Enbridge Inc

TSX:ENB

Earnings Call Transcript 2020-Q4

[Operator]

Welcome to the Enbridge Inc. Fourth Quarter 2020 Financial Results Conference Call. My name is Jonathan, and I will be your operator for today's call. [Operator Instructions] Please note that this conference is being recorded. I would now like to turn the call over to Jonathan Morgan , Vice President of Investor Relations. Jonathan, you may begin.

[Jonathan Morgan, Vice President of Investor Relations]

Thank you. Good morning, and welcome to the Enbridge Inc. Fourth Quarter 2020 Earnings Call. Joining me this morning are Al Monaco, President and Chief Executive Officer; Colin Gruending, Executive Vice President and Chief Financial Officer; Vern Yu, 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 and Power. As per usual, this call is webcast, and I encourage those listening on the phone to follow along with the supporting slides. We're going to try and keep the call to roughly 1 hour but will allow for additional time if necessary. [Operator Instructions] We'll do our best to get to each of you. And as always, our Investor Relations team is available after the call for any detailed follow-up. If you are a member of the media, please direct your questions to our communications team, who will be happy to respond. On to Slide 2, where I'll remind you that we're 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 non-GAAP measures summarized below. And with that, I'll hand it over to Al Monaco.

[Al Monaco, President, CEO & Director]

