delivered $1.2 billion in aggregate cost savings, with another $100 million realized last year. Our exposure to rising interest rates is limited, as most of our debt is fixed-rate, and what's remaining, we actively hedge. On FX, we are about 95% hedged on DCF for 2022 at a rate of 1.28. We've got good protection against exchange rate volatility. As you know, we intentionally limit our exposure to commodity prices, which amounts to less than 2% of our EBITDA. On the margin, we could see a little bit of upside from our investments in Aux Sable and DCP. Let's move to the funding plan. In keeping with our self-funded approach, all equity funding needs will be met through internally generated cash flows.
Debt maturities in 2022 are about 7% of our total debt, which is very manageable, and we'll continue to tap capital from diverse credit markets. In Q1, we've already swapped out some preference shares with hybrid notes. This allows us to capitalize on lower rates, which optimizes our funding costs. No change to our expectations for leverage. We expect to exit 2022 near the bottom of our 4.5-5.0 debt-to-EBITDA range, driven by annualized contributions from Line 3 and the Ingleside Terminal. This provides us excellent financial flexibility and results in $5 billion-$6 billion per year of investment capacity. A portion of that will fund our secured program, let's turn over to that. As of today, our secured backlog sits at $10 billion.
This reflects the $700 million of further investments in our U.S. gas transmission business that we announced today. We added the phase II of Texas Eastern Modernization Program and phase II of Appalachia to Market. That is consistent with our thesis that natural gas is a part of the long-term energy equation, providing reliable and affordable growth along with emissions reductions. More broadly, our secured program continues to be well-diversified across our businesses with an emphasis on ratable and capital-efficient growth. Over our three-year planning horizon, these projects will support a 5%-7% DCF per share growth outlook. As Al noted, we have good visibility to $6 billion per year of organic growth coming from conventional and low-carbon investment opportunities, which will support our longer-term growth outlook. Let's wrap up with our capital allocation priorities.
We will strengthen over the year, and we have BBB+ ratings from all four credit rating agencies. This is exactly where we wanna be. We will continue to grow our dividend ratably. We increased it by 3% this year, and that's our 27th consecutive annual increase. Annual ratable dividend growth remains core to our value proposition. Our cash flows and balance sheet leave us with about $5 billion-$6 billion of annual investment capacity. We'll deploy $3 billion-$4 billion to advanced brownfield, low multiple expansions and optimizations, along with ongoing modernization investments and the utilities annual capital program.
That leaves about $2 billion per year in excess investment capacity for more organic growth, potential asset acquisitions, share buybacks or debt repayment. Successful opportunities will need to meet our low-risk business model, our risk-adjusted hurdle rates, have a strong strategic fit, and align with our emission reduction goal. How we check all of these boxes. In addition, we have a proven track record of opportunistically. This could supplement our $5 billion-$6 billion of. The bottom line is we'll continue and be good stewards of capital. I'll wrap up and turn it back to Al.
Okay. Thank you, Vern. Just a few takeaways here. Our diversified business is low and consistently growing the dividend. The solid base, along with our secured growth outlook, drives 5%-7% DCF per share CAGR through 2024. We have a two-pronged strategy, capitalizing conventional energy fundamentals while increasing low carbon investments. We think that supports continued growth beyond 2024. As you just heard from Vern, we'll remain very disciplined, prioritizing capital efficient and utility-like projects, and ensure free cash is deployed to maximize value. All that to say that we believe that our value proposition remains very solid. If you recall that five-year look back and how 2021 capped it off, we believe we're in excellent position to continue growth. Before we get to the questions, I want to acknowledge Bill Yardley, our longtime leader of the gas transmission business.
A couple of weeks ago, we announced Bill's retirement after 21 years at Enbridge, and previous to that Spectra, and just a remarkable career. Bill developed a top-notch gas business, and he's been a key member of our broader executive teams on the board for us. What really stands out for me is how he set up the transmission business for the future, particularly in expanding it and executing our LNG export strategy. He's also personally led a mission to make us better on safety and reliability. It won't be lost on customers. He'll speak at Enbridge Day. Bill is very, very passionate about the future of natural gas. We spent a lot of time thinking and planning for succession and developing people at Enbridge to manage changes like this.
