Hello and welcome to the Enbridge Inc. 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 a listen-only mode. Following the presentation, we will conduct a question and answer session for the investment community.

During the question and answer session, if you have a question, please press star then one on your touchtone 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. 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, so 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.

Onto Slide 2, where I’ll remind 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. While 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, so 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 the midyear 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 the 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. But 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.

So 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 $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 $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, and 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% to 7% growth. About 1% to 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% to 5% is driven by the $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 gives us $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, so the goal is to try to elevate the 1% to 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. Now 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 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 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 $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, so that should help in the second half as well as through 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 $1 billion of new projects - that was good to see. Good outcomes on our rates 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, but as you can see, we’re still below normal. Diesel improved a bit and jet fuel 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, but 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, but we see a more gradual pace of recovery from here. For us, what’s most important is the regional picture, though, so here’s what happened on that front.

As product demand came back, overall refining utilization picked up significantly, and that’s shown in the grey circles here throughout North America. But 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, so as demand came back, they ramped up quicker.

As you can see, Pad 2 heavy margins doubled from about $6 to $12, so 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 of this into Western Canada and our outlook for 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 in at the favorable end of the 400 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, so 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, so good job by Vern and the team on that.

We’ve added so far, then, 175,000 barrels of egress in the last year with minimal capital, and 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 PUCs written order that you would have 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 road 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 and 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, and the PUC of course, as I said, has approved those items.

Importantly, the Pollution Control Agency has set November 14 to finalize the issuance of the permit, and they’ve also, as you’ll see on this slide, put in a couple of interim dates here around the hearing and the ALJ, so that’s good in 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 IESD estimate for the U.S. portion of Line 3, and 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, but I think in this case we think it improves further the permit and certainly solidifies it even more than it already would have been. Onto Line 5 now and the Great Lakes Tunnel.

There’s a lot of information on this slide that we’d like you to takeaway, but 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, and 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.

A second point on this, even though the current crossing is entirely safe, and again that’s been confirmed by third parties on more than one occasion, we’re replacing it with a state-of-the-art tunnel 100 feet below the lake bed. 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. Seventy-five percent of the legislature, Democrats and Republicans alike, voted for it last month. Twenty-three 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 of next year, followed by an oral hearing, and remember our shippers here support the offering rated at 70% of our throughput, and 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 will be good for the basin, and it supports future upstream investment.

Perhaps the most important element of this, and often forgotten, is that contracting is going to support higher net backs for producers and maximize provincial revenues.

That’s because WCSB crude prices offer marginal transportation to move for the last barrel in the basin, and contracting ensures that producers and the province benefit from the lowest marginal transportation costs in all scenarios.

We’re expecting an CER decision in 2021 but will likely need now to extend interim rates for a period of time, and the CTS prescribes the tolls during that period. Onto 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 $12 billion in rate base, we’ve locked down Texas Eastern in Q1, and we’re now done on both Algonquin and the B.C. system.

The combined revenue impact of those three is an increase in the order of $150 million annually. We also filed on Alliance, East Tennessee and Maritimes, and settlement discussions with customers will follow later this year.

Onto 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. Sable Trail Phase 2 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, and recall as well, going back to Line 3, there’s a very big opportunity for tribes in Minnesota as well.

Lastly, 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, but 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, but 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, but 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 $300 million in organic projects for ’21 and ’22 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, so combined this translates into over a billion a year of rate-based growth, so 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, and over the last year we’ve SIB two new investments in France.

The most recent fee comp 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 ’22 and ’23. 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 Canadian Pension Plan which is helping us do that, and it gives us scope to grow this business with less capital intensity.

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 of $3.3 billion in the quarter and Dcf of 2.4 billion. That’s $1.21 per share Dcf, $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, so we’re still getting things done. We had a stronger U.S. dollar benefiting our significant U.S. dollar cash flows, and 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 $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, and as mentioned, that’s about 400,000 barrels per day under-utilized but 100,000 barrels per day favorable relative to the midpoint of our guidance range in May.

However, more than offsetting this under-utilization was a higher mainline toll, including a $0.20 surcharge on Line 3 Canada and a stronger U.S. dollar, as mentioned.

Our Gulf Cost 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 $39 million, another good outcome despite the Canadian gathering and processing asset sale last year, which contributed about $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 2 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 will 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 to getting back to full capacity by the winter heating season.

Financially, that’s going to mean about $12 million per month of lost EBITDA. The second quarter reflects one month of this, i.e. June, but 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 $16 million compare to last year.

