Enbridge Inc Q4 FY2021 Earnings Call

Welcome to the Enbridge Inc. Fourth Quarter 2021 Financial Results Conference Call. My name is Amitras, 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. 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, Amitras. 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 get to answers as many questions as possible, we'll be limiting the questions to one plus a single follow-up as necessary. We'll be prioritizing questions from the investment community. So, if you are a member of the media, please direct your inquiries to our communications team, who will be happy to respond. And 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. And 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. As we start, the graphic serves as a reminder of how we launched Enbridge Day in December, emphasizing our role as a bridge to a cleaner energy future. I will begin with a recap of 2021, share our current view on the energy markets, then provide a business update and discuss our ESG performance, before handing it over to Vern for the financial results and outlook. To start, the end of 2021 marks five years since the Spectra acquisition, a deal that was crucial for us, providing a leading natural gas transmission business and a significant gas utility franchise. We are seeing substantial growth and synergies in this area. Simultaneously, we have expanded our liquids business and acquired the top crude oil export facility in North America. We've also developed our offshore wind business in Europe and established a comprehensive low carbon business. By divesting non-core assets of great value, we have streamlined our structure and our financial position is stronger than ever. The business is in a great place, and we are optimistic about the future. As indicated this morning, we had another strong quarter, concluding a significant year in our five-year journey. We achieved record safety and operating performance, with our systems running at full capacity, resulting in DCF per share at the high end of our guidance at $4.96, which included an additional $100 million in cost savings. We put $14 billion of capital into service, secured another $2 billion in growth, and sold $1.2 billion in non-core assets at favorable prices. We've made major strides with our crude oil and LNG export strategies and in low carbon initiatives. With Line 3 operational, we expect record mainline throughput and robust EBITDA growth in 2022, which coincides perfectly with the timing for producers, creating significant value as new capacity and improved netbacks come into play amid high prices. This underlines the value of our franchise. Gas Transmission utilization was also strong, with Texas Eastern experiencing 16 of its 20 highest peak days over the last decade. Although warmer weather affected our utility performance, we compensated well, and our renewables performed positively in terms of resources and EBITDA. This resulted in solid cash flow and dividend growth, marking our 27th consecutive increase this year. We're also free cash flow positive this year with clear organic growth opportunities across our businesses. Now, regarding Energy Markets, to be direct, we are currently facing an energy crisis. The economic recovery has led to strong global demand for energy. Typically, we would expect a supply response, but this time is different due to substantial underinvestment in both conventional and renewable energy. Unsurprisingly, this has resulted in energy shortages, increased fuel costs, and inflation, which pose challenges to competitiveness and economic growth. For instance, last month, electricity prices in the US Northeast exceeded $300 per megawatt hour multiple times, a situation mirrored by rising heating bills, all stemming from inadequate gas infrastructure. What we are experiencing highlights the critical need for reliable, affordable energy. North American conventional supply will play a significant role in the coming years due to long-lived reserves, low breakevens, and strong ESG performance. These North American advantages and coastal infrastructure will lead to increased exports, undergirding our crude and LNG export strategy. Prior to the crisis, we anticipated that conventional energy would grow through at least 2035, and current circumstances only reinforce this perspective. Despite favorable energy fundamentals, we will remain disciplined in utilizing free cash and will gradually increase our investment in low-carbon initiatives. We have a robust pipeline of both conventional and low-carbon opportunities, totaling about $6 billion annually, which aligns with our free cash flow capabilities after dividends and maintenance capital, including debt capacity. Of the $6 billion available for investment, we plan to prioritize $3 billion to $4 billion each year for stable utility-like projects and low capital intensity growth, while allocating any excess capacity to other promising options such as organic growth or potentially asset acquisitions like Moda, though such opportunities are rare, and share buybacks. In the conventional sector, we will expand and modernize our gas systems to replace coal and support renewable growth. We will continue to develop our LNG and export capabilities and invest in the gas utility sector while also pursuing capital-efficient liquid pipeline optimizations. Importantly, these initiatives come with opportunities for embedded low-carbon solutions, including RNG, hydrogen, and CCUS infrastructure. Additionally, our renewables backlog offers clear visibility for growth. Moving on to the conventional business update, our utility continues to gain 45,000 customers annually and we are connecting 27 new communities, which we expect will contribute approximately $1 billion to our rate base this year. In Gas Transmission, we recently sanctioned two more projects worth $700 million. These include Phase 2 of our modernization program aimed at enhancing reliability and reducing emissions, as well as the next phase of our Appalachian market expansion designed to provide much-needed capacity in the Northeast. In that business, we are now in negotiations regarding rates with Texas Eastern shippers. With Line 3 fully operational, our capacity is approximately 3.1 million barrels per day, and we are effectively running at full capacity in liquids volumes. Our current focus is on enhancing downstream egress to the Gulf via the Flanagan Seaway path. These expansions are capital-efficient and offer desirable returns. Here's how we envision the mainline tolling process moving forward. There are two main options: a CTS-like incentive tolling arrangement or a cost of service model. We are currently in the consultation and information sharing stage, aiming to determine the best option for our shippers while also aligning with our interests. The incentive tolling model has proven effective in the past, as it provides the toll certainty our shippers require to operate their businesses, keeps costs manageable, and encourages us to increase capacity. Within this framework, we assume operating capital and foreign exchange risks, while also managing the fluctuations in volumes. If we handle these elements well, we can achieve a return that exceeds the cost of service return. For context, we added approximately 1 million barrels per day of new low-cost capacity during the last CTS term, which offered significant value to shippers amid the difficulties of adding new egress out of Western Canada. Although this value equation has been beneficial for both sides in the past, we are also open to a cost of service arrangement moving forward, as it reduces the risks I mentioned and allows for a solid risk-adjusted return. As we've noticed, gaining consensus among shippers can be challenging, so we're currently preparing a cost of service application. While we don't want to speculate on timelines, we aim to define a path by this summer and subsequently file either a settlement agreement or a cost of service application. Regardless of the outcome, we do not expect any significant changes to Enbridge's overall EBITDA. Regarding liquids, we have integrated our Ingleside export terminal and are now pursuing expansions. The storage capacity is fully contracted, and we are in discussions with customers about adding another 2 million barrels of capacity, which we plan to approve later this year. Currently, 60% of the 1.6 million barrels per day export capacity has been contracted. Our objective is to maximize this capacity. Additionally, there is early interest in developing exports