Taking over for Bill will be Cynthia Hansen, who's had her own mark leading our gas utility over the years and has been through several senior roles. It's a natural fit, and she's excited about taking on this new role in Houston. Taking over for Cynthia in Toronto is Michele Harradence. Michele currently runs gas transmission operations in Houston and has great experience in every part of the value chain. Finally, in addition to his CSO role, Vern is taking on corporate development. Again, a long history of experience and leadership at Enbridge. We'll end it off there and turn it back to the operator for the Q&A.
Thank you. We will now begin the Q&A session. If you have a question, please press star one on your touch tone phone. If you wish to be removed from the queue, please press the pound sign or the hash key. If you're using a speakerphone, you may need to pick up the handset first before pressing the numbers. Once again, if you have a question, please press star one on your touch tone phone. We'll pause for just a moment to compile the Q&A roster. Your first question comes from the line of Robert Catellier with CIBC Capital Markets.
Thank you. Good morning, everyone, and thanks for the presentation. I wanted to start with the offshore wind, where we've seen rising costs causing some financial difficulties for one of the offshore wind contractors. Can you describe your exposure to Saipem on existing offshore wind projects? Just more generally, how do you see inflation and cost escalation impacting your ability to move other projects development to FID?
Okay, Robert, I'm gonna quarterback this Q&A, by the way. I think for this one we'll hand it to Matthew. It's a good question on inflation and offshore wind.
Okay, thanks, Al. Thanks, Rob, for your question. Yeah, you're right. We are seeing inflationary pressures in the industry generally, EPC contracts for construction. Right now, fortunately, we're not seeing inflationary pressure on our capital budgets over there. As you know, same as there. They're scheduled to come online later this year, and that's in good shape. Regarding Saipem, they are involved with us, especially at Courseulles-sur-Mer, Calvados. They are involved in the foundations. You know, generally a couple of points there. Calvados is a few years away from in-service. The major construction work there would start next year. As you can imagine, we have the regular protections in terms of bonds as well as collateral.
You know, it's also I think the main point, it's a very good contract. We don't see any disruption there at this point. You know, we're optimistic that there won't be any impact there as we go forward. Al, back to you.
Yeah. I think the broader point around inflation though in this opportunity set is real, though, Robert, I think your point is good. As I referred to in my remarks, I think we've got enough going on here that, you know, we're gonna watch that carefully, and we're not gonna necessarily get into projects that get us exposed. I mean, we know the returns are clamping down in this sector, so we're gonna be very careful about future investments. You know, there's no rush for us to, you know, get into a whole bunch of projects that are gonna crunch our returns, so that's the broader perspective on it.
Okay. That's very helpful. Maybe one more just on slide 13, you had a comment on your CCUS update about utility-like commercial model and returns. I'm just wondering if in your commercial discussions, are you taking a cost of service approach or a fee for service approach or maybe some other? I'm curious as to what level of scale you think is necessary to be able to make that work on a commercial basis.
All right. Okay. Well I'll start it off and then, as you know, we're working on a project here in Alberta, but generally speaking, you know, this whole sector is gonna develop with scale and cost in mind. Our thought is, with appropriate sort of, what would you call it? Throughput with CO2, on the infrastructure, we can make a utility-like structure work. And what I mean by that is good protection in terms of long-term cash flow, and in that way, we should be able to provide the lowest cost of capital to actually make things work. These are very cost and capital-intensive projects, so we need to be very thoughtful about how we bring our cost of capital to bear on that.
It really does fit the utility-like model, and that should line up with the competitiveness that customers will want on this. That's the bigger picture. In terms of scale, what we're thinking about on this project, as you know, we have a rough estimate of investment required for each megaton of reduction, which is about $1 billion for each. These are fairly large-scale projects, so that's probably the order of magnitude you're talking about for each megaton. I don't know. Colin, do you want to add anything on that?