Okay. Thanks, Jonathan. Good morning, everybody. So Colin and I are going to cover the usual agenda, including the business update, the financials and a recap of our capital allocation priorities. Given the challenging dynamics of energy today, we're also continuing our discussion on how we see the energy space. At the end, I'll tie it together with what you see here on the slide, which is how Enbridge is the bridge to the energy future and the value proposition that we're offering. So let me start with the energy landscape. As we said at Enbridge Day, we're cautious near term but very optimistic about the long-term fundamentals. We're in the heart of the second wave here so the timing of a full recovery is uncertain, and it depends on the speed of the vaccine rollout. But a strong recovery is bound to happen. It's also clear that the industry is fully aligned on the need to reduce emissions. We ourselves have established a net 0 target. And we've built optionality by diversifying our business and investing ahead of the curve on renewables, RNG and hydrogen, which will drive more infrastructure opportunities for us. But we also know that our economies are dependent on low-cost reliable energy. That's always been true and always will be. Stimulus is driving the right conditions for the recovery, and it's playing out if you look at the pickup in demand and stabilizing commodity prices. Good example is the growth we're seeing right now in Asian economies, and that's actually bolstering U.S. Gulf Coast energy exports. The fact is that all sources of energy supply are going to be needed to meet growing energy demand, and conventional energy and new investment in conventional energy is going to be part of that. We think Western Canada is really well positioned. Producers have lower breakevens, cut emissions and built a backlog of capital-efficient long-life supply growth. Developing greenfield egress projects is going to be challenging as it is today. So as new capacity is needed, the first call will be to optimize, expand and modernize existing infrastructure. That means the value of pipe in the ground is set to increase. We ourselves have plenty of opportunities in the hopper to support new upstream investment and energy export growth. Capitalizing on the value uplift though will depend on how good you are at environmental protection and permitting and the emissions reduction solutions that you bring to the table. So companies with scale, existing connections to prime markets, including exports, and world-class execution capability will thrive, others won't survive. The strategic location of our assets and the capabilities we've developed to operate in this environment means we're best positioned to win. So spending a minute on the energy outlook. We believe gas will be critical to any energy transition scenario you want to pick and future economic growth. Its abundance means it will be economic for a long time. It's got excellent load following capability on generation, lower emissions, and it will allow renewable generation to grow. Its fuel and density advantages are critical to industrial and manufacturing competitive. You've seen that play out globally as well. Demand was only down 4% versus 2019, and U.S. LNG exports have picked up nicely to 11 Bcf per day last month. The next slide hits home the fact that crude is also moving in the right direction. If you look at refined products, petchem demand didn't miss a beat last year, and gasoline and diesel are climbing back. Now jet fuel will take longer for obvious reasons, but it's a smaller slice of demand. You can see the massive 20 million barrel per day COVID impact on crude in Q2, so it will take some time to get fully back to normal. Oil exports held up well last year, around 3 million a day, but we remain bullish on the longer-term there in particular. Part of that is economic growth in Asia, which continues to invest heavily to kickstart their local economies. And all of this lines up well with our U.S. Gulf Coast strategy. We're starting to see customer interest to support export infrastructure pop back up. Global inventories are trending down, and with current discipline coming out of OPEC and U.S. shale production, we're seeing price stability. So what does all that mean to us? Our assets are positioned to benefit from growing energy demand, and that's because the strength of the markets we deliver to, including great connectivity to both gas and oil exports; the scale of the volumes we move; and the competitiveness of our tolls. As you saw this past year, the commercial underpinning and diversification of the assets generated strong and predictable cash flow. When you look at these 3 franchise maps, the utility-like nature of what we do really comes through. These businesses are absolutely critical to North American and global economies, and they'll be generating cash flow for a very long time. Our renewables business also fits the utility model very well. So that's how we see the big picture. Now let's have a look at last year and how it sets us up for this year. In short, we delivered very solid results and progressed our priorities. DCF came in about the midpoint of our pre-COVID guidance range, a good outcome, and it proves out the resiliency of the portfolio. You can see our track record here on the right in hitting the numbers over time and delivering constant dividend growth. On liquids, we lost 400,000 barrels per day of volume in Q2, but we mitigated a good chunk of that with cost reductions and a number of productivity enhancements. We drove about $300 million in savings, and the plan is to sustain that and add another $100 million this year. And by the way, we did not avail ourselves of government programs to get there. We brought $1.6 billion projects into service and started construction on Line 3 in Minnesota. We ramped up our ESG goals in both emissions and diversity. And we extended our 5% to 7% DCF per share growth outlook another year through 2023. So bottom line, in what has been the worst economic and energy downturn in decades, we grew cash flow, increased the dividend when others went the other way and we ended the year with an even stronger balance sheet. So let me move to the business update, starting with liquids. So fourth quarter Mainline throughput averaged 2.65 million a day, so we're seeing the return of volumes that we had forecast. That was driven by good WCSB response and strong pull from our heavy refinery customers. PADD II and U.S. Gulf Coast system utilization was up nicely, and it really shows the competitiveness of our system to the key markets. In fact, heavy Mainline capacity has been full since July, and we've been able to use up some available light capacity by optimizing the system to move mediums. What really shone through was the strength of the basin and our system. That has a lot to do with how critical our heavy feedstock is to our U.S. customers. And given we expect to see further decline in global heavy supply, heavies off of our full path through to the U.S. Gulf will be in big demand. You can see the highlighted path here in yellow. Next is our update on Line 3 and the capital cost refresh that we promised. The entire project underwent exhaustive review and vetting over 6 years. The record during that time we established is very solid. Our team worked extremely hard with indigenous partners, and we were responsive to community concerns. And that's why we have strong local and regional support on the ground. We got the final permits in Minnesota in late November and started early work in the field. Recent state and federal court decisions, once again, validated those permits. You saw the stays were designed -- denied at both state and federal level. I want to emphasize here that we are using the most fulsome environmental, health and safety measures possible. We made this a world-class project and the permitting agencies were focused on the very same thing. The right of way is mostly cleared, station work is underway, and trenching and welding has started. We'll manage through the spring environmental windows, as usual, which have been accounted for in our Q4 in-service date estimate. So lots of work ahead on this one. And we've reiterated to our execution team that environmental protection and safety are the #1 priority here. That includes stringent COVID measures. The next slide shows our cost estimate for the entire project and now reflects our final post-permit construction plan in Minnesota. From the last estimate in 2017, capital has increased from $8.2 billion to $9.3 billion or 13%. We actually came in very close to our budget on the vast majority of the projects. So that's great. This increase really stems mainly from our revised execution plan related to regulatory and permitting processes in Minnesota. So let me explain that. As you know, the plan changed to winter construction, which means more manpower and equipment. The days are shorter, productivity is lower, and there's seasonal transition from winter to spring. And remind you as well though that winter construction does come with some benefits on the environmental side. We also implemented even greater protection for wetlands, increased erosion controls, and we're using the most conservative crossing techniques. Obviously, the regulatory delays, monthly running costs and carrying costs were higher. Finally, scope changes like rerouting onto the Fond du Lac