Hello, welcome to the Enbridge Inc.'s Second Quarter 2020 Financial Results Conference Call. My name is Jonathan, and I will be your operator for today's call. At this time, all participants are in listen-only mode. Following the presentation, we will conduct a question-and-answer session for the investment community. During the question- and- answer session, if you have a question, please press star then one on your touch-tone telephone. Please note that this conference is being recorded. I would now like to turn the call over to Jonathan Morgan, Vice President, Investor Relations. Jonathan, you may begin.
Thank you. Good morning and welcome to the Enbridge Inc.'s Second 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, and Bill Yardley, Executive Vice President, Gas Transmission and Midstream. As per usual, this call is webcast, and I encourage those listening on the phone to follow along with the supporting slides. A replay of the call will be available today, and a transcript will be posted on the website shortly thereafter. We'll try to keep the call to roughly one hour, and in order to answer as many questions as possible, we'll be limiting questions to one, plus a single follow-up as necessary. We'll be prioritizing calls from the investment community.
If you are a member of the media, please direct your questions to our communications team who will be happy to respond. As always, our investor relations team is available for any detailed follow-up questions after the call. On to slide two, where I'll remind you that we'll be referring to forward-looking information on today's call. By its nature, this information contains forecast assumptions and expectations about future outcomes, which are subject to 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. With that covered, I'll turn it over to Al Monaco.
Okay, thanks, Jonathan, and good morning, everybody. Well, it's not much of a secret that the energy space is going through a challenging time. We've all seen that through the recent events. I'm going to start today with how we're thinking about that and our long-term perspectives on energy infrastructure. We'll then review the usual business update, including perhaps a bit of a deeper dive on crude oil fundamentals that we started last quarter. Colin will take you through the results and full-year outlook, and I'll come back with a mid-year checkpoint on the priorities. We're all acutely aware of how the energy landscape is changing. The long-term energy transition for one, opposition to what we do, and a challenging regulatory and permitting environment, to say the least.
That's been compounded, of course, by a COVID-induced economic contraction that's severely disrupting energy markets, and that's going to take some time to work through. The bigger picture backdrop we're not losing sight of is that the fundamentals are intact. The fact is that low-cost, reliable energy underpins the global economic engine, and it's going to be critical to the recovery. The factors leading to future energy demand increases haven't changed either, population growth, urbanization, and an expanding middle class. There's no serious disagreement from any credible forecast on that. North America's ability to provide low-cost energy should drive an increased share of global energy markets, and that means more infrastructure and modernizing energy systems here.
When you look at the challenges we're living through today through the lens of the undeniable need for more energy, we believe that the value of infrastructure and pipe in the ground will increase. Of course, you're not seeing that reflected today yet, but that's what the fundamentals are telling us. What does that mean for Enbridge? We believe we're well-positioned to be a winner in this environment. We've got a highly strategic and diversified asset base that moves energy to the best markets, and our scale provides a low-cost advantage to those markets. Our assets are underpinned by strong commercial constructs, and 95% of our customers are investment-grade. We've got a world-class project execution capability, completing CAD 30 billion of projects since 2016. It hasn't been straightforward by any means, but we are getting things done. On the balance sheet, we're strong, as are our credit ratings.
We sold CAD 8 billion in assets, reduced costs, and simplified the corporate structure. As you can see by the chart, our resilient pipeline utility model has delivered predictable cash flows and strong dividend growth through all cycles. That's showing up again today. We believe we'll not only survive these industry challenges but thrive and win. Just to put that assertion to the test, the next slide is going to illustrate the transparency of the near-term growth. Through 2022, we expect average annual DCF per share of 5%-7% growth. About 1%-2% comes from embedded revenue growth optimization and cost efficiencies. This part of the equation is zero or what we call minimal capital intensity at Enbridge, which is what we like to see.
Another 4.5%-5% is driven by the CAD 11 billion of projects we have in execution, including completion of Line 3 and the others that you see here on the list. That program should give us CAD 2.5 billion or so in incremental EBITDA. The combination of these two gives us confidence through 2022, and remember, we don't need any external equity to achieve that. After 2022, the same two buckets will drive growth, but we'll push harder on the embedded growth part of the equation here. The goal is to try to elevate the 1%-2% on that part of the equation. On the capital bucket, we have organic opportunities in the hopper, which we've talked to you about before and the teams are working on. In sum here, we see long-term growth continuing from these two sources.
That's how we think about the big picture today and where Enbridge is at. Let me shift to the second quarter highlights. We responded to the COVID challenges earlier, adding health and safety measures to make sure our people were protected and continued to deliver energy without disruption. In fact, we didn't really miss a beat on that front. We weathered the storm well, but we're monitoring the signposts very carefully to make sure we keep it that way. Results-wise, as you saw, we had a strong quarter. Despite the unprecedented downturn in mainline volumes, our businesses picked up the slack, and credit to our people on the job they did through this quarter. We had good utilization in gas transmission and distribution, and higher rates kicked in on the Texas Eastern system.
The rest of the Liquids Pipelines business performed well, which offset some of the mainline volume decline that we're talking about. Good energy services performance this quarter. Even though we're living with compressed differentials, our prime storage assets captured good contango gains in Q2. All of this translated to CAD 1.21 in DCF per share, which caps off a pretty strong first half. While there are headwinds in the second half, and Colin will take you through that, we expect to be within the guidance range, and the cost savings we talked about last quarter were enabled in late Q2. That should help in the second half, as well as through to 2021. Our balance sheet and liquidity are in good shape. The 2020 funding plan is done now, and we've got ample liquidity through 2021. Finally, good progress on priorities. We sanctioned another CAD 1 billion of new projects.
That was good to see. Good outcomes on our rate cases and Line 3 is moving forward, as is Mainline contracting review, and I'll come back to those specifically in a few minutes. The takeaway here is that although 2020 has been a tough year for our sector and the industry, we're managing it well here at Enbridge. The next couple of slides update you on the crude oil outlook. Starting with product demand, the big driver, of course, is gasoline consumption, which has come back as economies opened up. As you can see, we're still below normal. Diesel improved a bit and jet fuel, though, is still way off as personal and business travel are low. Overall, the pace of recovery was a little bit better than we thought in Q2.
With the rise in infection rates that we're seeing today, we're cautious on the timing of a full return. Our refreshed crude outlook is on the right-hand side here. Since April, North American demand came back by almost 3 million a day. We see a more gradual pace of recovery from here. For us, what's most important is the regional picture, though. Here's what happened on that front. As product demand came back, overall refinery utilization picked up significantly, and that's shown in the gray circles here throughout North America. Of course, these markets are not homogenous. The purple boxes here show the uptick in our mainline utilization into our core markets, which is now approaching pre-COVID levels. This really shows well the resiliency of the refining centers we deliver into and therefore the mainline.
