Enbridge Inc

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 1 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 Ember Jink second quarter 2020 earnings call. Joining me this morning are Al Monaco, President and Chief Executive Officer, Colin Grunding, 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. 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. And 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. 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 a mid-year checkpoint on the priorities. So 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. 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? So 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. So 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. Now, 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 give us $2.5 billion or so in incremental EBITDA. So 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. So in sum here, we see long-term growth continuing from these two sources. So 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 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 Collin 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 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. And finally, good progress on priorities. We sanctioned another billion of new projects. That was good to see. Good outcomes on our rate cases, and line three is moving forward, as is mainline contracting review. And I'll come back to those specifically in a few minutes. So 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, 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, 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 refinery utilization picked up significantly, and that's shown in the gray 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. So 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 a 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. So obviously we came in at the favorable end of the 4 to 600 we talked about on the Q1 call for decline this year, so that was a good outcome. And 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. And 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 three update now on the next slide. This is our usual milestones chart with the PUC's 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 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, 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. And as a reminder, the 401 covers construction methods and scope of work rather than whether the project is needed or the route required. And 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. And they've also, as you see on the 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. So 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 and 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. 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, 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 sure of the energy they need to keep this economy moving, especially bringing ourselves out of COVID. Second point on this, 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 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. 75% of the legislature, Democrats and Republicans alike, voted for it last month. 23 counties formally endorsed it, and a strong majority of Michiganders wanted to get going. Slide 14 is a brief update of the mainline contracting. So 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, greater than 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 main line 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. And that will 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 netbacks for producers and maximize provincial revenues. That's because WCSB crude prices offer marginal transportation costs 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, but we'll likely need now to extend interim rates for a period of time, and the CTS prescribes the tolls during that period. So 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 $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 $150 million annually. We also filed on Alliance, East Tennessee, and Maritimes, and settlement discussions with customers we'll 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. So Sable Trail Phase 2 went into service in May, and on the 1 billion P South project, construction is progressing well. And 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 three, 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-19. 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 facilities 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 21-22 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 SID'd two new investments in France. The most recent, FECOMP, is a 500-megawatt wind farm located about 13 miles off the northwest 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. So 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 again. So with that review, I'll pass it to Colin to go over the financial results.