reservation and COVID protocols were needed. So not surprising, costs have gone up, but a couple of things we want to note here. Despite this higher investment, our updated full cycle return remains attractive, and we're seeing a stronger volume profile. And lower interest rates versus the original economics has helped. Once Line 3 is in service, it's going to contribute a lot of free cash flow, and this year, we anticipate it will be about $200 million in Q4, with volumes and EBITDA ramping up in 2022. So on to Slide 12. Mainline contracting is progressing through the regulatory process. We're currently in what we call the evidentiary phase, which ends in April. And from there, we expect a hearing and decision this year. There's been a lot of commentary recently on Mainline contracting, but the bottom line is that we're moving forward with it because it's what our customers want, and that is dedicated capacity and toll certainty, and that's why we have strong support. And the offering reflected numerous changes, as you know, so that all shippers will be better off. So we're continuing to move our application along, and we're looking forward to the hearing as that will help us get the facts out on to the table for everyone. On Line 5, a couple of comments on the state's attempt to revoke the straits easement that was granted decades ago. First of all, the fact is that the straits segment is safe and PHMSA has confirmed that more than once. Secondly, the line is absolutely critical to Michigan and the entire surrounding region, and in our view, attempting to cancel the easement contradicts the U.S. federal jurisdiction over safety of the line. It would severely hinder both interstate commerce and North American energy flows, but most important, it endangers the energy security of millions of people and industry in the entire region, resulting in higher consumer costs and lost jobs at the worst possible time. And let's remember that Line 5 moves existing volumes so shutting down this line is a very serious issue for everybody. One thing that's been lost in all of this is that we are just as or more committed to protecting the Great Lakes than anybody. We've proven that by taking numerous additional actions, listening to the state's concern very carefully to make a safe pipeline even safer; for example, 24/7 monitoring of vessel traffic in the straits, replacing the St. Clair crossing, shutting down the line during periods of high wave conditions and a bunch of other measures, too many to go through today. We then committed to build a tunnel under the straits to house a brand-new line that will reduce the risk to near 0, and that tunnel was blessed by the state government. On that front, we received initial environmental permits, and we're working on the remaining 2 approvals. Finally, just a quick point here on a development area for us, which is carbon capture. And just for context here, this has a lot of power in terms of reducing emissions. So by 2035, there's a potential to store 22% of GHGs, and that's the case on both sides of the board. Transportation is a key part of any carbon solution, which fits our skill sets very well, and it's a big opportunity for us actually. We're going to be focused initially on Western Canada, where there's strong interest in an industry solution. I'm talking pipe and facilities there. So more to come on that one in the months ahead. Now let's move to our natural gas businesses, which are a key part of the diversification I talked about earlier. In terms of gas transmission, last year was strong and this year looks better as a bunch of projects come into service in the second half. Renewals on Texas Eastern and Algonquin came in at 99%, which just shows how critical these systems are to U.S. Northeast energy needs, especially on peak demand. Everybody's noticed how cold it is out there. The team did a good job of settling new rates as well with our customers so they're happy, which added a good chunk of EBITDA for us in the process. We completed last year's $700 million modernization program, which is part of a recurring investment opportunity going forward that Bill talked about at Enbridge Day. We've got $5 billion in execution through 2023 of solid return projects that are moving along well. $3 billion of that, by the way, is slated for in-service this year so that will contribute to growing free cash flow. On to Slide 14. The gas utility put up good numbers again and keeps on giving on growth. We added 43,000 customers last year, and synergy capture in that business is on track. So we're generating a good premium return above the allowed regulated rate. There's another $4 billion of utility rate-based capital through 2023. Part of this is new community expansions, those are the white dots you see in the map here; and in franchise replacement projects. On low carbon options, we've got 6 RNG projects operating and in construction and more planned. On hydrogen, we're piloting a 2% hydrogen blend facility, and most recently, Gassafair, that's our utility in Québec, is working on a similar pilot. By the way, the RNG and hydrogen projects are either included in rate base or have long-term contracts so they fit the business model. Finally, let's talk renewables, specifically offshore wind. Offshore France construction is well underway now on the 480-megawatt Saint Nazaire project. We've kicked off now the 500-megawatt Fécamp wind farm. We expect those to be cash flowing in 2022 and 2024. Next up is the 450-megawatt Courseulles project, which should reach FID in the first half of the year. Some nice development opportunities we're working on as well, including an expansion of our operating Rampion project in the U.K., and that's a 1.2 gig project; and another project in Dunkirk, offshore France as well. An exciting area of future growth for us is floating offshore wind. Matthew covered that at Enbridge Day. And we're actually working on a pilot project on the south coast of France, and this could actually turn into a pretty big opportunity for us going forward. As everybody knows, renewable valuations these days are frothy to say the least, so that's good for the value of the business. But it also means that returns are being crunched down on new opportunities. So it's nice to have a backlog like we do of construction and development projects, and we're not going to stretch our investment criteria on risk or return. The next slide shows how we're also ramping up our solar cell power program into high gear. We really like these projects because the strategy marries up renewables experience with our gas transmission and liquids franchises, and it reduces our carbon footprint. You can see we've got 15 to 20 projects here totaling several hundred megawatts, so roughly $0.5 billion of investment through 2023 and more beyond that. Now these projects are not just on the drawing board. In October, we completed Lambertville on Texas Eastern, and another one is on the go on Texas Eastern as well right now. And we've just started our first project for the Mainline in Alberta. We've got several late-stage development here which could FID this year. Now just stepping back for a minute in terms of how we look at these from an investment perspective. You have to remember that power costs are one of the largest operating expenses we have. To the extent we can effectively deploy capital and earn a good return to reduce cost and emissions, we're going to do that. And these projects, by the way, compete for capital just like the rest of the organic growth that we have, and we'll prioritize the best ones. It's a good segue on to ESG. As you know, we set emissions goals last year to net 0 by 2050 and a 2030 interim intensity goal of 35% reduction. We spent over a year landing on these and the levers to make sure we hit these targets, so not pie in the sky at all, and they're linked to executive compensation. The 3 primary ways we'll get there is using less carbon-intense sources to run pumps and compressors; self powering with solar, like the projects I just went through; and modernizing our assets with the latest technology. Maintaining our ESG leadership position is really important to us, I think everybody understands that, not that we can put that on a slide but because reducing emissions is part of our business. And it supports the lowest cost of capital. You'll see here we've just added a couple more sector-leading scores from S&P and Wells. So let me conclude the business update by reiterating the 3-year growth outlook of 5% to 7% DCF per share CAGR through 2023. First, there's 1% to 2% of highly visible growth from the revenue and cost lines, very little capital required on that. Embedded revenue escalators in liquids and gas are part of it; watching our overhead, which we've done a good job at; and importantly, leveraging technology to improve productivity and optimize our operations. That has real bottom line impact, and we went through those at Enbridge Day. Another 4% to 5% will come from completing the $16 billion secured capital that we expect will generate a couple of billion of EBITDA through 2023. If we execute as planned, we'll have $5 billion to $6 billion of annual financial capacity starting after Line 3 goes into service, so call that 2022. As we've been saying, we'll be very disciplined in the way we put that capacity to work, which Colin is going to cover and recap our approach to that. So Colin, over to you.