The Midwest and Gulf Coast refineries, as everyone knows, are the most complex in terms of what they process. As demand came back, they ramped up quicker. As you can see, PADD II heavy margins doubled from about CAD 6 to CAD 12. Those refineries and our system are first to recover. We saw good pull as well on Canadian heavy barrels into the Gulf, which helps our Flanagan and Seaway pipes. Light crude demand in Eastern Canada still lags a bit, though, which is why we have some space left on our light lines, but we expect this to increase as Ontario and Quebec continue to reopen. The next part of the story shows the upstream effects of all this into Western Canada and our outlook for the second half. In Q2, Western Canadian supply was off about 1.1 million barrels per day.
The mainline in Q2 actually averaged 2.44 million barrels per day, which was roughly 400,000 barrels per day lower than our pre-COVID forecast at the beginning of the year. That's the blue line that you see on the right there, showing the 2.85 original line. Obviously, we came at the favorable end of the four to 600 we talked about on the Q1 call for decline this year, so that was a good outcome. With stabilized prices, we've seen heavy volumes come back. Actually, if you look at July, heavy capacity is being fully utilized again. Barring another shutdown of the economy, we expect mainline throughput closer to where we were in Q1 by year-end.
The way we're looking at the remaining six months, we're estimating an average throughput of about 2.6 million barrels per day or roughly 250,000 lower than that blue line that we forecast originally in 2020. We expect to exit this year with some excess light capacity, but that should fill up in the first part of 2021. While all of this is going on, we continue to think about what's next and optimize capacity on the system for volumes coming back. We're currently focused on low capital intensity revenue enhancements. In Q2, we added another 50,000 barrels per day on the Mainline and the first phase of our Express expansion at 25,000 barrels per day. Good job by Vern and the team on that. We've added so far 175,000 barrels of egress in the last year with minimal capital.
That brings us to about 400,000 barrels per day over our 10-year CTS agreement that we've added. This is a very good outcome, obviously for us, but particularly for our customers who needed that capacity during this phase. The full replacement of Line 3, of course, will restore more capacity. So let's get to the Line 3 update now on the next slide. This is our usual milestones chart with the PUC's written order that you would've seen about 10 days ago now. The regulatory track on this slide is done as the petitions for reconsideration on the EIS, the certificate of need, and the route permit were rejected by the PUC. On permitting then, the focus is on the 401 right now.
The Pollution Control Agency, they run the permitting process here, issued their draft in February. It basically said that our construction plans met what they needed. However, after they reviewed it and received public comments, they decided to hold what they call a contested case to finalize the permit. As a reminder, the 401 covers construction methods and scope of work rather than whether the project is needed or the route. The PUC, of course, as I said, has approved those items. Importantly, the Pollution Control Agency has set November 14th to finalize the issuance of the permit. They've also, as you see on the slide, put in a couple of interim dates here around the hearing and the ALJ. That's good and that those milestones are set. The DNR and the U.S. Army Corps are continuing to work their permit in parallel.
Again, we've said this before, I know, but when we do have clarity on the final timing of those permits, we'll provide our ISD estimate for the U.S. portion of Line 3. Again, a reminder, it should take six to nine months after we get the permits in our hands. Finally, maybe just an overall comment on Line 3. Of course, we're disappointed with the delay in the 401 that came about last quarter, I think in this case, we think it improves further, the permit and certainly solidifies it, even more than it already would've been. On to Line 5 now and the Great Lakes Tunnel. There's a lot of information on this slide that we'd like you to take away, maybe I'll make just two broad points about the project. First of all, Line 5 is absolutely critical to the entire region.
It provides over 500,000 barrels per day of feedstock that provides refined products to Michigan, Ohio, and part of central Canada. Without Line 5, Michigan would be short three-quarters of a million gallons a day of propane, and a lot of that is for winter heating in the Upper Peninsula. Michigan would also be at least 45% short of gasoline, diesel, and jet, and that's about half the regional supply that it uses every day. Of course, let's not forget, Detroit's airport fuel supply would be at risk. All of this impacts people, thousands of refining and related skill trades, fuel shortages across the state, and of course, higher consumer energy prices. There's no viable alternative for Line 5. That's already been determined by the state's own study, and every refiner will tell you the same thing.
The bottom line is that Michigan and the region would be short the energy they need to keep this economy moving, especially bringing ourselves out of COVID. Second point on this is, even though the current crossing is entirely safe, again, that's been confirmed by third parties in more than one occasion, we're replacing it with a state-of-the-art tunnel 100 feet below the lakebed. We're doing that because we want to provide Michiganders an added measure of comfort. A couple of years ago now, we reached an agreement with the state to construct the tunnel. The courts have now twice confirmed the agreements, and the state isn't appealing that decision further. We've completed the geotech work and design as well and filed our application. Just one final comment on this. I think one thing that's important and is often missed in this equation is that people support the tunnel.
75% of the legislature, Democrats and Republicans alike, voted for it last month. 23 counties formally endorsed it, and a strong majority of Michiganders want it to get going. Slide 14 is a brief update of the mainline contracting. Again, this offering is the culmination of a two-year effort to negotiate a deal that makes sense for our customers and as well, the entire industry. In May, the CER landed on the process and timing to review our application. It's a good thing because it's a single step process, and we're now fully into that, responding to information requests back and forth. The process runs through April next year, followed by an oral hearing. Remember, our shippers here support the offering, greater than 70% of our throughput. The point of that is that they'll be active in the regulatory process.
Just to reiterate, the benefits of contracting the mainline really revolve around what's good for customers and the entire industry. First and foremost, priority access at predictable, stable, and competitive tolls. That's what they told us they wanted to see. Contracting secures a very much needed source of long-term demand pull for WCSB supply from a highly competitive refinery complex that we just talked about. That'll be good for the basin, and it supports future upstream investment. Perhaps the most important element of this, and it's often forgotten, is that contracting is going to support higher net backs for producers and maximize provincial revenues. That's because WCSB crude price is often the marginal transportation cost to move for the last barrel in the basin, and contracting ensures that producers and the province benefit from the lowest marginal transportation cost in all scenarios.
We're expecting a CER decision in 2021, we'll likely need now to extend interim rates for a period of time, and the CTS prescribes the tolls during that period. On to gas transmission now. It's been a very busy year on the regulatory front, and we're very pleased with the outcomes there, as are our customers. For us, what this does is assure we earn a reasonable return, particularly as we enhance and modernize the system. By getting three proceedings done this year, we've covered off about CAD 12 billion in rate base. We've locked down Texas Eastern in Q1, and we're now done on both Algonquin and the BC system. The combined revenue impact of those three is an increase in the order of CAD 150 million annually. We also filed on Alliance, East Tennessee, and Maritimes, and settlement discussions with customers will follow later this year.
On to slide 16. Bill and his team have done a good job of getting new projects in place and execution is ongoing here, and these projects are going to contribute to the $2.5 billion in EBITDA that I mentioned earlier. The $4 billion of system expansions and extensions is going to keep the team busy through 2023. These projects, by the way, have good returns and are underpinned by solid commercial models and high-quality counterparties. Sabal Trail phase II went into service in May, and on the $1 billion T- South project, construction is progressing well. By the way, as a side note on this, indigenous-affiliated companies have won $30 million in business so far on this project. Recall as well, going back to Line 3, there's a very big opportunity for tribes in Minnesota as well.