for LNG, hydrogen, and ammonia, driven by global petrochemical feedstock demand. We believe that the low-cost, abundant supplies of natural gas and natural gas liquids from the Permian will be critical to fulfilling that demand. We are also co-locating up to 60 megawatts of solar power at Ingleside, which will help us achieve net-zero emissions and contribute to scope 3 reductions, effectively making Ingleside net negative in terms of emissions. This is a prime example of how we evaluate new investment opportunities. Outside of Corpus Christi, we are continuing our development of the Houston oil and spot terminals, which will facilitate expanded upstream access to the Gulf and enhance 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, there is strong buyer interest in contracting US Gulf capacity. We just brought on our Cameron extension project connecting to the Calcasieu Pass facility, our fourth transport deal. We got several projects in development as well, and we've 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 $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 all, we've got $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. But we know that energy transition is gaining momentum. And 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 storage assets are essential to unlocking low-carbon energy for the economy. And our franchises feed the best North American markets. The transition is going to take time, as we all know. So we're focused on investing capital where there is 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 ripe for renewables, and we've been building that business for a decade. We're starting to see the policy framework and investment flow for hydrogen in CCUS, but they are not where they need to be to accelerate and scale investment. Global carbon markets are starting to form, but that will take time to mature as well. In our view, the importance of regulatory and permitting clarity is underestimated. We had more certainty and shorter timelines to permit projects. Through 2025, we see about $4 billion of 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 hydrogen accelerate. So let's run through the key low-carbon areas. We've got 14 renewables projects in construction right now, including Solar South Power in North America and offshore wind in France, totaling 1.5 gigawatts. Our offshore, over half of the 80 foundations are now in at St. Nizar and it’s on schedule for late this year. Fecamp 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 megawatts 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. And by leveraging our own land position and load, we've identified another 1.5 gigawatts 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 emitters over 20 megatons per year of CO2 capture potential in the circle that you see on the map. In December, we signed an MOU with Capital Power and last month, another one with Lehigh Cement. So, combined, that's close to four megatons of CO2, which would anchor Wabamun, which would make it one of the largest globally. Timing-wise, we could see a phased-in service between 2025 to 2027. So, it's a project that could get the CCUS ball rolling in Alberta 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 just filed our application for port space through the Alberta government's RFP process. On RNG, the technology, economics, and commercial support, as you know, are already established. So, we're in a scale-up mode on this. At the Gas Utilities, three RNG facilities are operating in construction, and there's over 50 in early-stage development. The goal here, by the way, in the utility is 5% of our 2 Tcf annual send out to be RNG by 2030. In Gas Transmission, there's 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 Markham project, a pilot blending green hydrogen, into our gas network. That's North America's first one of those facilities, which went operational in Q4. We're developing a similar but larger one in Quebec with Evolution. Finally, let's cover our ESG scorecard and how we're moving the ball forward further. So, we're doing well against our emissions target 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 south power facilities will reduce about 20,000 tons of CO2 equivalent in the first full year of operation. And in GTM, for example, investments to modernize compressors lowers emissions by 25% at each facility. In Liquids, we're just signing a long-term power contract with a local utility that could see 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 as the $3 billion of sustainability-linked financing that we've done over the past while. So you can see on the right here that we're leading the pack already, but here's how we get better. And just to illustrate the mindset behind this. We've previously set and met emissions targets in the past, 21% down on our Canadian operations and taking out 55 metric tons of CO2 equivalent with our conservation programs. We set four new goals with four pathways and align them with Paris on net zero. We've now added Scope 3 metrics, including a contribution to Scope 3 reductions by investing in renewables, low carbon fuels and conservation. So 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 work with third parties to help develop science-based guidelines for the midstream sector. We're enhancing our disclosures to include a net zero scenario in our next sustainability report. That's coming out in Q2, by the way. And 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. So here's what that looks like. First, every new investment we consider includes an ESG lens in line 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 risks 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. So 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 EBITDA was well within guidance. This is our 16th year in a row where we 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 $1.5 billion BC pipeline expansion. And as Al mentioned, the utility's annual results were affected by $31 million due to warmer-than-normal weather. But, 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 continue 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 US businesses were impacted by a weaker Canadian dollar, but our FX hedging program offsets much of this. And you can see our hedge gains in eliminations and other. And finally, earnings reflect increased depreciation associated with the $14 billion of capital that we spoke about. So another solid year in the book 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. So 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. So 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. So we've got good protection against exchange rate volatility. And as you know, we intentionally limit our exposure to commodity prices, which amounts to less than 2% of our EBITDA. But 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 to 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 to $6 billion per year of investment capacity. A portion of that will fund our secured program, so 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 US Gas Transmission business that we announced today. We added the phase two of Texas Eastern modernization program and phase two of Appalachia to market expansion. 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% to 7% DCF per share growth outlook. And 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. So let's wrap up with our capital allocation priorities. Our priorities start with maximizing our financial strength and flexibility. Our balance sheet is in great shape. It will strengthen over the year, and we have BBB+ ratings from all four credit rating agencies. This is exactly where we want to 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 to $6 billion of annual investment capacity. We'll deploy $3 billion to $4 billion to advance brownfield, low multiple expansions and optimizations along with ongoing modernization investments and the utility's annual capital program. That leaves about $2 billion per year in excess investment capacity from 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 goals. The Ingleside terminal acquisition was a good example of how we checked all of these boxes. In addition, we have a proven track record of opportunistically recycling capital. We did another $1.2 billion last year, and this could supplement our $5 billion to $6 billion of annual investment capacity. The bottom line, it will continue to be highly disciplined and be good stewards of capital on behalf of our shareholders. So I'll wrap up and turn it back to Al.