[Colin Kenneth Gruending, Executive VP & CFO]

Thanks, Al, and good morning, everyone. I'm going to provide some color on our financial results; our secured capital and funding plans; thirdly, our performance outlook for 2021; and then finally, how we'll allocate capital to maximize shareholder value. But first, I'd like to take a quick step back and assess our 2020 performance with this simple dashboard. The punchline is we're stronger, resilient and growing. Our balance sheet metrics are in good shape and give us flexibility. We're right where we want to be here. Our counterparties and the contractual nature of our cash flows have always been good, and they remain so, if not even a little better again here. Our proactive actions to reduce costs will also give us a competitive edge. And cash flows and our dividend are growing amidst challenging market conditions. So while it's a tough year for energy, we're entering 2021 in a position of strength. On to Slide 20 for our results. 2020 was a strong year, as Al mentioned, both operationally and financially. Gas transmission, our distribution utility and our renewable power assets were all highly utilized even through the pandemic. They delivered right in line with or better than our 2020 guidance. Liquids Pipeline throughput was solid overall and recovered quickly, demonstrating the strength of the markets we deliver to. And of course, early actions on costs helped to offset most of that impact. Full year adjusted EBITDA landed at $13.3 billion, which is right where we guided to, and we updated you on December 8. After factoring in unrecognized demand charges on unutilized capacity, we would have been at about $13.5 billion, and there's a similar impact there on our earnings, about $0.10 per share. We do not expect this last factor to be a material one in 2021 as volumes have mostly recovered. DCF per share of $4.67 is just above the midpoint of our guidance range, which we provided well before the pandemic. That's a solid outcome in any year. Turning to Slide 21. I'll walk through each of the segments. Liquids Pipelines full year EBITDA is up almost $140 million over last year despite the pandemic-related volume loss. This increase is largely driven by our annual toll inflator on the Mainline; a $0.20 surcharge for Line 3 Canada, which has been in service for a while now; lower operating costs; and stronger U.S. dollar exchange rate ratios on U.S. earned cash flows. Regional oil sands volumes are recovering in line with Mainline volume recoveries. And as a reminder, our regional business has strong commercial take-or-pay underpinnings. Further downstream, high demand for Canadian heavy barrels into the Gulf drove increased full path volumes on our Flanagan South and Seaway pipelines. But we did see lower light spot volumes on Seaway legacy system, which was a slight headwind in the quarter. Finally in this segment, a reminder that Gray Oak pipeline began full operations in the first quarter of the year, providing incremental take-or-pay EBITDA all year. After factoring in the makeup rights matter I mentioned on contracted assets, this segment's results were right in line with our pre-COVID plan. Similarly, in Gas Transmission, full year EBITDA was up $27 million. Our assets in the U.S. and Canada benefited from the rate case settlements in 2020 on Texas Eastern, Algonquin and the BC Pipeline system, which we discussed earlier in the year. As a reminder, these 3 rate cases -- or rate settlements, I should say, combined provide an incremental $160 million of EBITDA on a full year run rate basis. As another reminder, 2020 results for this business include about $100 million of prior period catch-up revenues related to the settlement of these rate proceedings in midyear 2020. The benefit of these rate settlements in U.S. Gas Transmission was partially offset by higher integrity costs and lower revenues due to pressure restrictions in the third and fourth quarters related to our system-wide integrity program. That program is substantially complete and the system is back to full operating capacity, but we do anticipate integrity costs will still run higher in 2021. Our utility EBITDA was up a little despite a warmer year. Actually, the weather delta year-over-year full year is significant. It's about $100 million when you compare a warmer 2020 with a colder 2019. Weather normalized, the business grew ratably, adding 43,000 new customers, which is in line with historical trends. $500 million of new capital placed into service, higher distribution rates, and we're making good progress on amalgamation synergies. This predictable growth is again reflected in our 2021 guidance. Our renewables business was up also $80 million over last year, and that delivered results consistent with full year guidance. This includes contributions from the 2 German offshore wind farms placed into service in late 2019 and early 2020; good wind resources at both our Canadian and U.S. facilities; and finally, about $40 million in insurance-related settlements. Energy Services, which is typically a small contributor to the whole company, say 1% of consolidated EBITDA, experienced a loss of just over $80 million in the quarter and full year results were below our 2020 expectations. Now that's consistent with what we said in December, where basically, we'd continue to see compressed location and quality differentials into 2021 which create fewer opportunities to generate sufficient margin to cover fixed demand charges on our portfolio of commitments. More recently, at the margin, we're seeing some improvement in market conditions, but all in, we continue to expect to be about neutral in 2021; roughly speaking, minuses in the first half and this EBITDA contributions in the second half from the small business. Finally, eliminations and other was $40 million favorable to last year on better foreign exchange hedge settlements and the corporate portion of the $300 million of enterprise cost reductions for 2020. Now on to Slide 22 for our distributable cash flow reconciliation. Cash distributions received from our joint venture investments, maintenance capital, financing costs and distributions to noncontrolling interests are all roughly in line with expectations in our full year guidance for the year. Income taxes or cash taxes in this case on the year are comparable with 2019 but slightly lower than our initial guidance due to lower taxable earnings during the year. And I think I've mentioned the normal course add-back of cash receipts related to makeup rights reported within the full year. This was more of a Q2 and Q3 event, quite negligible in Q4. Now with that, I'm going to shift focus forward here now, beginning with our secured growth capital program. As you can see from the table on Slide 23, we've got a solid $16 billion of secured capital program that provides visibility to our 5% to 7% DCF per share growth outlook through 2023. Our program is well diversified across each of our businesses and comes with contractual frameworks that fit our low-risk model. We placed $1.6 billion of utility and utility-like projects into service in 2020 and so far this year, including our 2020 gas modernization program, which will be ongoing. 2021 is shaping up to be a big year for execution with about $10 billion of capital expected to be placed into service, and some of that is already incurred. This includes the Line 3 U.S. project and a number of smaller expansions within our gas businesses. This economic activity is, of course, well timed and should help stimulate economies in the regions we operate. Execution on our program will set us up nicely for significant cash flow growth in '22 and beyond, further bolstering our strong financial position. We exited 2020 well within our target range for debt-to-EBITDA at 4.6x, and we've got ample excess liquidity. This gives us more than enough capacity to manage Line 3 spend and still remain inside our target of 4.5 to 5x range. And yes, we're doing this still on a self-equity funded basis. Project execution is going to provide us with even further financial flexibility going forward, as you can see in the middle chart. By the way, we've been updating the rating agencies on our funding plans, and we believe they're comfortable with our outlook metrics and current ratings. In connection with our ESG strategy that Al mentioned, earlier this week, we entered into a 3-year $1 billion sustainability-linked credit facility, which is a first amongst our peers. We're excited by this financing as it links our ESG performance with our borrowing costs and, in our view, solidifies the metrics all companies will need to pay attention to. And these metrics, of course, are also tied to management compensation so we're aligned to our ESG leadership on multiple fronts. And concurrently, given 2020 -- 2021 prefunding actions conducted in 2020, we have given notice of early cancellation of the $3 billion credit facility entered into last March that, at the time, provided extra liquidity cushion during the early days of COVID. On to Slide 25, and I'll quickly recap our outlook for 2021. While it's early, we remain confident in our 2021 outlook we provided in December. We're seeing the strong performance from Q4 continuing to this year. Mainly -- Mainline volumes are recovering in line with our expectations. Line 3 construction in Minnesota is progressing well. And as a reminder, we're anticipating $200 million of EBITDA contribution in Q4 2021 once the U.S. portion is in service, and that's, as a reminder, on top of the Canadian portion surcharge, which is earning in Q1 to Q4 already. In Gas Transmission, both the T-South and Spruce Ridge expansions on the BC Pipeline system are on track for service dates in the back half of the year. And our utility continues to realize synergies and add customers predictably year-over-year. In terms of headwinds, the outlook for Energy Services remains a little bit challenged. Finally, I thought I'd provide you my perspective on a few evolving issues that are attracting attention in the market macroeconomically. Foreign exchange translation. We've seen the U.S. dollar weaken relative to the Canadian dollar, and we're now in the $1.27 exchange rate area. While we do have some FX exposure to cash flows, I would say, around the edges, we are largely hedged in 2021, 90% on an earnings basis and about 2/3 on a cash flow basis at a hedge rate in the area of $1.28. And so the impact of any further weakening of the U.S. dollar should not have a significant impact on our outlook for the year or really the next few years as we've got a laddered portfolio of hedges. Our guidance for '21 and our plan assumes $1.30 on the unhedged exposure, so we are relatively insensitive to foreign exchange. In terms of the sensitivity, every $0.01 exchange rate variance equates to about $0.01 of DCF per share. I should mention too that from a balance sheet perspective, a weakening U.S. dollar will have the effect of reducing our translated U.S. debt balances, which, in combination with our hedged cash flows, may be a positive tailwind for our credit metrics in that scenario. In the event that corporate tax rates in Canada or the U.S. rise at some point, we do not expect a big impact on our cash taxes over the planning horizon. And that's because we have significant existing tax pools and growing in Canada and the U.S., and those will also get revalued upwards if tax rates increase. Plus we have, of course, regulatory frameworks in many cases that allow recovery of higher tax rates just as these revenue allowances were adjusted downward a few years ago. In terms of counterparty risk, the strength of our counterparties is league leading, which was demonstrated earlier this year during the pandemic. Many of our counterparties have taken steps to improve their cost structures and have exited 2020 in a stronger position. However, our ultimate credit protection is the strong demand pull nature and high utilization rates of our Trunkline assets. This is now reproven out as well. Finally, we are well protected against rising inflation in both Canada and the U.S. if or when it may manifest. As a reminder, about 65% of our revenues have some type of embedded rate escalator that is tied to different inflationary benchmarks. Moving on to Slide 26. So I'll briefly remind you of how we are allocating capital to drive efficient growth. Protecting the balance sheet remains our top priority. This is not going to change. Similarly, ratable dividend growth is central to our value proposition, and that's not going to change either. Finally, as we went through in detail at Enbridge Day, we have a healthy hopper of organic projects consisting of low-capital-intensity expansions and executable optimizations and regulated utility and gas transmission modernizations. We expect to deploy $3 billion to $4 billion annually on these high-confidence opportunities. The remaining $2 billion per year will be allocated dynamically to the next best value-add opportunities at the time. Traditional longer-dated organic growth is one option, but those projects will need to compete head on with share buybacks. And as a reminder, at current valuation, share buybacks remain attractive. This dynamic approach ensures we're maximizing value for shareholders and supports our growth ambitions. With that, I'll turn things back to Al to wrap up.

[Al Monaco, President, CEO & Director]

Okay. Colin, thanks. I'll come back to how we began the call here. If you go back when we established the Enbridge name years ago, it illustrated the fact that we were building energy bridges between low-cost supply and the most important demand-consuming markets. I think we've built strong bridges, and we're proud of providing the energy that fuels everybody's quality of life and drives our economy, and that will be true for a long time. But today, our name also conveys something else, which is how we're positioning Enbridge as a bridge to the energy future. It's clear that energy systems are transitioning just like they have over time, which is why we started diversifying our mix over 2 decades ago, adding more natural gas and building a renewables business from scratch. Today, we're investing in low-cost options to develop hydrogen and renewable natural gas and as well looking at carbon capture, and we're reducing our environmental footprint and targeting net 0 emissions. As we do that though, we'll continue to generate predictable and reliable growth and are hyper-focused on returns and protecting the low-risk business model. The $16 billion of secured growth gives us that transparency that Colin mentioned of 5% to 7% DCF per share through 2023. So when you combine the growth outlook, the attractive dividend yield today, the potential for capital appreciation with how we bridge to the energy future, we think Enbridge provides a very compelling value proposition for investors and all stakeholders in any energy market. So with that, we'll turn it to Q&A. And Jon mentioned we would extend beyond the hour if people wish to stay. And I'll sort of quarterback the questions given that we're in different locations. So operator, please proceed with the Q&A.

[Operator]

[Operator Instructions] Our first question comes from the line of Rob Hope from Scotiabank.