This reflects higher indexed distribution rates, more synergies, as Al mentioned, and stronger utilization from colder spring weather. Similarly, the power business was up $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, but 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, so second half results are looking much less robust in the segment. Finally, eliminations and other was $23 million favorable to the second quarter of last year.

Most of this improvement is from lower cost as we began to realize enterprise-wide cost reductions. About $60 million of targeted cost reductions were realized in the quarter, and we’re realize the balance of the $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 $100 million less than expected; however, we do expect these capital expenditures to ramp up in the second half of the year, in line with our full year guidance.

Finally 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, and 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. $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 $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 seldom fully constructive, so 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 $5 billion to $5.5 billion inclusive of maintenance capital, and of course that reflects some Line 3 spending shift into the first half of 2021 offset by a stronger U.S. dollar and some announced project wins.

On the liquidity front, we exited the quarter with over $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 triple-B plus territory and continues to trend in 2020 well within our 4.5 to 5 times target range, so 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 in both buckets, we’ve talked about all of them. Tailwinds include lower interest rates, a stronger U.S. 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 at 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 $4.50 to $4.80 per share. In sum, two messages from me.

Number one, we’re managing the business conservatively from a financial perspective, and 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, so this is basically a wrap-up with a midyear checkpoint. It’s turned obviously to be a more difficult year for industry than anybody imagined, but 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 so we had a good start to the year, as Colin just went through.

To protect against a 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 will be a very good outcome in this kind of year. On Line 3, while the 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 continued 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 has been a key leader at Enbridge over many years, bringing his financial expertise and judgment to our growth and our evolution, someone who has 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, and not having him around will be an adjustment for us, but 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..

[Operator instructions] 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, so I’m wondering how that’s impacting your capital allocation strategy.

Maybe in your answer, you can specifically address what influence it’s having on hurdle rates and project selection, but 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, and 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 and we’ve 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 bond yields are lower, obviously betas have been higher that we’ve seen, so those two factors are at play in either direction.

But 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, so the simply 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 have to say whether or not you think schedule and costs will come in as you predicted, so 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 kind of assess what 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 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. That may be 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. It’s 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, and 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 kinds 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, but again we go through a pretty distinctive process there where we look at what the hurdles 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. But 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? Okay, so let’s move on, then..

That was very helpful. Just a 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. .

Yes, 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 markets, and we continue to have access to supply chain fulsomely, including insurance markets and all that stuff, so we feel good about that..

Maybe on the equity side of things, Robert, which 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 that we sort of went through how we stack up to the rest of the group, and there’s a lot of good work being done, I think, in our industry generally on this front.

We’ve, at least according to the independent sources, have been ahead of the game here, but to move back to your other question, obviously ESG and how investors are looking at this comes into the hurdle rate as well, so 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, so 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.

Just wanted to start off with a quick question, and with the caveat being not a legal expert, not in a great position to opine on this, but if for some reason Dakota access pipeline were to be shut down for some period of time, just wanted to see what the reaction could be from you network of pipelines, given you have a lot of assets in that area and potentially things could--Enbridge could do things to help basin egress.

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, but as you mentioned, we obviously have a very broad and diverse network of crude oil pipelines.

We have a couple ways to get Bakken crude into our system, so 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 can--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 in 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. Then maybe shifting gears a little bit, just wanted to touch on Enbridge’s appetite for maybe more green investments over time. It seems hydrogen has been getting more attention, could be later dated at this date, but given your nat-gas pipeline network, I imagine you’d be well positioned to capitalize on that.

Then as far as offshore wind is concerned, you guys have been very involved in the European side and the supply chain hasn’t quite stood up as well on the U.S. side, so 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, so 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, so we think it makes sense strategically from the point of view of diversifying our capability to have a portion of the assets in renewables, and as I’ve said, we’ve built that slowly.

You mentioned hydrogen, and it’s a good question because it’s a 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, and I think we’re well advanced on a couple of ideas, so 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, and you’ve got to remember here, I think U.S.

offshore wind is certainly an attractive opportunity but, as you point out, the supply chains are not as developed yet, and frankly nor are the regulatory environments as developed as Europe. It’s probably the biggest reason why we’re not involved in U.S. offshore yet.

Maybe Bill, you can comment on the interaction with natural gas?.

Yes, and Jeremy, you’ve 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, so today is a great example. I took the opportunity to look on the ISO website while Al was talking, and wind is 30 megawatts, natural gas is 10,200.