Okay. Thank you, Vern. Just a few takeaways here. Our diversified business, as you just heard, continues to generate predictable cash flow and consistently growing the dividend. The solid base, along with our secured growth outlook, drives 5% to 7% DCF per share CAGR to 2024. We have a two-pronged strategy, capitalizing on conventional energy fundamentals while increasing low-carbon investments, and we think that supports continued growth beyond 2024. As you just heard from Vern, we remain very disciplined, prioritizing capital-efficient and utility-like projects and ensure free cash is deployed to maximize value, all I have to say that we believe that our value proposition remains very solid. And if you recall, that five-year look back and how 2021 capped it off, we believe we're in an excellent position to continue growth. Before we get to the questions, I want to acknowledge Bill Yardley, our long-time 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 team. Many of you have known Bill for a long time, and it's been a real pleasure to work alongside of him. He's put a lot of points on the Board for us, but 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, but he's also personally led a mission to make us better on safety and reliability. And it won't be too far into a discussion with Bill before he gets to the importance of serving our customers. Finally, as you heard him speak at Enbridge Day, Bill is very passionate about the future of natural gas. We spend a lot of time thinking and planning for succession and developing people at Enbridge to manage changes like this. So 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. So 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. And finally, in addition to his CFO role, Vern is taking on Corporate Development, again, a long history of experience and leadership at Enbridge. So we'll end it off there and turn it back to the operator for the Q&A.