[Robert Hope, Analyst]

Questions on Line 3. So can you just give us an update on how you think construction is progressing so far just given what looks to be favorable weather aside from the last couple of days here? And then as we look forward, what are the key gating factors in terms of construction that we should be looking for? Is it going to be the water priority crossing? Or is it just getting the miles of pipe in the ground?

[Al Monaco, President, CEO & Director]

Vern, do you want to take that?

[Dai-Chung Yu]

Sure. Rob, I think construction is progressing really well. Obviously, the warm weather has helped us so far, but that's changing now. So what the -- we're welding pipe on 7 spreads right now. We've got tents erected at each station so we're able to progress work through the winter. I think the things that you've highlighted are all the things that we'll be looking out for as we finish construction over the balance of the year. Don't forget we do have a short tools-down period for environmental windows. So still early days, but I think so far, things are going better than we had hoped for.

[Operator]

Our next question comes from the line of Jeremy Tonet from JPMorgan.

[Jeremy Bryan Tonet, Senior Analyst]

I just want to kind of pick up maybe on part of the conversation Colin had there with regard to capital allocation. It just strikes us after Line 3 completion that, that provides a lot more flexibility post that. I'm just wondering how your thought process might evolve at that point because there seems to be a lot of nice bite-sized M&A opportunities out there like you've done recently. There's also a very sizable offshore and solar opportunity, as you discussed there. Yet, kind of the ENB valuation would also argue for more share buybacks. So once all this extra cash flow starts hitting, how do you guys think about these different opportunities at that point?

[Al Monaco, President, CEO & Director]

Okay, Jeremy. Well, let me start out, and Colin can add if I miss something here. So the way we're thinking about this -- first of all, you've got it right, post Line 3, and as I said in my remarks, call it, 2022, we're going to have a lot of cash coming at us and very good financial capacity in total if you include where we are on the balance sheet. So we're in good shape there. So the way we're thinking about it is really this way. We have probably, I would say, $3 billion to $4 billion a year of what we call real sort of primary utility-like investments.So if you look at Bill's business in transmission, Cynthia's business in the utility and Vern's business and of course, even power now, they all fit the utility mantra, if you will. So we know how we'll recover capital on those and over what period of time. So you can look at that and say that's pretty solid and that's going to drive some very ratable growth. Now beyond that, and this is, I think, what Colin was getting to around being dynamic, because you're right, at this valuation, buybacks certainly come to the front of the decision-making process. So we're going to -- depending on where we are in terms of several factors when we look at buybacks versus organic growth, we'll pick and choose. And so you'll have probably a couple of billion dollars of capacity to determine what the best angle is for that deployment. And as I'm saying, I think buybacks have certainly moved up higher in the rating corridor. Does that help?

[Jeremy Bryan Tonet, Senior Analyst]

That's very helpful. And just the M&A opportunities, do you see more of those? Or are those very kind of select small things?

[Al Monaco, President, CEO & Director]

Yes. I think we've been saying the smaller sort of tuck-in things around asset deals is probably most likely for us. If we see an opportunity there that we can bolt on or extend the franchise and give us better growth in the base business, we'll look at those. In terms of large-scale M&A, I think we've been pretty clear that's a low priority for us. We've done the repositioning we wanted to with the Spectra acquisition a few years back. But it kind of comes back to what Colin said around the low-capital-intensity organic growth. We've got plenty of that. The balance sheet is in very good shape now. We want to protect that. And the reality is, Jeremy, that there's not that many targets that really fit our business model. So the last thing we want to do is dilute that utility low-risk business model. So that's our perspective on M&A generally.

[Operator]

Our next question comes from the line of Robert Catellier from CIBC Capital Markets.

[Robert Catellier]

I'm going to ask a question related to the Mainline. I just wanted to know if you could comment on the additional storage assets acquired at Cushing and how those might enhance the value of the Mainline proposed contracting for shippers and whether there's any other opportunities such as storage, further upstream. And then related to that, I'm curious as to how aggressive you think you can be in the U.S. Gulf Coast strategy before you have Mainline contracting certainty.

[Dai-Chung Yu]

Rob, it's Vern. I think the recently acquired storage assets were quite helpful to the system as a whole because it just gives us more optionality for our system overall. And the real nice benefit is that those tanks are already plumbed into our existing network and we can capture cost and commercial synergies right away. I think more broadly, there's lots of opportunities for more tanks upstream. I think we've been working with industry on trying to establish a bigger hub in Flanagan and other points on our Mainline system. I think, as we've seen with demand and supply disruption over the last year or so, having more physical assets is beneficial to our customers. We're seeing strong interest. And that's particularly true on the U.S. Gulf Coast, where, because of the decline in foreign heavy crude production coming into the Gulf, there's more demand obviously for Canadian heavies. And as you bring more heavies in, you want to have the ability to blend crudes, create the specific crude slates that the refineries want on the Gulf Coast. And you also want to have the optionality of moving that crude offshore. That gives producers more strength when they're negotiating with refiners about month-to-month crude sales. So we are seeing some very good interest in our Houston -- Enbridge Houston Oil Terminal. We're seeing renewed interest in our joint venture with Enterprise on the spot export terminal. And we expect to see some really good interest on more pipeline demand coming down from the U.S. Midwest into the Gulf Coast here in the next few months. So I think the fundamentals are really lining up nicely for us to be able to grow our assets on a relatively low capital basis, and we provide a lot more optionality for our customers.

[Robert Catellier]

And Vern, there's nothing about the Mainline contracting process that would make you hesitate to make further investments in the U.S. Gulf Coast strategy?

[Dai-Chung Yu]

Yes. Our Mainline contracting proposal in front of the CER really dovetails nicely into being able to provide international joint tariffs all the way from Canada to the Gulf Coast for potentially incremental volumes on our system and growth on the Flanagan South and Spearhead -- Seaway and Spearhead pipelines. So that is going to be critical for all of our customers to see that you can see a joint tariff all the way down the line.

[Operator]

Our next question comes from the line of Robert Kwan from RBC Capital Markets.

[Robert Michael Kwan, MD & Energy Infrastructure Analyst]

Maybe I'll stick with the Mainline here. I'm just wondering if I can get some additional thoughts on top of what you set out earlier on the call specifically if you see the fate of Keystone XL factoring into CER's decision-making process. And I guess that's the first. The second being, have you had any discussions with shippers on a contingency basis on kind of the fallback to either negotiated tolls or even cost of service flowing framework in light of the new L3R costs, which presumably would drive rate base and tolls higher? And then the third being, again, if you're in that negotiated or cost of service framework, what cost of capital you might be seeking, given there's been some clear market signals that the cost of capital for oil pipelines has moved materially higher.