You could quadruple the amount of wind as they’re projecting and it’s just--on the peak hours, it’s just not there. Nothing else is, either, so we’ve got a really 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. Then you mentioned hydrogen.

I think hydrogen is very interesting, so both our utilities [indiscernible] business and ourselves on the natural gas side, we have been studying this.

It’s extremely expensive - you know, is it green hydrogen, is it blue hydrogen, how does it interact with the pipelines and the actual steel in the pipeline, and that takes a lot of engineering to look at.

But you’re right - the network, and this is decades from now, would be well positioned if hydrogen transitioned from that shiny object that is potentially a solution to a reality. I don’t know if that’s what you were looking for, Al and Jeremy, but that’s a couple 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?.

Morning everyone, and John, all the best in retirement. First question 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 wildcard 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..

You know, 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, and then of course if you look at the diesel numbers which we talked about and certainly jet fuel, they’re just not moving, so I think the appropriate approach here as far as how we look at the rest of the year it 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..

Appreciate the color. Then secondly, just a 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?.

Yes, 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, and I’ll add the power business in there, so I think to the extent that we can see value and 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 is in very good shape, so 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, but 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, so I would say low priority..

All right, thank you..

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

Your question, please?.

Good morning. Can you give us an update with your negotiations with the Bad River band reservation with respect to Line 5? I just ask because there is a pipeline in the Bakken that was shut down earlier this month for what seems to be similar circumstances, so 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 re-route. 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 to 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 [indiscernible] on our easement and we have not seen the Bureau of Indian Affairs get involved in our pipeline situation with the Bad River band, so 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 the 2022-plus time frame.

Can you just elaborate what you mean by that, and some of the levers that you essentially have to pull there?.

Hey Praneeth, it’s Colin. Yes, great question, and it’s something we’re actively on. You can see--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, I’d put in this category some of the 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 will proactively look to ourselves to renew and modernize systems, and that is effectively utility-esque, kind of boring growth.

I think those are all factors that play into that plus emphasis on the 1% to 2%..

Yes, 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 liquids 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, and if you can add 50,000 here, 25,000 there of capacity by doing things like adding DRA, for example, then that’s a very low capital intense type of revenue line improvement, so those are the kinds of things.

The team already does this, but for example, can we use technology in a different way to further optimize the system or how we move volumes through terminals? For example, we have a massive liquids terminal system, and 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 mentioned..

Thanks..

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 [indiscernible] sensitivity for potential downtime, say on a monthly basis inclusive of any offsets, such as Bakken volumes coming off of DAPL but flowing onto your wholly owned systems, such as [indiscernible] or Clearbrook?.

Hi Robert, it’s Vern. Maybe I’ll start with Line 5. Obviously the west leg is running right now. The stray crossing is a dual pipeline network where for a period of time, one leg can service our requirements downstream of the straights. 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 is 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 start-up 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, and 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 a couple hundred thousand barrels a day of incremental flows very easily, and then 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 take--to offset a lot of the production coming out of the Bakken.

Then obviously as those barrels hit our system, we will then [indiscernible] from the downstream pipeline takeaway throughput that takes those volumes to other markets..

Robert, this is Colin. 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, so 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 $250 million to $300 million a year of EBITDA, which is about 2% of consolidated EBITDA, and 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..

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, and with the asset mix and sustainable infrastructure, whether it’s right or wrong, you’ve got negativity towards 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, or 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?.

Yes, 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 the liquids businesses, with a little bit in there for renewables, I think we’re happy with the mix there.

There’s certainly energy transition in play here, but in the end it’s going to come down to the competitiveness of assets to each of the key markets, and 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, and if you can be the most competitive system into each one of these markets, the transition is happening but it’s certainly not going to happen over a short period of time. So 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, but 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, so 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..

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 new projects that you’ve secured.

How does capex shift around in terms of the delay 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 ’21? 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 base 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 $1.5 billion of that to next year, we just moved it.

As I noted, this year’s capex is lower than guided in December of 2019, so 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, so indeed--and if you need a list of them, they’re basically outlined in that $11 billion secured project listing that we’ve been carrying.

.

On that $1 billion, Shneur, $300 million of that, let’s call it conventional utility capital - it’s basically reinforcements, and so 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.

Then in terms of the size of it, remember that project will be project financed in terms of how it’s funded, so we’ll actually put quite a bit less equity into that relative to the overall debt equity split within the company. That’s how--hopefully that answers what you’re getting at..