We got FERC approval for the Cameron extension, supplying Venture Global's Calcasieu LNG facility, and construction will start on that later this year. As you know, we recently won projects to feed LNG facilities on the Gulf. These are progressing, not surprisingly given COVID and the demand decline globally for gas, and LNG in particular, those will likely move at a slower pace now. We're managing the near-term spend on those, we will be ready to go when those facilities are sanctioned coming up. Moving now to our gas utility. The utility, as you've heard me say before, is a true gem in our portfolio. It fits so well with our low-risk value proposition, it's also one of the fastest-growing in North America. Cynthia and the team are making great progress on synergy capture from the combination of the two Ontario utilities.
This is helping drive a very good ROE from this business, especially when you think about the low-interest rate environment we're in. This quarter, we sanctioned another CAD 300 million in organic projects for 2021, 2022 in service. That's on top of the community expansion and reinforcements we have in flight. Aside from that, we continue to add 40,000 to 50,000 a year in new customers, and there's opportunity to bring gas to new communities and system modernization. Combined, this translates into over CAD 1 billion a year of rate base growth. This is a franchise that just keeps on giving on many fronts. On the next slide, we'll wrap up the business review with renewables. Of course, renewables is not as large as the other businesses within the Enbridge context, but it's progressing really well.
We've built it gradually with the same utility-like commercial structure as the rest of our businesses. We've grown our development, operational, and construction capability, most recently in European offshore, where we've been focused mostly in the last little while. We have a good growth hopper here, supported by good fundamentals in Europe and well-developed supply chains, and that's probably been the biggest factor in bringing down power costs in Europe. In the last three years, we've put three large offshore wind farms into service, totaling about a gigawatt of capacity. Over the last year, we've FID-ed two new investments in France. The most recent, Fécamp, is a 500-megawatt wind farm located about 13 miles off the northwest France shoreline, and we'll start seeing cash flow from these new projects between 2022 and 2023.
The three French projects, by the way, come with long-term PPAs and some added protections, which are unique here in these types of projects for wind variability. Again, very solid project slate here, and we have a very good partner in EDF. Finally on this one, we've been focused on further enhancing our returns, and we have another partnership here with the Canada Pension Plan, which is helping us do that. It gives us scope to grow this business with less capital intensity again. With that review, I'll pass it to Colin to go over the financial results.
Thanks, Al, and good morning, everyone. I'll take you through our financial results, financial position, and our outlook for the full year. Slide 19 summarizes our results. I want to start by saying that I'm very proud of our performance, all things considered. We've worked hard over the years at strengthening our business, and in the past few months have taken further actions to bolster the business. It's consistently been a conservative approach. It's serving us well, and I think it's a point of differentiation. As you can see on the slide, second quarter adjusted EBITDA and DCF were both up year-over-year on strong underlying performance. Adjusted EBITDA, CAD 3.3 billion in the quarter and DCF of CAD 2.4 billion. That's a CAD 1.21 per share DCF, CAD 0.07 better than last year. What stood out to me during the quarter were the following items.
We had strong, reliable performance from a number of our businesses. Gas Transmission, our utility, and the power business all performed well, materially unaffected by the COVID disruption. I think this is the diversity point. We had growth from recently completed projects, the German offshore wind projects and Gray Oak, we're still getting things done. We had a stronger US dollar benefiting our significant US dollar cash flows, we had also some opportunistic storage profits in our energy services segment. Finally, we also had a little help from delayed maintenance capital related to COVID spend, but I'll come back to that in a minute. If we drill down to the segment EBITDA performance on Slide 20, we can see that Liquids Pipelines was down only 1% or CAD 22 million, which is a decent outcome in the conditions.
On average, our mainline was approximately 85% utilized during the quarter, delivering 2.44 million barrels per day. As mentioned, that's about 400,000 barrels per day underutilized, but 100,000 barrels per day favorable relative to the midpoint of our guidance range in May. However, more than offsetting this underutilization was a higher mainline toll, including a CAD 0.20 surcharge on Line 3 Canada and a stronger US dollar, as mentioned. Our Gulf Coast and MidCon systems were down period-over-period due to lower light spot volumes on the Bakken pipeline and the Seaway Legacy system, largely as a result of reduced demand for lighter crudes in the Gulf in the quarter. Recall, though, that we are mostly take or pay on these contracted systems, but do have a little bit of spot capacity, too.
On the other hand, heavy deliveries into the Gulf were very strong, offsetting some of that weakness. Flanagan South Pipeline utilization is a good example of this. Gas Transmission EBITDA was up CAD 39 million, another good outcome, despite the Canadian gathering and processing asset sale last year, which contributed about CAD 40 million per quarter historically. Two main positive drivers here. The first is continuing strength from our U.S. gas systems, headlined by Texas Eastern and primarily ongoing contributions from its recent rate settlement. We expect Texas Eastern's new rates to contribute an incremental CAD 125 million of full-year EBITDA on a run-rate basis. The second driver is the contribution from assets placed into service last year, namely Stratton Ridge and phase II of Atlantic Bridge. This business segment continues to drive stable and predictable results, with virtually all of our cash flows coming from reservation-based revenue contracts.
Looking forward, I should mention another item. We're working through an integrity program in this business, and we'll have some capacity restrictions in place while we do that. That's going to limit throughput a little during the summer shoulder months so we can focus on getting back to full capacity by the winter heating season. Financially, that's going to mean about CAD 12 million per month of lost EBITDA. The second quarter reflects one month of this, i.e. June, and we will likely have a few more months of this, the third quarter really, until full capacity restoration. Turning to other business segments, Gas Distribution EBITDA was up CAD 16 million compared to last year. This reflects higher index distribution rates, more synergies, as Al mentioned, and stronger utilization from colder spring weather. Similarly, the power business was up CAD 50 million for the quarter.
This was driven by stronger wind resources at our U.S. wind facilities and contributions from the German offshore wind farms put into service, as mentioned. Energy services was relatively flat over last year. Both this year and last can be characterized as stronger than usual results for this segment. This year, well-publicized contango spreads in the crude market allowed us to capture profitable storage margins on a small portion of the company's storage fleet, primarily in Cushing. Looking ahead, we've seen differentials tightening and most of the contango opportunity is now behind us. Second half results are looking much less robust in this segment. Finally, eliminations and other was CAD 23 million favorable to the second quarter of last year. Most of this improvement is from lower costs as we began to realize enterprise-wide cost reductions.
About CAD 60 million of targeted cost reductions were realized in the quarter. We'll realize the balance of the CAD 300 million cited program in the second half. Moving to Slide 21 for other components of cash flow performance. A significant portion of our DCF growth came from the strong EBITDA performance I just mentioned. Financing costs, maintenance costs, and taxes collectively are trending as expected for the full year, with some timing differences showing up in the quarter. As mentioned, maintenance capital was light in the quarter as we experienced a slowdown in discretionary field work due to COVID-19 restrictions. In fact, we spent about CAD 100 million less than expected. We do expect these capital expenditures to ramp up in the second half of the year, in line with our full-year guidance.