[Dai-Chung Yu]

Robert, I'll see if I can answer all of those. So our path forward is really that we're going to continue with our Mainline contracting regulatory process with the CER. We've seen interveners file evidence, and we've now been able to ask questions about that evidence that they've filed. And we will have an opportunity here to respond. So if we back up and just remember that's over 75% of the volumes that move on the Mainline today are supported with Mainline contracting, it provides certainty of capacity. It reduces the amount of apportionment on the system. We get certainty of tolls. And it allows us, probably most importantly, to grow the system over time because there's a mechanism available for us to, as I mentioned earlier, provide joint tolls all the way to the different markets. That's job 1, is to continue on in that process. And we think we filed a very strong regulatory case for that. I think you are right on that there has been some good precedence, particularly in the U.S., for allowed rates of return on oil pipelines to be higher than what people think they have been in the past. We will be filing U.S. tolling on our Lakehead System over this year, which will demonstrate that we're currently significantly under-earning on that portion of the pipeline system. So the higher L3R costs would go into those filings. But I should remind everyone that for Line 3, it is an attractive toll surcharge on every barrel that flows on the system. So I think we have some really strong regulatory precedents, particularly in the U.S., that supports that the toll that we're looking for in Mainline contracting is just reasonable. So hopefully, that answers your question, Robert.

[Operator]

Our next question comes from the line of Shneur Gershuni from UBS.

[Shneur Z. Gershuni]

I was wondering if we can focus on Slide 26, the capital allocation slide. Just sort of thinking about capital allocation beyond '21. It sounds like in the answer to one of the former questions and as outlined on the slide that you're sort of expecting $2 billion of the $6 billion to be towards buybacks, balance sheet, strategic investments. So I kind of wanted to focus on the $3 billion to $4 billion of long-term growth, sort of against your target of 2050 and the whole energy transition trend. At the same time, I understand you want to be a reliable transporter of traditional energy, and that does require continued investment. Should we expect the $3 billion to $4 billion to be primarily focused towards renewable and energy bridge transition-oriented investments? Do you have different return profiles given the longer terminal value versus traditional legacy investments? Can you sort of walk us through the lens that you're looking at that? And are you finding opportunities that will allow you to hit your target of a 5% to 7% return profile?

[Al Monaco, President, CEO & Director]

Okay. So Shneur, it's Al here. Yes. I think the way the lens comes out on this is in that $3 billion to $4 billion, let's call it, utility-like category. We believe that in any scenario that we see, from the fundamental perspective on supply and demand and the need for energy just given the length of transition that's required for moving energy systems along, utility investments, whether it's our gas utility in Ontario or Bill's transmission business, is going to come with very strong commercial underpinning, whether it's strictly regulatory or contractual, that gives us a high degree of confidence around return on and of capital. I would put renewables in the same category though, as I mentioned in my remarks, because they really come with the same kind of contractual underpinning. So I would say out of the utility category, whether it's gas utility or gas transmission and the renewables category, it will be a question of what's the best opportunity to ensure that we're going to generate the best risk-adjusted return. You might favor renewables, depending on the situation, particularly if it's offshore Europe, where we have good opportunities to grow there. But generally speaking, we think we can accommodate what we need to from an infrastructure point of view for our customers with that $3 billion to $4 billion in both the utility and renewable category.

[Colin Kenneth Gruending, Executive VP & CFO]

Can I tie in one point in there?

[Al Monaco, President, CEO & Director]

Yes, go ahead.

[Colin Kenneth Gruending, Executive VP & CFO]

Sure. So within that $3 billion to $4 billion, for example, in Bill's business, it's got maybe $700 million a year of modernization capital, right? That is consistent with transition. Those expenditures are basically reducing emissions, which I think is consistent with some of our other goals, and we're going to have it in rate base. So I think it's an example of how these objectives are consistent.

[Shneur Z. Gershuni]

No, that makes perfect sense. And I appreciate the expanded color on that. Maybe for a follow-up question, just wanted to focus on Line 3 for a second here. When you established your balance sheet and CapEx targets for '21 at Investor Day, did you already have a sense of the material step-up in Line 3 CapEx? Or were the only like open questions really related to the fact that it was going to be winter construction and COVID-related costs totaling about $500 million? Just trying to understand what was known at the time and sort of like what's changed. And did I understand your answer to the prior question, I think it was to Robert, that it could actually be recoverable in rates over time?

[Colin Kenneth Gruending, Executive VP & CFO]

Shneur, it's Colin. So yes, at Enbridge Day, we had a good sense the cost estimate was moving up. And I think we signaled that and we've -- the last couple of months, refined and finalized those plans, working through a few moving parts yet as we receive the final permit conditions just days before our Analyst Day, right? So we had a bit of a placeholder, I think, in our thinking. We've refined it since. We've been sharing those funding plans with the rating agencies along the way, and they've been kept up to speed.

[Dai-Chung Yu]

I can answer the second.

[Al Monaco, President, CEO & Director]

Sure.

[Dai-Chung Yu]

So Line 3 is a toll surcharge for 10 years. After that, all the capital will go back into rate base.

[Shneur Z. Gershuni]

Okay. So to clarify, the rating agencies knew exactly kind of where we're at so there shouldn't be any surprises there. And then in 10 years, you should be able to start recovering.

[Dai-Chung Yu]

Yes, on the rate base for sure. But I would point out, we're making a very attractive return on the project even with this capital cost overrun in the first 10 years.

[Al Monaco, President, CEO & Director]

Yes. And back to the first part, just to confirm. Colin and his team obviously are very intertwined with rating agencies, and we keep them up to date, I'm going to say, almost monthly on whatever's going on in the business. So good connection there.

[Shneur Z. Gershuni]

No, that makes perfect sense. I just wanted to make sure that everything was buttoned up, and it sounds like it is. Perfect.

[Operator]

Our next question comes from the line of Patrick Kenny from National Bank Financial.

[Patrick Kenny, Managing Director]

Just on the carbon pipeline and storage opportunity, it looks like it has good potential on both sides of the border over the long term. But are you expecting any funding support from the various governments anytime soon on these initiatives, either at the provincial state or federal levels? And I know it's early days, but perhaps you can comment on how meaningful this opportunity could be in terms of accelerating some of your emission reduction targets, either reaching the 35% reduction goal well before 2030 or perhaps you keep the 2030 target but you're able to exceed that 35% by a certain amount.

[Al Monaco, President, CEO & Director]

Yes. Let me start, Patrick. So I think the way we'd characterize it -- you're right, it's early. Let me characterize it though as there's some pretty good inertia around carbon capture from the government side of things, whether it's provincial, federal or at the state level. One of the things we've been encouraging from a policy perspective is -- just given the cost carbon capture and the fact that, as you know, it's out of the money currently, I think we've encouraged people to think about the U.S. system with the 45Q support that is provided there. If we did something similar in Canada, I think it would really be helpful. But overall, I think the support that we're hearing from governments is quite positive on this front. We have a decent shot of exceeding the 35%, I would say, so far. I mean it's a little early to tell on that front. But when we came up with the targets, we had a dynamic process where we could optimize the pathways that I mentioned in my remarks, and we'll be pushing them along hard. So hopefully, we'll be able to exceed. But I think it's a good starting point, and we've got, as I said, a number of levers to get there. Do you want to add anything, Vern, on carbon capture?