Thank you. We will now begin the question-and-answer session. 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. So, can you describe your exposure to Sepam, a lot of existing offshore wind projects? And 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 going to back this Q&A, by the way. So, I think for this one, we'll hand it to Matthew. It's a good question on inflation and offshore wind.

Thank you for your question, Rob. Yes, we are experiencing inflationary pressures across the industry, particularly in infrastructure. However, for our offshore wind assets and construction projects, we have strong protections in place with our wrap EPC contracts. Fortunately, we are not currently facing inflationary pressures on our capital budgets in that area. The projects are on track to come online later this year. Regarding Sepam, they are collaborating with us, particularly on the Courseulles Calvados foundations. It’s worth noting that Calvados is a few years from going into service, with major construction expected to start next year. We have standard protections in place, including bonds and collateral, and we believe this contract is solid. We do not anticipate any disruptions at this time, and we remain optimistic that there will be no negative impact as we move forward. Al, I’ll pass it back to you.

Yes, I think the broader point around inflation, though, in this opportunity set is real. Robert, I think your point is good. As I referred to in my remarks, I think we've got enough going on here that we're going to watch that carefully, and we're not going to necessarily get into projects that get us exposed. I mean we know the returns are clamping down in this sector. So, we're going to be very careful about future investments. And there's no rush for us to get into a whole bunch of projects that are going to crunch our returns. So, that's the broader perspective on it.

Okay, that's very helpful. And maybe one more. Just on slide 13, you had a comment on your CCUS update about utility-like commercial model and returns. And I'm just wondering if commercial discussions, are you taking a cost-of-service approach or a fee-for-service approach or maybe some other? And I'm curious as to what level of scale you think is necessary to be able to make that work on a commercial basis?

Okay. Well, I'll start it off and then as you know, we're working on a project here in Alberta. But generally speaking, this whole sector is going to develop with scale and cost in mind. So, our thought is with appropriate sort of, what would you call, 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. So, 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. So it really does fit the utility-like model and that should line up with the competitiveness that customers will want on this. So 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. So 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, moving the waste product, the shortest distance possible contributes meaningfully to the outcome. So our project is designed to transport and store the carbon relatively close to the emitting source. So that helps too.

Okay. That's helpful color. Thanks, guys.

Great. Good morning.

Thank you, Robert.

I would like to discuss emerging energy transition initiatives such as carbon capture, utilization, and storage, as well as hydrogen. Historically, your organization has focused on returns. What is your willingness to invest capital with less than optimal returns just to establish a presence, with the expectation that it will lead to a franchise capable of generating more profitable projects in the future?

Yeah. Well, in short, we don't have a lot of appetite to deploy capital in low-return projects. I think this is going to be 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 Enbridge-like returns, let's call it. The hydrogen pilot plant is generating a good return under regulatory protection, let's just call it. So that will continue to be the process. 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 we could see a little bit of capital deployed to see that happen. But generally speaking, during this period, while we're in a scale up, we want to be very careful not to get too far ahead of the curve on putting capital to work that isn't going to generate the right return for us. So that's our overall approach.