On this slide, our cash distributions from joint venture investments benefited from new projects coming into service in late 2019. In summary, we had another very good quarter despite the challenges. Next, a few words on our financial position on slide 22. Overall, our financial position is relatively strong. We've been conservatively reinforcing the balance sheet and our liquidity to help us weather this downturn. Our 2020 needs have now been fully funded, and we've even pre-funded some of our 2021 capital requirements. As shown here, in terms of 2020 sources, our net cash flows are tracking to plan. We also banked some proceeds in the quarter from our continuing asset sales program, where again, the objective is to enhance returns by recycling capital. CAD 5.5 billion of term debt has been issued so far this year at attractive rates, both underlying rates and reasonable credit spreads.
In addition, we issued a CAD 1.4 billion hybrid security in early July. This is in keeping with our conservative approach and represents opportunistic pre-funding of 2021 in the context of our Line 3 U.S. construction timeline firming up and our forward-looking capital markets uncertainty. The hybrid market is seldomly fully constructive, we seized the opportunity at a good tax-deductible coupon. The 50% equity credit from the hybrid bolsters our financial position, which we view as a non-regret action in this environment. In terms of capital uses, our capital program for the year remains in the range of CAD 5 billion-CAD 5.5 billion, inclusive of maintenance capital. Of course, that reflects some Line 3 spending shift into the first half of 2021, offset by a stronger US dollar and some announced project wins.
On the liquidity front, we exited the quarter with over CAD 14 billion of available liquidity, and it's a little higher in July after the hybrid issuance. It's sufficient by design to get us through all of 2021, absent further capital market access. Our leverage remains firmly in BBB+ territory and continues to trend in 2020, well within our 4.5 to five times target range. The balance sheet is in great shape, and that's contributed to several agencies reaffirming their ratings recently, which I think is noteworthy. Let's move finally to slide 23 and our financial outlook for the rest of the year. While uncertainties remain, our business is resilient and diverse.
These points and our first-half results provide confidence in our full-year outlook. As always, there are some tailwinds and headwinds to consider in the second half against our original guidance. I think on both buckets, we've talked about all of them. Tailwinds include lower interest rates, a stronger US dollar, gas transmission rate settlements, and further cost reductions, which are now enabled. Those should be likely more than offset by headwinds, namely mainline volume utilization, catch-up and maintenance capital in line with the full-year guidance, fewer opportunities in energy services, Q3 capacity availability on Texas Eastern, as mentioned, and finally, lower contributions from our small commodity-sensitive businesses, DCP and Aux Sable.
Looking at all these puts and takes for the remainder of the year, along with positive first-half results, we remain confident that we'll be within original DCF per share guidance range of CAD 4.50-CAD 4.80 per share. In sum, two messages from me. Number one, we're managing the business, excuse me, conservatively from a financial perspective. Two, the diversity of the business is shining through. With that, I'll hand it back to you, Al.
Okay. Thanks, Colin. If we rewind back to Enbridge Day, you'll recall we set some priorities for ourselves in 2020. This is basically a wrap-up with the mid-year checkpoints. It's turned out, obviously, to be a more difficult year for industry than anybody imagined. If there was ever a time to have a low-risk business model, it's now. We responded well operationally, keeping our people safe as well, and our resiliency paid off. We've had a good start to the year, as Colin just went through. To protect against the prolonged and deeper recession, we took some actions on liquidity and completed our funding early for the year and at the same time capitalized on some good rates in those financings. The well-diversified stream of cash flow is helping us mitigate the impact of lower mainline volumes.
Throughput is coming back, but we're watching the recovery carefully, and we're certainly not going to get ahead of ourselves. We took action to cut costs, and we reaffirmed the guidance and assuming we can get there, that'll be a very good outcome in this kind of year. On Line 3, while the Minnesota Pollution Control Agency's contested case has delayed things a bit, I think we're coming to the end of this process now, so we're looking forward to that. Finally, we continue to secure new growth for the future. Lastly, on the remarks today, and before we get to the Q&A, many of you know John Whelen, our Chief Development Officer, and previous to that, CFO. After 28 years with Enbridge, John has decided to retire. He's been a key leader at Enbridge over many years, bringing his financial expertise and judgment to our growth and our evolution.
Someone who's really exemplified our values and approach to the business as a company. John has taken a lot of pride in developing people, and as you know, succession planning is a big focus at Enbridge. Matthew Akman, who looks after strategy and power, will report to me, as will Allen Capps, leading corporate development and energy services. John has been a friend over this period. Not having him around will be an adjustment for us. On behalf of Enbridge, and I know many of you on the phone as well, we wish John and his family the very best in the future. With that, we'll turn it over back to the operator for the Q&A.
Thank you. We will now begin the question-and-answer session. If you have a question, please press star then one on your touchtone telephone. If you wish to remove yourself from the queue, please press the pound or hash key. If you're using a speakerphone, you may need to pick up the handset first before pressing the numbers. Once again, if you have a question, please press star then one on your touchtone telephone. Our first question comes from the line of Robert Catellier from CIBC. Your question please.
Hey, good morning, and thank you for your comments this morning. I have a couple questions about capital allocation that you partly touched on in your prepared remarks. Obviously it's an increasingly difficult environment to get pipeline projects developed. I'm wondering how that's impacting your capital allocation strategy. Maybe you can, in your answer, specifically address what influence it's having on hurdle rates and project selection. Also, the relative attractiveness of other, and perhaps even new parts of the value chain you might consider or other jurisdictions outside of North America.
Okay. Well, I'll go first, Robert. Thanks for the question. It's a good one in this environment, then Colin can fill- in. I think you know us well, in terms of the amount of effort we put into the capital allocation process. We've got a pretty in-depth framework here. We put a lot of work into it, and more so even these days. I think, if you go to hurdle rates specifically, we've always taken the approach of developing those from the bottom up, and they're very much project-specific. I guess maybe if you look at the overall weighted average cost of capital, just intuitively you'd say, well, bond yields are lower. Obviously, betas have been higher than we've seen. Those two factors are at play in either direction.
In terms of what we're seeing out there today and the risks that you're pointing to, what we try to do is reflect each one of the risks around project challenges in the hurdle rate. The simple way to look at it from the way we approach it is we do the basic hurdle rate based on those things I mentioned, but we essentially take adders, if you want to call them that, based on how we see the variability, depending on what risk you're talking about. For example, today, if you're entering a new build, you'd have to say whether or not you think schedule and cost will come in as you predicted.
We do our best to come up with those estimates, and then we run a bunch of scenarios around that to see what happens to the equity return if schedule, say, is delayed and that schedule increases your cost inevitably. When we do that, we can assess what sort of adder we need to apply depending on what the type of sensitivity is that you're looking at. We do that, Robert, for essentially every element of the risk profile of a project.
It's a very in-depth and pedantic review of hurdle rate, but it really is to the essence, I think, of what we're all about, which is making sure that when we put capital to work, and we put a lot of it to work in this business, you've got to have a pretty good feel for ensuring you can generate value above that hurdle rate. Otherwise, you're not really doing much to add any value at all. That's how we look at the process that we go through here. It's maybe more than what you wanted, but that's what we do. As to the other part of your question around other parts of the value chain, I think our view is always extending the value chain whenever we can is something that we always strive to do.