[Dai-Chung Yu]

Yes. I think carbon capture's not going to be material for us to meet our emissions targets. It's really about helping our customers reduce their carbon footprint. So I think there's a big opportunity to provide a network for carbon pipelines in highly industrialized areas such as the oil sands, where we can then capture a significant amount of carbon and move it by pipeline to a series of storage areas. And I think, as Al mentioned, carbon incentives such as Q45 (sic) [ 45Q] would be very instrumental in making that happen. And we do have a little bit of funding right now from some of the provincial and federal governments to just kick off work on how we could create a model that would work for both our customers, ourselves and potential downstream users of carbon as we move forward.

[Operator]

Our next question comes from the line of Andrew Kuske from Crédit Suisse.

[Andrew M. Kuske]

Obviously, you've got a lot going on in the liquids business, with a clear focus on L3R, contracting the Mainline and then Line 5. But when you get through all of that, how do you think about Southern Lights on just a longer-term basis as the contracts start to roll off on that asset?

[Dai-Chung Yu]

Well, I think what we talked about, Andrew, at Enbridge Day was once we're through our near-term initiatives, there is a possibility of growing our network fairly substantially over -- through a series of things. And Southern Lights is one of those things. And from my perspective, the biggest factor for Southern Lights is what is happening with condensate in Alberta, will there be enough condensate coming from some of the nonconventional oil play --- oil and gas plays in Alberta to replace that condensate coming out from Southern Lights. So that will be a key focus for our customers probably over the next year or 2 on determining what is the best way to supply the oil sands with condensate. And if they feel comfortable with that indigenous condensate production, I'm pretty sure they will put their minds to the reversal of Southern Lights.

[Andrew M. Kuske]

And if I may, just a follow-up. How do you think about the connectivity on things like Capline?

[Dai-Chung Yu]

I think we -- there's lots of options at Flanagan to move crude to various markets. Capline is an option. We do have quite a bit of expandability that's available on Flanagan South as well, and the Southern Access extension, obviously, could be expanded as well. So I think we have some good optionality, and we'll probably be focused on our own projects first.

[Operator]

Our next question comes from the line of Praneeth Satish from Wells Fargo.

[Praneeth Satish, Senior Equity Analyst]

Just on Line 3, I see the surcharge is $0.895 per barrel. Just will this surcharge be flat or change over the 10-year period? For example, are there any inflation escalators on it? And then when Line 3 does go back into rate base after 10 years, would you expect that rate to hold flat or move higher or lower?

[Dai-Chung Yu]

Right now, the toll surcharge is flat for the 10-year period, and that's something we agreed to several years ago. When it all goes back into rate base, the Canadian segment will obviously go into the Canadian Mainline. The U.S. segment will go into the Lakehead cost -- rate base. And -- but there will -- if we do go forward on our contracted offering for Mainline contracting, the whole Line 3 would be captured as part of that. And with our current filing, we do have an inflator built in. So I think it depends on our success at the CER and how that capital will be inflated over the next 10 years. After the next 10 years, then we would be looking at whatever regulatory mechanism we had in place to get our appropriate return on capital at that time.

[Operator]

Our next question comes from the line of Harry Mateer from Barclays.

[Harry Mead Mateer, Head of Global Energy Credit Research & Co]

First one just on the 2021 financing plan. Do you guys anticipate issuing any hybrids? Or given your plan to be in your target leverage and you don't really need any equity credit, would those just be viewed as high-cost debt and you're more likely to go straight to senior bonds?

[Colin Kenneth Gruending, Executive VP & CFO]

Yes. It's Colin. The latter, just straight up vanilla financings. We don't -- we've used hybrids in the past. We don't have that in our base plan. It's always an option, of course, if we do need some more equity credit, but at this point, we don't see the need for it. So I think a pretty straight-up conventional program there issued through various members of our families in Canada, the U.S. and across the maturity term.

[Harry Mead Mateer, Head of Global Energy Credit Research & Co]

Okay. And then a little bit more broadly, I guess. This is circling back to capital allocation, where I know there have been a number of questions this morning, but what I want to focus in on is just on the leverage target. And you guys have been very consistent now for a couple of years about 4.5 to 5x. You still expect to be within that. I guess the question is what gives you comfort that continues to be the right number? And why shouldn't it perhaps be lower? Because rating agencies can and do change the thresholds sometimes quickly. So I'm more wondering just why it might not be prudent to pull that leverage number down and just to accommodate a less certain energy outlook. Or put differently, why not shrink both the equity and debt sides of the capital structure?

[Colin Kenneth Gruending, Executive VP & CFO]

Yes. Again, it's Colin. Hey, it's a great question, and it's something we're mindful of. As Al mentioned, we're fluently and frequently in front of all of the agencies and keep our ear to the ground on this. Our sense is that the goal posts aren't moving in the midstream space in the near term. I think certainly there'll be more differentiation within the space. But we're confidently at the higher quality end of that spectrum. We map very strongly to BBB+ credit metrics. And we're trending right now in the bottom end of our range, which I think is consistent with your general spirit of your question. So we're going to allocate capital dynamically and in a very disciplined way, I think, with an eye on all of these dashboard metrics. And preserving strength, as I said, is our first priority. So I think in spirit, we're directionally aligned here, but at the same time, pretty confident where we're at.

[Operator]

Our next question comes from the line of Alex Kania Wolfe Research.

[Alexis Stephen Kania, Senior Vice President]

One question I guess. Just maybe it's more on the hydrogen side of things, but it feels like Europe is really involved with things and thinking about offshore wind integration. Is that at all in your radar? Or is that something that might be too early to look at right now?

[Al Monaco, President, CEO & Director]

I don't know, Cynthia or Bill, I can comment too, but why don't you start off?

[Cynthia Lynn Hansen]

Sure, Al. Thanks. It's Cynthia. Alex, I think we are looking at all opportunities in hydrogen. As you said, it's early days, and currently, we're looking at those low-cost options and where we can gain our expertise and knowledge. But I know Matthew can also touch on this from the offshore perspective. There may be opportunities as that continues to build out. We have, of course, our existing infrastructure now in Markham, and we're starting to plan, as Al mentioned, in Markham. So we do have some expertise that we'll be able to build on. Thanks.

[Al Monaco, President, CEO & Director]

Yes. Maybe it's probably too early to be specific on offshore wind. But generally speaking, we like where we're at here, Alex, because I -- I don't know if anybody else can say this. We've built up a pretty big renewables business, and I would say we're at the front end of the curve on hydrogen. So we like it because it's a natural for us. So that's ultimately where you get the biggest bang for your buck, is in the green hydrogen side. So the fact that we can play in both of those arenas gives us a lot of confidence. But obviously, it takes a bit of time to get there, and we'll be prudent about how we get there over time.

[Operator]

Our next question comes from the line of Asit Sen from Bank of America.