I think you covered most of it. The only thing I'll add, Robert, is a point on proximity and to help this cost down equation, you know, moving the waste product the shortest distance possible contributes meaningfully to the outcome. Our project is designed to transport and store the carbon relatively close to the emitting source. That helps too.
Okay. That's helpful color. Thanks, guys.
Thank you.
Your next question comes from the line of Robert Kwan with RBC Capital Markets.
Great. Good morning.
Good morning, Robert.
If I can just follow a little bit here on emerging energy transition initiatives, whether it's CCUS or you talked about hydrogen and just you've been a returns-focused organization historically, and what's the appetite to deploy capital at suboptimal returns just to establish the footprint with the hope of developing a franchise that can drive additional projects with better returns over time?
Yeah. Well, in short, we don't have a lot of appetite to deploy capital in low return projects. I think this is gonna be you know, an interesting number of years here as we go forward. I think so far, Robert, we've been able to deploy capital right in line with our traditional investment criteria as you point out. Whether you look at the RNG opportunities that we're investing in, good returns there. Certainly, the renewables projects in broad terms have generated you know, Enbridge-like returns, let's call it. The hydrogen pilot plant is generating a good return under a regulatory protection, let's just call it. So that will continue to be the process.
You know, there may be something at the margin, let's say, where we're trying to prove a technology out or prove it out to scale that, you know, we could see, you know, a little bit of capital deployed to see that happen. Generally speaking, during this period while we're in a scale-up, we wanna be very careful not to get too far ahead of the curve on putting capital to work that isn't gonna generate the right return for us. That's our overall approach.
That's great, Al. Maybe if I can finish here on the Mainline, you know, it's been, I guess now a little over 10 years under CTS. You've got a shipper group that's arguably maybe more disparate in terms of their interest than we've seen in the past. What are you seeing, just as you've had these initial discussions as the top 2 or 3 points of contention in terms of, you know, what they're coming to you and just even what members within the representative shipper group, you know, may be wanting here?
You know, it's an interesting question. While some time has passed, some things stay the same. Don't wanna be presumptive here because as Al mentioned, we're still in relatively early innings consulting and listening carefully. What is staying the same is the early feedback is to ensure Enbridge behaves in a manner that creates value for the shipping community. I think Al went through the ingredients to that and moving you, we are here. We're hearing about the need for continued you know, fixed tolling, certainty on the toll and that alignment. The Mainline contracting you know, contentious at the end.
You know, I think if we remove the contracting element of it or substantially do that, I think there'll be potential for consistent alignment here by the group. Al, do you wanna add anything?
Yeah. I think, Robert, you know, everybody's for years, so, you know, Colin mentioned toll certainty, but just generally certainty for our customers is important as it is for us. Everybody wants to move forward, I think, and try to tolls. It's key here is that it's difficult to build any pipeline capacity. We know that the upstream customers do have a lot of opportunity to grow incrementally. They wanna make sure that we bring what we brought before, which is ideas and options to move barrels at very low incremental cost for them.
Probably the other thing that's staying the same, which I think we've done, and that's why I mentioned in my remarks that, you know, having us aligned to ensure that, we're managing the cost part of it ultimately flows through the toll and what we land on here. A lot of certainty as we've had, as they've had in the past. That's the main priority from what we see.
That's great. Appreciate the comments. Bill, all the best in retirement.
Thanks very much, Robert.
Thank you, Robert.
Your next question comes from the line of Jeremy Tonet with JP Morgan.
Hi. Good morning.
Hi.
Hi. Bill, you will be missed. Best of luck going forward.
Thanks very much, Jeremy. Appreciate it.
You know, just want to touch on the Mainline a little bit here, and I don't know if you guys exactly disclosed it, but as we think about the reserves booked in the fourth quarter, just wanna confirm that that's for two quarters, third quarter and fourth quarter. Do you guys quantify what that level was?