A good example of that would be the liquids business, where you've seen us extend that value chain from pipes and then all the way down to the terminal side of it in the realm of exports that you saw in the Gulf Coast, for example. I think as long as we can do that on the same type of commercial model that we have today, I think we're good on that front. Those are the kind of things that we would look at as priorities. With respect to, I think you said something about, I guess you implied international. Certainly, on the face of it, what we do and the capabilities we have could be exported if you want to look at it that way.
Again, we go through a pretty distinctive process there, where we look at what the hurdle rates would need to be for international investments. We don't have anything other than the European business right now for wind that's really imminent, but certainly, I suppose it could be an opportunity in the future. You'd have to really make sure that the country risk and the other factors within the risk profile fit with the rest of the business model. Anyway, that's the broad answer to your question. I don't know, Colin, if you want to add anything to that.
No.
Okay. Let's move on then.
Yeah, that was very helpful. Just the last question related to cost of capital. It doesn't seem to really be limiting your access to capital at all here, but you've seen some ESG trends impacting capital markets with some suppliers deciding not to lend to the fossil fuel-related industries, including oil sands. Despite the fact that you still have some pretty good access to capital, how are you addressing the availability of capital from an ESG point of view?
Well, we've done some transactions recently, so maybe, Colin, you can touch base on how debt investors are looking at that.
Yeah. Hey, Robert. Good morning. I think, obviously, we're very focused on ESG and want to continue to be a leader in that space. I think that's well-recognized in our outings in the capital market, and we continue to have access to supply chain, fulsomely, including insurance markets and all that stuff. Yeah, we feel good about that.
Maybe on the equity side of things, Robert, which is, I'm not sure if that's where you were going specifically, but we spent a lot of time on this, and I think you might recall at Enbridge Day, we sort of went through how we stack up to the rest of the group. There's a lot of good work being done, I think, in our industry generally on this front. To loop back to your other question, obviously, ESG and how investors are looking at this comes into the hurdle rate as well.
We're trying to include that as well in our capital allocation and investment review process. Overall, we're seeing the trends. If you look at the numbers, we're pretty good on all of those three markers. We'll have to see where we go from here and continue to build on that. I think this area is going to develop further over the next little while, and we should be well-positioned relative to the rest of the group.
Okay. Thank you for your very fulsome responses.
Okay, Robert. Thank you.
Thank you. Our next question comes from the line of Jeremy Tonet from JP Morgan. Your question, please.
Hi, good morning.
Hi.
Just wanted to start off with a quick question with the caveat being not a legal expert and not in a great position to opine on this. If for some reason Dakota Access Pipeline were to be shut down for some period of time, I just wanted to see what the reaction could be from your network of pipelines, given you have a lot of assets in that area, and potentially, Enbridge could do things to help basi n egress, but just wondering if you could share any thoughts on that.
Maybe we'll ask Vern. He's been doing a lot of thinking about that. Vern?
Good morning. Obviously a shutdown of DAPL would be bad for North Dakota and all the users of that crude oil coming from the Bakken. As you mentioned, we obviously have a very broad and diverse network of crude oil pipelines. We have a couple of ways to get Bakken crude into our system. We're doing a lot of work on contingency planning should the courts shut down the DAPL pipeline. I think it's fair for us to say that we think we will be able to provide more egress than we do today, and we should be able to mitigate a good chunk of any lost revenue or EBITDA coming from DAPL.
I think, Jeremy, I think as he's saying, we can mitigate, and we should be in generally good shape. Although, on a broader sense, we're obviously, as Vern alluded to, concerned about it. Again, as I said around Line 5, for example, it's easy to talk about shutting down systems, but it really does have a detrimental effect, not just to North Dakota in this case, but consumers and the entire region. It's a serious issue that we're watching closely, but at least we're in pretty good position.
That's very helpful. Thank you. Maybe shifting gears a little bit, just wanted to touch on Enbridge's appetite for, I guess, maybe more green investments over time. It seems hydrogen has been getting more attention. Could be later dated at this state, but given your Nat Gas pipeline network, imagine you'd be well-positioned to capitalize on that. As far as offshore wind is concerned, you guys have been very involved in the European side, and the supply chain isn't quite stood up as well on the U.S. side. Maybe your expertise could be an advantage there. Just wondering, overall appetite for green investments and specifically those two avenues, if you see opportunities there over time.
Okay. I'll start off and then maybe Bill. I'd like Bill to comment too on this because the reality is that the renewable side of things in terms of power generation really does link up with natural gas. Maybe he can address that part. Overarching that, though, I think from a strategic point of view, Jeremy, the way we're looking at the renewable space this year, and as I mentioned, we've been gradually building this. We know the supply profile is going to change globally for energy. It's not going to be a quick transition by any stretch, but slowly, renewables will be a bigger portion. At the same time, we're going to see conventional fuels growing as well, especially natural gas. We think it makes sense strategically from the point of view of diversifying our capability to have a portion of the assets in renewables.
As I said, we've built that slowly. You mentioned hydrogen. It's a good question because it's quite prominent issue today. I will say that Cynthia and her team in the utility have been doing a very good job in getting ahead of the curve on this. I think we're well advanced on a couple of ideas. We're going to look forward to looking at that, especially as it relates to natural gas. All of this, of course, again, going back to Robert's question, comes back to the commercial fit and whether or not we can make a good risk-adjusted return. Before I hand it to Bill, you mentioned the supply chain.
I think you're right about that in the U.S. context. You got to remember here, I think, U.S. offshore wind is certainly an attractive opportunity. As you point out, the supply chains are not as developed yet. Frankly, nor are the regulatory environments as developed as Europe. It's probably the biggest reason why we're not involved U.S. offshore yet. Maybe, Bill, you can comment on the interaction with natural gas.
Yeah. Jeremy, you probably heard me talk about this once or twice in the past. If you look at the regions that, especially our pipelines serve, we have a great partnership with renewables. Today's a great example. I took the opportunity to look on the ISO website while Al was talking, wind is 30 megawatts. Natural gas is 10,200. You could quadruple the amount of wind as they're projecting, it's just on the peak hours. It's just not there. Nothing else is either. We've got a really good opportunity just with our gas side to be, especially where we operate in the Northeast, to be a very good partner for a long time. You mentioned hydrogen. I think hydrogen is very interesting.
Both our utilities, Cynthia's business, and ourselves on the natural gas side, we have been studying this. It's extremely expensive. Is it green hydrogen? Is it blue hydrogen? How does it interact with the pipelines and the actual steel in the pipeline? That takes a lot of engineering to look at. You're right. The network, and this is decades from now, would be well-positioned if hydrogen transitioned from that kind of shiny object that is potentially a solution to a reality. I don't know if that's what you're looking for, Al and Jeremy, but that's a couple of comments there.
Thanks, Bill. That's helpful. Thank you.