It does. 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 pre-funded--or you’ve funded ’20, you’ve started pre-funding ’21.

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?.

Shneur, it’s Colin. Thanks for that question. Indeed rates are low and attractive, and indeed we’ve been capitalizing on that trend ourselves. Any time you can issue 10-year debt in the mid-2 range is probably a non-regret move on a tax deductible basis.

We have observed this, we’re participating in it, and we have been extending our maturity through this process as well. I think our average maturity is about 17 years now, so we’re happy with that. It matches our long-lived asset base, so 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..

Thanks Shneur..

Thank you. Our next question comes from the line of Linda Ezergailis with TD Securities.

Your question, please?.

Good morning. Looking at your long term growth beyond 2022, it’s great to see you reaffirming the 5% to 7% Dcf per share growth and providing some visibility on enhancing the 1% to 2% base optimization beyond 2022.

Can you help me understand what the possibilities are in terms of magnitude? Could you double that to 3% to 4%, and implicitly should we assume that maybe that’s being done to maintain that 5% to 7% growth rate prospectively, suggesting that the secured growth contribution to growth might decelerate a little bit?.

Linda, it’s Al here. First of all, I think you’d expect growth overall to be slowing down in the industry. I mean, that’s just a reality, I think, in this environment when you’ve got a major disruption and 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 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 seeing coming in secured growth beyond 2022. That’s how we’re looking at it.

When we see the--you’ll recall back at Enbridge Day, we said to generate that 4% to 5%, we’d probably need to spend roughly $5 billion a year in new project execution. It sounds like a big number, and it is; but when you break it down by business - you know, Bill’s got lots going on, I mentioned over a billion dollars just in GDS, the utility.

Power’s got some projects, liquids can optimize, and frankly if we can get more of the growth rate with these low capital intensive optimizations, expansions or modernizations of the system, and Bill’s is a good example of that, Bill’s area, then I think we can see ourselves getting pretty darn close to that.

So 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 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 were 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?.

Yes, it’s a good observation, and the short answer is yes, because I think if--I mean, we’ve got some great franchises and they’re certainly core to us, so we wouldn’t want to see them necessarily just be sold off, but if somebody is presenting compelling value and you’ve got some good reinvestment opportunities, then we’d have to look at that.

We have big businesses so it would obviously be constrained to pieces and JVs, so 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, and 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 $6.5 billion range annually.

The other thing too, Linda, is we tend to look at these on a full cycle basis, so 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, and so 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. 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..

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

Your question, please?.

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 of 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, but 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, or 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 and 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, we changed our minds.

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 different 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, and then there’s finally the smaller producers who, quite frankly, are just coming up the learning curve on how this all works, and 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, and this is not an easy thing to really absorb at 100,000 feet.

You’ve got to kind of get into what the value drivers are, and 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.

But 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, that again I think is 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, but I think people are starting to get a bit of that story..

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 that court decision on the pipe being shut down or not? Is clarity by next week before that initial August 5 deadline reasonable, or could this drag on for another few weeks here?.

I think that’s for Energy Transfer to comment on how the core proceedings are going to play out. I think that’s all I can say. It’s in front of the U.S. Court of Appeals right now..

Got it, okay. Thanks guys..

Thank you. Our next question comes from the line of Ben Pham from BMO.

Your question, please?.

Thanks. Good morning. On the U.S. election, if the polls are correct and Biden wins, what do you think the impact is on your business, if any, on your existing U.S.

assets, projects under construction, Line 3, anything else - tax rates, that’s worth commenting on?.

Well I guess, Ben, it’s a good question. I mean, that’s certainly something on everybody’s mind, I think. Specifically to 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, so 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, but certainly we don’t see any major change, and 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, we don’t have any--I guess we’re not seeking any federal cross-border permits at this point, so 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 the response to your study. It’s still early days, but quite expensive.

Are you at the point in the next 12 months to put some dollars into some pilot investments? Then also curious, is the study, is it more to gas utilities [indiscernible] are you also talking with Canadian producers more broadly exporting hydrogen on pipes and more of a broader discussion on studying the hydrogen opportunity?.

It’s probably two fronts. I would say the more imminent certainly in the utility - you know, 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, and to answer your question, I think yes, we are 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 yes, I think we can start to do some pilot investing for sure..

All right, that’s great. Thanks Al..

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, and thanks to everyone for taking the time to join us this morning. As always, we appreciate your continued interest in Enbridge and 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..