[Asit Kumar Sen, Research Analyst]

This week, we saw a privatization transaction in the Canadian midstream space. Al, just wanted to get your perspective on whether we see such more deals in North America. And probably some of the topics, if you could hit on access to capital, cost of capital and pressure on public companies in this new energy transition regime.

[Al Monaco, President, CEO & Director]

Okay. Well, what we're seeing so far, whether you look at the midstream or the upstream part of things, one thing is for sure, downturns always spawn consolidation. So I think what you're seeing here is exactly the right response from the industry that you'd expect here. So people are shifting to focus on returns, scaling up the business, capital preservation, cost efficiency. So from our own perspective, when we watch that upstream, we think it's really positive for the business and makes the industry stronger in terms of its ability to sustain itself but also grow the business for us. We probably get some credit benefits at the margin. So I think this is all very good. I mean you mentioned a privatization transaction that's in the market here recently. The good news about that is we're starting to see how this is surfacing value, which we've been talking about. I mentioned in my remarks that the value of existing pipe in the ground is going to go up. So I think this foray, if you want to call it that, although we're not involved with it, is certainly good for illustrating the value that's going to be surfaced in this business. So hopefully, that will come about in a broader sense, I guess, and it gets the ball rolling. As to the challenges to our business generally from -- if you're a public company, I would agree with you. It's certainly more difficult as a public company. But on the other hand, I think as what we've shown in the last several years, is we've certainly adapted to the way you have to operate and the way you have to permit projects. This is clearly all about how strongly we engage with communities, the expertise of our people on the ground and through the regulatory application process. So it's kind of what I was referring to earlier. It's our job to manage this in public companies, but I think the skill set we're developing here is going to set us apart. So it's a broad response to your question, but that's actually how we look at it.

[Operator]

Our next question comes from the line of Matthew Taylor from Tudor, Pickering.

[Matthew Taylor, Director of Midstream Research]

On renewables, Al, you mentioned the frothy valuations that aren't reflected in the stock price. Just wanted to hit on offshore wind there. We're seeing massive growth potential. You saw that recent U.K. auction tracking oil majors, and then South Korea is poised to build a pretty massive wind farm. But can you talk about the competitive landscape there in offshore wind? Because, as we all know, you have an incumbent position, you have a partner, you have projects in queue, you've got more in the backlog. Do you see participating in more growth in Europe or across the globe? Just any thoughts there would be helpful.

[Al Monaco, President, CEO & Director]

Yes. I'll start off. Matt, you can add. I have to say that the target right now for us is Europe. Mostly because -- I mean what you're pointing to is right in that new opportunities seem to be going for extreme valuations, if I can put it that way. But we're in a good spot here because we've got our development pipeline and our construction projects. I think that's going to keep us full for quite a while. So the target is Europe for now. We can never count out going elsewhere, but we're going to be pretty cautious around that. I mean you've seen the U.S. Northeast frothiness as well. I suppose being in the international offshore business helps us think about other areas we might go to, but it's not really on the radar screen for us right now. We've kind of got a lot going on our plate already in Europe. So I think that's the high-level picture. And I don't know, Matthew, if you want to add anything to that.

[Matthew A. Akman, Senior Vice President of Strategy & Power]

Thanks, Al. Not much. I think that's exactly right. And Matt, we are seeing new entrants trying to kind of elbow their way into the business here. It's something we're watching very closely. We're, like Al said, in a great position. In France, we've got 3 -- we'll probably have 3 projects in construction this year, a couple more contracted development projects in France and then a couple more behind that. And as Al mentioned, in the U.K., our big project there was a round 3, so we don't have those big lease payments. So I think we're in really good shape with our pipeline right now, and that's what we're focused on delivering.

[Operator]

Our final question comes from the line of Michael Lapides from Goldman Sachs.

[Michael Jay Lapides, Vice President]

Al, this is more, for one, for you and the Board. You've mentioned that renewable valuations -- not just renewable bids but actual valuations of renewable companies have expanded dramatically in terms of the multiples. If you also look at a multiple of earnings, maybe not a multiple of EBITDA, at how some of the Canadian utilities trade, they're obviously at significantly higher levels than where you all trade on a multiple of earnings. Do you look at Enbridge and see a "sum of the parts" opportunity? And is there an opportunity -- and you guys have never been afraid to be transactional. Is there a scenario where a separation of maybe the utilities and the renewable business from the traditional kind of oil and gas -- pipeline businesses might be value-enhancing over the longer term?

[Al Monaco, President, CEO & Director]

Yes. I think it's a good question, Mike. And by the way, the -- Matthew and strategy and the rest of the team, Colin and I and others do a lot of pondering about ways that we can release value. So we certainly look at all of the opportunities. Maybe for this question, I'll focus just on the renewables just given the extreme valuations we're seeing in the market. So we're definitely -- it's definitely on the radar. I think though, if you go back, we've actually been pretty disciplined at this already. We did a sale -- a partial sale of our onshore wind business to recycle some capital, and we did that at pretty good value. Bringing in Canadian pension plan into our offshore projects, that's a form of capitalizing, I think, on the valuations that we're seeing. So I think you're right in that it's -- we're not getting the value for the renewables business yet in the valuations we're seeing at Enbridge. But I think the key here is that we considered it an option, but timing and your ability to capture full value is a question mark in these kinds of things. Because, as Matthew just said, we've got 3 big projects in construction this year. Those will be cash flowing over the next 2 to 3 years. So I think mostly, it's a question of -- you pointed out we're not afraid to be transactional, but it's a question of what's the right timing to capitalize on it in the best way. And right now, we feel comfortable that the renewables business housed within Enbridge is a good way to go. So that's how we're looking at it from a high-level perspective on capital allocation, Mike.

[Michael Jay Lapides, Vice President]

Got it. And what about the utilities? I mean it's a smaller piece of the total pie, but there is a little bit of a multiple spread or comparison when you look at valuations on those assets relative to pure play.

[Al Monaco, President, CEO & Director]

Yes. Right again. It's obviously not the same situation, just given where the valuation differences are. I would say it's -- there's probably some juice there. It's so far not really large enough to make a real impact, at least in our view. It's not that we wouldn't consider it. You also got to look at other things. The utility is obviously very credit enhancing to the overall corporation. And I have to tell you, we're very happy with the growth that we're getting in that business. As we alluded to, it just keeps on giving with good ratable growth. So right now, I think we're okay. There's no plans immediately. But I think it's certainly on our minds, and we look at all of those opportunities.

[Operator]

This does conclude the question-and-answer session of today's program. I'd like to hand the program back to Jonathan Morgan for any further remarks.

[Jonathan Morgan, Vice President of Investor Relations]

Great. Thank you. Thank you for taking the time to join us this morning. As always, we appreciate your interest in Enbridge. Our Investor Relations team is available after the call to address any additional questions you may have. And once again, thanks, and have a great day.

[Operator]

Thank you, ladies and gentlemen, for your participation in today's conference. This does conclude the program. You may now disconnect. Good day.