That's great, Al. And maybe if I can finish here on the Mainline, 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. So what are you seeing just as you've had these initial discussions as the top two or three points of contention in terms of what they're coming to you and just even what members within the Representative Shipper Group maybe waning here?

Go ahead, Colin.

Hey Robert, good morning. It's an interesting question. And while some time has passed, some things stay the same. And I don't want to be presumptive here because as Al mentioned, we're still in relatively early innings, consulting and listening carefully to customer interest. What's staying the same as the early feedback, which is fairly homogenous is to ensure Enbridge stays aligned and behaves in a manner that creates value for the shipping community. And I think Al went through the ingredients to that and it's moving as much oil as we can safely every day at $90 a barrel, that's the primary value lever here. So we're hearing about consistently the need for continued fixed tolling, certainty on the toll and that alignment. So while I know that the Mainline contracting application was contentious at the end, 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, if you want to add anything?

I believe everyone has faced significant challenges over the past three to four years. As Colin pointed out, certainty regarding tolls is crucial, not only for our customers but also for us. There is a strong desire to move forward and make progress. While Colin discussed tolls, we must also consider egress. The main point is that constructing new pipeline capacity is quite challenging, and our upstream customers have ample opportunities for incremental growth. They want us to provide the same solutions as before, offering ideas and options to transport barrels at a very low additional cost. Additionally, maintaining cost management has been a consistent strength for us. This is why I emphasized in my remarks the importance of alignment in managing costs, as this will ultimately influence the toll we settle on. Overall, there are many reasons to ensure we have a high level of certainty, similar to what we've experienced in the past, which remains our top priority.

That's great. Appreciate the comments. And Bill, all the best for retirement.

Thank you very much, Robert.

Thank you, Robert.

Hi, good morning.

Hi.

Hi, and Bill, you will be missed. Best of luck going forward.

Thanks very much, Jeremy. Appreciate it.

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, I just want to confirm that's for two quarters, third quarter, and fourth quarter. And do you quantify what that level was?

So this we're going to hand to, Vern.

Hi, Jeremy. The reserve that we booked was for Q3 and Q4. And as we talked about at our Investor Day in December, we're not disclosing the magnitude of that or the provision that we have in 2022 and beyond. So I think you'll understand that these are commercially sensitive numbers and we don't want to broadly disclose those.

I understand. That's reasonable. I wanted to return to the topic of buybacks and ask if you could share more details about the capital allocation process and what factors might influence different levels of buybacks. I'm trying to get a clearer picture of the potential for a large program, but I'm curious about what might actually happen.

Okay. Well, I'll start it off, Vern can add. I think we got some broad criteria of how we're going to deploy this share buyback program. I think just going back a little bit, Jeremy, 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. So the way to think about it generally is, we want to make sure the balance sheet is in very strong position at all costs. And the reason for that is we need that flexibility to take opportunities that we see and capitalize them. So leverage is number one. Now on that, you've got this buying for capital between additional organic growth, potentially some asset M&A, the Moda-like opportunities. And then, of course, we'll look at where the shares are in the market and determine so it's all about how we maximize the value here amongst those three options after we make sure the balance sheet is in check. So that's the policy or approach generally to using the buyback program. Vern, do you want to add anything?

Well, I'll just add that we continue to think that the shares are undervalued. So buying more of our assets is always a good thing. And it's really nice to have another avenue to give the capital back to our shareholders on top of our dividend. So really, you can think about it that it's a supplement to our annual dividend.

Got it. That’s very helpful. I’ll leave it there. Thank you.

Okay. Thanks, Jeremy.

Good morning, everyone, and congratulations on your upcoming retirement, Bill. Wishing you all the best for the future. My question is regarding the $2.5 billion T-South expansion. Is this completely reliant on the Woodfibre project moving forward? If so, are we looking at a 2026 or 2027 in-service date for this pipeline expansion, considering Woodfibre's expected timeline?

Yes, we have been significantly expanding T-South, with the completion of a project last year costing around $1 billion for customers in Southern BC and the Pacific Northwest. The next major project will likely be linked to a significant offtake, and Woodfibre fits that description. Any new projects we initiate now would likely service by 2025 or 2026, which brings a lot of optimism. It’s a manageable project, and I believe they have a strong chance of success.