Thank you. Our next question comes from the line of Rob Hope from Scotiabank. Your question, please.
Good morning, everyone. John, all the best in retirement. First question's on the Mainline outlook. It looks like Q2 played out a little bit better than we expected, yet you did keep your H2 outlook. Can you just give some puts and takes there, especially given the fact that heavy is fully utilized right now? Are you assuming that you do see some heavy degradation in the back half of the year? Is it all light or is it looking towards the upper end of your volume outlook there?
Hi, Rob. It's Vern here. I think we're purposely being a little bit conservative. Obviously, the wild card is whether there's a second wave of COVID and we continue to see some more demand destruction on the refined product side of things. I think we believe the worst is behind us, but we remain cautiously optimistic on mainline throughput over the rest of the year. Our expectation is if things remain the way they are, that we'll be fully utilized on the heavy side for the balance of the year.
Rob, we talked about this quite a bit, actually. I think this is the appropriate approach because even if you just look at the last couple of weeks, some of the driving numbers, and you've seen these, have sort of stabilized a bit, whereas we were on a big roll before that. Of course, if you look at the diesel numbers, which we talked about, and certainly jet fuel, they're just not moving. I think the appropriate approach here as far as how we look at the rest of the year is to be, I guess, suspect until we see some signposts, which Vern and his team look at pretty carefully. I think that's the right way to go here.
All right. Appreciate the color. Secondly, just to follow up on the capital allocation question, just given your allocation of capital as well as how Enbridge's shares have performed versus the U.S. peers, have you reevaluated your view on M&A, whether that's on the corporate side or using this as an opportunity to acquire single assets that could be contiguous with your system?
Yeah. I think on the latter one, I think that's right. We would certainly not hesitate if we saw something in the single asset category that made sense in either of those three businesses. I'll add the power business in there. I think to the extent that we can see value in how it enhances the existing franchise on single assets, I think that's probably the prime area. In terms of larger scale M&A, it's not on the priority list right now. I think we've done the repositioning we need to do. We've got very good embedded growth and some hoppers that are filling up in each of the businesses.
The balance sheet's in very good shape, we want to make sure we're not messing with that. It's true that maybe this is where you're going. It's true that the midstream valuations are, I guess, attractive relative to where they were. Every time we look through those, we run up against our value proposition issue, I'll call it, where there's not a pure match with the stability and predictability of our cash flows with some of the others out there. I'm not saying they're bad, it's just that they're different than what we shoot for. I would say low priority.
All right. Thank you.
Okay. Thank you.
Thank you. Our next question comes from the line of Praneeth Satish from Wells Fargo. Your question, please.
Thanks. Good morning. Can you give us an update with your negotiations with the Bad River Band reservation with respect to Line 5? I just asked because there's a pipeline in the Bakken that was ordered to shut down earlier this month for what seems to be similar circumstances. Just curious on your thoughts there.
Okay. Well, I'll take that question. I think job one for us is to continue to operate the line safely and do the work necessary on the reservation to have that happen. Job two for us is to progress the reroute. I think the tribe has really asked us to move the pipeline off of their lands, and we're in the process of doing that. We've filed for all of the environmental permits and the easement permits necessary to do that, and we believe that regulatory process will take about 12-18 months to complete. Once we've done that, we'll be able to meet the wishes of the tribe and remove the pipeline from their reservation. We've been following that Bakken pipeline situation quite closely.
I know at first glance it looks like an analogous fact pattern, but when we really dig deeper into it, the fact patterns are, in fact, quite different, where we have been in constant negotiation with the allottees on our easement, and we have not seen the Bureau of Indian Affairs get involved in our pipeline situation with the Bad River Band. While at first they may look similar, I think when you really do a deep dive, the fact patterns are quite different.
Okay, thanks. Then in your prepared remarks, you mentioned that you'd push harder on the 1% to 2% embedded growth in kind of the 2022 plus timeframe. Can you just elaborate what you mean by that and some of the levers that you potentially have to pull there?
Hey, Praneeth, it's Colin. Yeah, great question, and it's something we're actively on. You can see it. Probably the simplest example is just our cost pursuit. I'm sure everyone in the industry is doing this as well, but we're all over that. I think that's a positive vector relative to history in this bucket. I think, secondly, you've seen us incorporate and push on index rates or inflators in our tariffs. That is continuing, and we'll do more of that.
Thirdly, and I'd put in this category some of the just kind of embedded rate base growth that you see in our utility-esque investments where, I think Al talked about this, where we're going to be asked and we'll proactively look to ourselves, renew and modernize systems, and that is effectively utility-esque, kind of boring growth. I think those are all factors that play into that kind of plus emphasis on the 1%-2%.
Yeah, maybe the only other example, Praneeth, just to give you a feel for it, we talked about this in terms of, let's use the liquid system. The size and scale of it at whatever it's going to be, I guess, over 3 million barrels per day once Line 3 gets done, that sure gives you a lot to work with. If you can add 50,000 here, 25,000 there of capacity by doing things like adding DRA, for example, that's a very low capital intense type of revenue line improvement.
Those are the kinds of things. I mean, the team already does this, but for example, can we use technology in a different way to further optimize the system? How we move volumes through terminals, for example. We have a massive liquids terminal system. Is there a more efficient way to move volumes around those terminals to get revenue quicker? It's those kinds of things generally, aside from the things that Colin's mentioned.
Got it. Thanks.
Thanks, Praneeth.
Thank you. Our next question comes from the line of Robert Kwan from RBC Capital Markets. Your question, please.
Good morning. For Line 5 East Leg and DAPL, can you talk about what's embedded in guidance, in terms of downtime or potential downtime, and are you able to provide EBITDA or cash flow sensitivity for potential downtimes on a monthly basis, inclusive of any offsets such as Bakken volumes coming off of DAPL but flowing onto your wholly owned systems like Cromer or into Clearbrook?
Hi, Robert, it's Vern. Maybe I'll start with Line 5. Obviously, the west leg is running right now. The Strait Crossing is a dual pipeline network where for a period of time, one leg can service our requirements downstream of the Straits. We expect to have the east leg up and running, hopefully within the next few weeks. We've obviously been working with our federal regulator to demonstrate that the pipeline is fit for service, and the regulator's working through that right now. Once that's complete, we'll make an application to the court to have the temporary restraining order amended to allow for the startup of the east leg, which will then provide redundancy on Line 5. I don't think there's any real magic there from an EBITDA perspective.
On DAPL, prior, with the downturn in Bakken volumes, we do have some space on our legacy North Dakota line that runs into Clearbrook. We also have some space on our Bakken expansion project that runs up from the Bakken back into Canada at Cromer. I think ballpark-wise, we can handle 200,000 barrels a day of incremental flows very easily. We're working on incremental optimizations to allow us to even move more crude should that be required. I think we're in pretty good shape to be able to offset a lot of the production coming out of the Bakken. Obviously, if those barrels hit our system, we will then benefit from the downstream pipeline takeaway throughput that takes those volumes to other markets.