As we talked about at our Enbridge Day in December, we're not disclosing the magnitude of that or the provision that we have in 2022 and beyond. I think you'll understand that these are commercially sensitive numbers, and we don't wanna broadly disclose those.
Got it. Fair enough there. Just wanted to come back to buybacks, I guess, a little bit. I was wondering if you could provide just maybe a little bit more color on the capital allocation calculus as far as, you know, what could lead to different levels of buybacks if it's, you know, if that falls in the rank of where capital allocation points to. Just trying to get a sense. There's a big program out there, but what-
Well, I'll start it off, Vern can add. You know, I think we've got some broad criteria of how we're gonna deploy this share buyback program. I think, you know, just going back a little bit, Jeremy, you know, it certainly moved up in the order for us after Line 3 went into service. I think we communicated that, and it's certainly right in the mix right now. The way to think about it generally is we wanna make sure the balance sheet is in... The reason for that is we need that flexibility to take on opportunities that we see and capitalize them. So leverage is number one. Now, beyond that, you know, potentially some asset M&A, the more-like opportunities, where the shares are in the market and determine.
It's all about how we maximize the value here among those three options after we make sure the balance sheet is in check. That's the policy or approach generally to using the buyback program. Buying more of our assets is always a good thing. It's really nice to have another avenue to give on top of our dividend. Really, you can think about it that it's a supplement to our annual dividend.
Your next question comes from the line of Rob Hope with-
Morning, everyone, and congrats on the upcoming retirement. All the best in the future. The question actually could be for you or Sia. Looking at the CAD 2.5 billion T-South expansion, is this entirely proceeding? If so, is this kind of a 2026, 2027 in-service pipeline expansion just given when Woodfibre is expected to come in?
Yeah. Pretty much, Rob. You know, we've been expanding T-South quite a bit. You know, just finished one last year that was about CAD 1 billion for customers in southern BC and the Pacific Northwest. The next big one is probably gonna be related to a major offtake, and Woodfibre certainly would fit that bill. And yeah, anything we start now would be, you know, 25, 26 in service. A lot of optimism there. I think you've been following them for sure. Yeah, no, I think they've got a good shot.
All right, great. Thank you. just moving over to the crude oil business, the downstream expansion opportunities on things, you know, more further along, just given that Line 3 is now in service. kinda has the Capline reversal changed any of the dynamic avenues of flow?
Okay. Over to Colin.
Hey, Rob. Our downstream pipes, we've mobilized, you know, early work on that ISD. We would be talking. You should probably think about those in concert with the EHOT as well. They kind of all go together, and it'd be good to have of all that down in Houston. Timing-wise, we're having parallel discussions with industry as we advance the Mainline tolling framework. You can see how they would interrelate to ensure for sure. So that's the kind of timing we're thinking on those. On the other business development ideas, those are, you know, Ingleside and Express, et cetera. Those are all happening on a quicker basis, I would say, independent of the Mainline Gantt chart.
On your question on Capline, I think we're viewing that as more opportunity than threat at this point. As you know, we feed it from three of our pipelines and an upstream about the Mainline and regional, so cannibalize Flanagan South volumes, for example. I think they're moving about 100 a day, and I think that came off of rail and barge service.
All right. Appreciate it. Yes, of course. Thank you.
Thanks.
Thanks, Rob.
Your next question comes from the line of Ben.
Okay, thanks. Good morning. I was wondering, what are your updated thoughts on non-core asset sales at this point? The more commodity-based businesses. Are you comfortable just holding on to, or is this a good window to?
Yeah. Hey, Ben. You know, generally speaking on non-core asset sales, there's not a lot that fits that category. I mean, certainly we could look at, you know, portions of our other assets if we could see great value. We'd always look at that, and the team's always monitoring that. As far as the commodity sensitive ones, there's really not a lot in that category. Certainly the main ones would be Aux Sable and DCP. In the case of Aux Sable, it's really tied to the Alliance Pipeline, as you know, from an operational point of view. The commodity exposure there is relatively low for us in the bigger picture context of Enbridge. In the case of DCP, I think you're familiar with that one.