Alright. Great. And then just moving over to the crude oil business. The downstream expansion opportunities on Flanagan and Seaway, what are the gating factors to get these things more further along just given that Line 3 is now in service? And kind of has Capline, was there so changed any of the dynamics there just given ultimate avenues of flow?

Okay. Over to Colin.

Hey, Rob. Regarding our downstream projects, we've begun early work to ensure a quick in-service date. We'll be in discussions with customers about these projects. You should consider them alongside EHOT, as they are interconnected, and it would be beneficial to establish terminaling in Houston at the end of the process. Timing-wise, we're having parallel discussions in the industry. As we refine the Mainline tolling framework, it's clear how these elements will connect to guarantee access to the downstream capacity. There's definite interest in this. That's the timing we're considering. For other business development ideas, such as Ingleside and Express, those are progressing quickly, independent of the Mainline. Regarding Capline, we view it as more of an opportunity than a threat at this stage. We supply it from three of our pipelines, along with the Mainline and regional sources, so we don’t see Capline cutting into our volumes, for instance.

Thanks. They are moving about 100 a day. And I think that came off of rail and barge service previously. So, it didn't see it from our system.

Great. Appreciate the color. Thank you.

Thanks.

Thanks, Rob.

Okay. Thanks. Good morning. I was just wondering what are your updated thoughts on non-core asset sales at this point? I'm probably more curious about the more commodity-based businesses. Are you comfort just holding on to capitalize on increasing margins, or is this a good window to look on monetization?

Yes. Ben, generally speaking, on non-core asset sales, there's not a lot that fits that category. I mean, certainly, we could look at portions of our other assets, if we could see great value, we'd always look at that, and the team is always monitoring that. As far as the commodity-sensitive ones, there's really not a lot 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. And 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. It's a relatively small piece of our EBITDA as well. And it comes with a very large negative tax basis in that asset. So right now, I think we're pretty comfortable in just holding those relatively small pieces of commodity exposure.

Okay. Thanks, Al. And also, your comment around renewable returns coming down and being careful about future investments. I'd like to hear that. But what about also being opportunistic on maybe buying some of these junior renewable developments that could be challenged in terms of returns and inflation? Is there a window here to take advantage and going to new geographies, for example?

Yes. Well, you're right to point out that 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. And the reason for that is I think we've got, as I alluded to earlier, quite a bit going on in the business. And when you talk about the source of power opportunities, there's a number of what we call front-of-the-meter renewables opportunities, where we can bring our expertise to bear. We've got the projects that Matthew has been working on and developing for the last two to three years. So I think we've just got enough on the go right now to 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.

Okay. Great. And then maybe just a quick one for Colin, perhaps on the Wabamun project or maybe anything in Alberta CCUS. Do you need to get the CR involved at some point or Bill C-69, like how does that feed in at all?

We'll need regulatory permits physically as they develop. It's intra-Alberta situation doesn't cross the border. So, as Al said, while the whole industry will need clarity quickly on permitting on this whole new slate of projects, so we'll be advancing that in parallel. The ISDs for the emitters we're working with are relatively early in the relative scale of things in '25, '26. So, we've got some time to work on that, but...

Yes. I think you mentioned C-69, I don't think that applies here, I'm pretty sure about that, Colin, but if there's something different, we'll get back. But I don't think C-69 applies.

Okay. Makes a lot of sense. Thank you.

Okay.

Thanks. Good morning. The takeaway situation in the Bakken continues to look constrained. And I know in the past, you were evaluating an expansion of Alliance to accept more Bakken gas. I guess the question is where does that expansion stand today? And I know there's a bunch of competing projects, but is that something you're still pursuing?

Yes. We've been talking to producers on and off to meet over the course, really, of the last few years. And it's just a matter of getting the right concentration and traction we feel as though there's great connectivity and we bring the gas to the right place. So nothing to report as far as new contracts there, but we do keep pursuing that.