Hey, Robert. Sorry, just to confirm that. At a high level, I think as Vern was saying, we don't see any material impact from these in the back half of the year. That's what's embedded in our guidance. I think on Dakota Access Pipeline, just high level sensitivity there. On a full year basis, DAPL represents about CAD 250 million-CAD 300 million a year of EBITDA, which is about 2% of consolidated EBITDA. I think as Vern mentioned, while we don't want to see it out of service, there are avenues to substantially mitigate that on our system.
Got it. Thank you. Just to finish, Al, you mentioned the energy transition earlier. There's been a lot of questions on the call just around your strategy around asset mix and capital allocation. With the asset mix and sustainable infrastructure, whether it's right or wrong, you've got negativity towards kind of your pipeline business, including at least in some circles, gas infrastructure. With that, what are your thoughts on harvesting free cash flow from the pipeline business and accepting less attractive returns in renewable energy? Do you just take the view that your assets are what they are, you do the best you can with sustainability, benchmarking against your peers, and just continue your discipline of investing capital at the highest risk-adjusted returns, regardless of where those opportunities are?
Yeah, I think it's the latter. Just given the comments before on capital allocation and how we look at future investment. In terms of the asset mix today, I think when we repositioned the asset mix to almost 50/50, I'm going to call it, between natural gas and liquids businesses, with a little bit in there for renewables. I think we're kind of happy with the mix there. There's certainly an energy transition in play here, in the end, it's going to come down to the competitiveness of assets to each of the key markets. That's where I think we're going to be really strong, whether it's liquids, whether it's natural gas, utility, or transmission. The reason I'm saying that is because in the end, it's going to come down to the fundamentals.
If you can be the most competitive system into each one of these markets, the transition's happening, but certainly not going to happen over a short period of time. We think we're pretty solid on each of the businesses for decades to come. If we do see something where we can, I think you called it harvest or sell, then we would look at that. At this point, we're pretty happy with the asset base. We've kind of done the monetizations and sales that we thought were most important. That's how we're looking at this at a high level. If I haven't gotten to the crux of what you're getting at, let me know.
No, that's great. Thank you very much.
Okay. Thank you.
Thank you. Our next question comes from the line of Shneur Gershuni from UBS. Your question, please.
Hi, good morning, everyone. Happy to hear that everyone is safe and well. Maybe to start off, a broad CapEx type of question. Line 3 is kind of delayed at this point right now. At the same time, you've announced a couple of new projects that you've secured. How does CapEx shift around, in terms of the delay and as well as the announcements? Does CapEx potentially come down a little bit this year? Does it go up next year? How should we think about the total CapEx number as we think about 2020 and 2021? With respect to the new projects that were added to the backlog, can you confirm that they're utility-type projects that are tantamount to a rate-based type of expansion opportunity, and is that the priority going forward?
Hey, Shneur. It's Colin. Good question. I think on Line 3, I alluded to this in my remarks. We've got approximately CAD 2 billion left to spend on Line 3 U.S. here, and we've earmarked approximately CAD 1.5 billion of that to next year. We've just moved it. As I noted, this year's CapEx is lower than guided in December of 2019. We'll have a little more next year, but overall, the CapEx budget is declining as we go forward here, which should help us generate free cash flow.
You're right, I think, marrying your question maybe with Robert's at the beginning, our capital allocation framework and adders risk premia are indeed channeling us towards lower beta projects, if you like, the in-corridor expansions, extensions, modernizations, executable projects. If you need a list of them, they're basically outlined in that CAD 11 billion secured project listing that we've been carrying.
On that CAD 1 billion, Shneur, CAD 300 million of that, let's call it conventional utility capital. It's basically reinforcements. That is very much right down the middle of the fairway. The other part is the renewable project that we sanctioned offshore France. I'd have to say that one is at least as good in terms of the risk profile. As I mentioned in my remarks, that one has got this other feature where the wind variability that you typically see in these projects is actually quite limited because there's a collar on it. In terms of the size of it, remember, that project will be project financed in terms of how it's funded. We'll actually put quite a bit less equity into that relative to the overall debt equity split within the company. Hopefully, that answers what you're getting at.
No, it does. I really appreciate the color and the detail on that. Maybe as a follow-up question. I know there's been a lot of questions today about capital allocation and in terms of projects and free cash flow harvesting and so forth. I was wondering if maybe we can pivot a little bit and talk about the balance sheet. Rates out there right now are extremely low. One of your U.S. peers issued debt this week at fairly low levels in terms of rates. You've funded 2020, you've started pre-funding 2021. What are the thoughts around extending the maturity profile as you're in the market right now to sort of take advantage of and capitalize on the current rate environment?
Yeah, sure. It's Colin. Thanks for that question. Indeed, rates are low and attractive, and indeed, we've been capitalizing on that trend ourselves. Anytime you can issue 10-year debt in the mid two range is probably a non-regret move on a tax-deductible basis. We've observed this. We're participating in it. We have been extending our maturity through this process as well. I think our average maturity is about 17 years now. We're happy with that. It matches our long-lived asset base. It's a good point. I agree with it.
All right. Perfect. Well, thank you very much, guys. Really appreciate all the color today, and have a safe day.
Okay. Thanks, Shneur. Thank you.
Thank you. Our next question comes from the line of Linda Ezergailis from TD Securities. Your question please.
Good morning. Looking at your long-term growth beyond 2022, it's great to see you reaffirming the 5%-7% DCF per share growth and providing some visibility on enhancing the 1%-2% base optimization beyond 2022. Can you help me understand what the possibilities are in terms of magnitude? Could you double that to 3%-4%? Implicitly, should we assume that maybe that's being done to maintain that 5%-7% growth rate prospectively, suggesting that the secured growth, contribution to growth might decelerate a little bit?
Okay. Linda, it's Al here. First of all, I think you'd expect growth overall to be slowing down in the industry. That's just a reality, I think, in this environment, when you've got a major disruption like this. Specifically, you have, and you see the numbers probably better than we do. The economic contraction overall going on is undeniable. I think we're going to probably be really well-positioned, though, in this downturn with respect to continuing growth. We'll look at other things to do with capital as well, in case we can't find the opportunities that we've been focused on and pretty good at. I think, to get to the root of your question, though, I wouldn't want to specify that distinctly what the first bucket would be. If we can add another percentage to it, I think we'd be pretty happy.
The way I look at it is, if we can add more there. It certainly would offset some of the things that we might not see coming in secured growth beyond 2022. That's sort of how we're looking at it. You'll recall back at Enbridge Day, we said, to generate that additional 4%-5%, we'd probably need to spend roughly CAD 5 billion a year in new project execution. It sounds like a big number, and it is. When you break it down by business, Bill's got lots going on.
I mentioned over CAD 1 billion just in GDS, the utility. Power's got some projects. Liquids can optimize. Frankly, if we can get more of the growth rate with these low capital-intensive optimizations, expansions, or modernizations of the systems, and Bill's is a good example of that, Bill's area. I think, we can see ourselves getting pretty darn close to that. Although generally the market's less growth-y going forward, I think that's a reality. I think we should be in good shape to get pretty darn close.