You know, it's a relatively small piece of our EBITDA as well, and it comes with a very large negative basis, tax basis in that asset. Right now I think we're pretty comfortable in just holding those relatively small pieces of commodity exposure.
Okay. Renewable returns coming down and being careful about future investments. You know, I like to hear that. What about that could be challenged in terms of returns and inflation? Is there a window here to take advantage and go into new geographies, for example?
Yeah. Well, you're right to point out that, you know, valuations have certainly compressed over the last little while, and some of them are encountering difficulties. It's probably not a primary objective of ours right now, Ben. The reason for that is I think we've got, as I alluded to earlier, quite a bit going on in the business. When you talk about the solar self-power opportunities, there's a number of what we call front of the meter renewables opportunities where, you know, we can bring our expertise to bear. We've got the projects that Matthew's been working on and developing, you know, for the last two to three years.
I think we've just got enough on the go right now, to you know not necessarily require going out and doing some kind of M&A deal. We always watch it, of course, but low likelihood at this point.
Just a quick one for Colin. Project or maybe anything in Alberta CCUS. Do you need to get the CER involved at some point or Bill C-69? Like, how does that feed in at all?
Permits, you know, physically, as they develop, it's an intra Alberta situation. It doesn't cross borders. As Al said, the whole industry will need clarity quickly on permitting on this whole, you know, new slate of projects. We'll be advancing that in parallel. The ISDs for the emitters we're working with here are relatively early in the relative scale of things in 2025, 2026. We've got some time to work on that, but not a lot.
Yeah. I think you mentioned C-69. I don't think that applies here. Pretty sure about that, Colin, but if there's something different, we'll get back. I don't think C-
Your next question comes from the line of Brian Reynolds with UBS.
Bryan.
Hi. Good morning. Good morning, everyone. Just as a follow-up on the share buyback authorization in Mainline. Was just curious if you could, you know, provide a little bit more color on, you know, how Mainline contracting uncertainty and reserving could ultimately, you know, impact the size and pace of those buybacks over the balance of 2022 and 2023. Thanks.
I see that actually. I think as Vern alluded to, we've made our provisions. It's within you know the guidance that we're talking about for 2022 as well as our. I think you know if you look at call it the variability in those outcomes, it's actually relatively small. You know in the bigger picture, the share buyback program really shouldn't be impacted by the outcome there. That's how we're looking at it. Just from the numbers that we see and the variability, it's not going to be impacted by. The share buybacks won't be impacted by the Mainline outcome.
Great. Appreciate all that color. As a follow-up, just curious if you could provide an update on the Markham hydrogen blending, you know, post in-service. You know, how is the project performing and do you see this project as scalable and replicatable across the rest of your footprint at this time?
Yeah, that's a great question, Brian. Cynthia is on the line. Cynthia.
Yeah. Thanks, Brian, and thanks, Al. We've just started with the project. It went live in, as Al said, in Q4. It's been performing well. You know, we will continue to learn from it. It is something that we're looking to scale, and we're very hopeful. Things are.
Maybe you could help us maybe paint a little picture about how this Alberta Carbon Capture initiative might evolve from an operational and governance and ownership framework, recognizing that a lot of different partners bring unique attributes and skills to the table. I'm just wondering, you know, what are the guardrails of what is possible for the range of ownership that Enbridge would consider. You know, how important is operatorship and how those interfaces might work if there's elements that others operate. Then also layering on the governance.
There's a lot of complexity, and I realize that it's all being navigated and there might be some sensitivities, but anything you could help us understand as to how to mitigate some of the execution risk on beyond the commercial frameworks.
Okay. Well, I'll start off, Linda. Thanks for the question. Well, first of all, I think you're right in pointing this out. This is going to be a, let's put it this way, a collaboration. As I mentioned in my remarks, this is going to take a lot of integration if you just think about the capture, the transportation all the way through to storage. So we see this as a combination of players.