Okay. Great. And then, I guess, I was just wondering, if you could comment at least directionally on how either of the two commercial frameworks you're advanced on Mainline would impact your financials? I know you've embedded the reserve and the guidance for toll uncertainty. But is it fair to assume that, if you're able to advance either of the commercial frameworks, it would have a modest positive impact on your financials?

Sorry, can you repeat that last part of the question again?

Yeah. The last part is just is it fair to assume that, if you're able to advance either of the commercial framework, you would have a modest positive impact on your financials?

I think the reserve or provision really is our best guess of where we end up at the end of the day.

Okay. I think maybe – if I understood the question right, what Vern said is the answer really, with the provision, you can think of it as a neutral outcome. If we booked the provision as to the best outcome, we think there is or the most likely, I don't think we see much beyond on the upside or downside. So I wouldn't say that it's a modest positive effect is, as you had mentioned.

Yeah. I should reiterate that obviously, we think on the context of our consolidated EBITDA over $15 billion for 2022, any outcome is not material. I think the bigger takeaway here though is really what we said about the commercial outcomes. So we're quite comfortable managing a CTS-like environment. We've proven that for the last, I think, 25 years working on incentive-free making. But as I said earlier, we're equally comfortable, though, with cost of service. And so with the provision and the fact that cost of service would certainly minimize the risks that we were talking about, I don't want to say, we're agnostic, because I think as we were pointing out earlier, Colin was referring to, I think our shippers were probably happy moving on to a new CTS. So those are the things that we look at. It really is more of a commercial issue going forward here, given that we've booked the provision.

Got it. Thanks. And Bill, congrats on your retirement. Thank you.

Thank you.

Thank you.

Thanks. Good morning. Al, you kind of started at the beginning of the call framing the energy crisis that people are experiencing right now with high pricing and then also the producer discipline side of it. And I guess that's a bit of a two-edged sword for you. You can wind up with a lack of volume growth, but better counterparties. Just how do you see that translating to your business overall? And then does that really compel you to pivot faster into some of the energy transition activities?

Yeah. I think Andrew, where we see this is – as I alluded to there. It's pretty clear that the conventional runway is going to be there for a long time. At the same time, you've got pretty solid discipline we're seeing out there. I mean, there may be some upticks that you've heard about recently, particularly in the Permian around drilling and so forth. But generally speaking, producing community is not unhappy in our view, given where prices are and the fact that they're not really deploying a lot of capital and returning it back to shareholders. So, I think that discipline is going to be maintained. With respect to how we pivot, again, if you look at any of the three areas, as I said, RNG is probably the fastest growing but maybe lower capital investment opportunities there. But hydrogen and CCS are going to take some time. Policy-wise, incentive frameworks, that's got to still develop. So, I think we're going to have to be disciplined here and really focus on the two-pronged approach. Conventional energy will have a runway. We'll capitalize on those opportunities. But we'll also look to gradually invest in low carbon, providing that we can make those work economically and scale up over time. So, those are going to happen, but they'll happen not in the next two to three years, but after that, we'll certainly be scaling up those investments. Hope that's answer?

No, that does help. And then just a follow-up and really focuses on the producer health and the discipline they have at this point in the cycle, has that changed the dialogue that you have with them at this point in time in your customer focus, or is it more of the same from an Enbridge perspective?

I think it's pretty much the same. I mean we have a lot of dialogues across the four businesses with our customers on all kinds of issues. So, I think so far, their health has been very positive for our industry and us. We like the fact that they've sort of turned over and balance sheet has strengthened. And ultimately, I think that's going to be very positive for the industry, and they'll probably get back on to growth year outlooks. But as for the next two to two years, I think we're keeping in touch and being very responsive. And the CCUS project that Colin was talking about is a good example. There's a lot of producer interest in that, but we're being very careful to make sure that whatever we talk about with them has cost in mind in that, that will be a big driver on the growth in CCS going forward.

Okay. That’s great. Thank you.

Great. Thank you, and thank you for joining us this morning. We appreciate your ongoing interest in Enbridge. As always, our Investor Relations team is available following the call to address any additional questions you may have. So, once again, thank you and have a great day.

Thank you, ladies and gentlemen. We appreciate your participation. This concludes today's conference. You may now disconnect.