That's helpful context. Thank you. Just as a follow-up, I guess one of the other levers you have is the growth aspirations are on a per-share basis. I'm wondering what might trigger consideration of a share buyback, and also, to the extent that you don't need to partner or sell assets to pension funds and other financial investors. I'm just wondering if you're approached with a very compelling offer to do further JVs, like you have recently with your offshore wind. Is that another lever that you would seriously consider balancing off, I guess, the complexity associated with that potentially?
Yeah. It's a good observation. The short answer is yes. I think, we've got some great franchises and they're certainly core to us. We wouldn't want to see them necessarily just be sold off. If somebody's presenting compelling value and you've got some good reinvestment opportunities, we'd have to look at that. We have big businesses. It would obviously be constrained to pieces in JV. That's probably what you're getting at. I guess linked to that, which was the other part of your question, had to do with buybacks. We're going to look at that pretty carefully. I think we've said before, we will make sure that that's part of our capital allocation review.
I would say, Linda, at this price, it's a pretty obvious source of growth if you want to look at that on a per-share basis like you were mentioning. Other considerations, though, aside from the fact that the assets that we have are core to our growth and they've got a lot of embedded growth in them, we already return a boatload of capital through the dividend. I think Colin will correct me, it's probably in the CAD 6.5 billion range annually. The other thing, too, Linda, is we tend to look at these on a full-cycle basis.
Whereas, yes, we can make something accretive by buying back shares, we tend to compare that to not just short-term accretion, but what are we going to get out of the buyback in the longer term? We look at what else we could do with that if we had growth opportunities. I think really this comes down for us to more of a timing thing. We'll certainly look at buybacks, especially at this price, once we get Line 3 in. I think until that, we are still in pretty heavy capital investment mode here. I think that's how to look at it in general terms.
That's helpful. Thank you.
Okay.
Thank you. Our next question comes from the line of Patrick Kenny from National Bank Financial. Your question, please.
Yeah, good morning, guys. Just on the mainline contracting, I know it's still early days, but given the value of pipe in the ground, as you mentioned, Al, and the mounting challenges in getting new pipe capacity built, are you starting to see additional commercial support come in from shippers? It looks like that 70% support number hasn't changed yet. If competing projects continue to be challenged, to say the least, could that not alone bring in further support for your mainline offering over the coming quarters? Do you think you're at the point where you would need to refine the terms in order to achieve a level of support well above 70%?
I'll make a quick comment, then I'll turn it to Vern. On your point about additional support, I think at this phase of where we're at, having filed the application, I wouldn't see necessarily somebody coming out and saying, "Oh, well, we changed our mind." I think while we're in this application process, we're probably not going to see much change in that, and the focus would be on making sure that everybody is still with us. I wouldn't have expected anybody to be added to the list at this point. I don't know, Vern, if you want to expand a bit on his question.
Okay. I think you've hit most of it, Al. I think the only nuance I would make is that we continue to talk to the producing community here in Calgary who are the primary opponents to Mainline contracting. Those people are of differing views on why this may not be the best thing for them. Some just don't like the toll. They just believe it's too high. Others are waiting to see how the competing pipelines play out. There's finally the smaller producers who, quite frankly, are just coming up the learning curve on how
All this all works. We focus most of our attention to see if we can get a few more of those people into our camp, and we'll continue to do that as we go through the CER process. I think the one thing that the application has helped, though, is the question-and-answer part of it. I think it's starting to maybe gel a little bit. This is not an easy thing to really absorb at 100,000 feet. You got to get into what the value drivers are. I think, as I mentioned in here, it really comes down to the predictability of those tolls. That's really what I think will be the key value driver.
I wouldn't sell short the fact that having locked-in demand from the best market in North America is another key factor along with this concept of the marginal toll economics. Again, I think starting to get some headway with people who are really actually now starting to look at how is this going to affect them. I think it's easy to say, well, we don't want to do this or that. I think people are starting to get a bit of that story, I think.
Okay. I appreciate that color. Then just a quick follow-up on the DAPL situation, if I could. I know you're not in the driver's seat there, but can you clarify when you expect a court decision on the pipe being shut down or not? Is clarity by next week before that initial August 5th deadline reasonable, or could this drag on for another few weeks here?
I think it's best for Energy Transfer to comment on how the court proceedings are going to play out. I think all I can say is it's in front of the U.S. Court of Appeals right now.
Got it. Okay. Thanks, guys.
Okay. Thanks, Pat.
Thank you. Our next question comes from the line of Ben Pham from BMO. Your question, please.
Okay, thanks. Good morning. On a U.S. election, if the polls are correct and Biden wins, what do you think the impact is on your business, if any, your existing U.S. assets, projects under construction at Line 3? Anything else, tax rates, that's worth commenting on?
Well, I guess, Ben, it's a good question. That's certainly something on everybody's mind, I think. Specifically, the last part. There's nothing different that we expect on Line 3. I think the fundamental there is it's a state process, and we're right into working with Minnesota, as you know, for quite a while. I'm not sure that one really plays into the change in administration, if in fact that happens. It's always something we contemplate and look at whenever you have a potential administration change. I think the point is, frankly, we work pretty well with all administrations, even the previous one, on many fronts. I think it's probably a little too early to tell, honestly, Ben, what the policy implications will be and what it means to infrastructure.
Certainly, we don't see any major change. Really that's because in the end, as I said earlier, it's pretty clear that our assets are going to be critical to the economic growth in North America. A lot of, as I said, what we do falls into that state regulatory and permitting camp, and I guess, by the way, Vern, I guess we're not seeking any federal cross-border permits at this point. All in, I don't see it as a big factor. We're watching it, obviously, Ben, but generally, we think we'll be in good shape.
Okay. Thanks for that. Maybe a follow-up on the earlier question about hydrogen and your response. You're studying it. It's still early days, quite expensive. Are you at the point in the next 12 months to put some dollars into some pilot investments? I'm also curious, is the studying, is it more the gas utilities blending? Are you also talking with Canadian producers more broadly exporting hydrogen on pipes and more of a broader discussion and studying of the hydrogen opportunity?
It's probably two fronts. I would say the more imminent, certainly in the utility. Cynthia and her team are working diligently on this. You heard Bill's comment about how that might work through the gas transmission side. This is all, I think, in the realm of call it blue hydrogen. To answer your question, I think yes. We're at the point where we could certainly see putting in small amounts of capital to prove out our understanding of this.
I think we've got a pretty good head start on this. People have been working on it in the company for quite a while, and I think we'll be in good shape so that when we put in some amounts to test things out, which I think is appropriate for us, then we'll have pretty good confidence around that. Not huge amounts, mind you, Ben, but yeah, I think we can start to do some pilot investing for sure.
All right. That's great. Thanks. Thanks, all.
Okay. Thanks, Ben.
Thank you. We have reached our time limit and are not able to take any further questions at this time. I will now turn the call over to Jonathan Morgan for final remarks.
Thank you. Thanks to everyone for taking the time to join us this morning. As always, we appreciate your continued interest in Enbridge. Following the call, investor relations is available to address any follow-up questions you may have. 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.