Enbridge Inc

Welcome to the Enbridge, Inc. First Quarter 2020 Financial Results Conference Call. My name is Patrice, and I'll 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 1 on your touch-tone phone. Please note that this conference is being recorded. I will now turn the call over to Jonathan Morgan, Vice President, Investor Relations. Jonathan, you may begin.

Thank you, Patrice. Good morning and welcome to the Enbridge Inc. earnings call for the first quarter 2020. I hope you're all doing healthy and well. 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, 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 to the website shortly after. In terms of Q&A, we'll prioritize calls from the investment community and if you're a member of the media, please direct your questions to our communications team who will be happy to respond immediately. Generally, we target to keep these calls to roughly one hour, however, we recognize that There's a lot of information to cover during these unprecedented times, so we'll be a little more flexible this morning. That said, in order to answer as many questions as possible, please try to limit your questions to one plus a follow-up. As always, our investor relations team is available for your detailed follow-up questions afterwards. On slide two, I'll remind you that we will 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 the risks and uncertainties outlined here and discussed more fully in our public disclosure documents. We'll also be referring to the non-GAAP measures summarized below. With that, I'll turn it over to Al Monaco.

Okay, thanks, Jonathan. Good morning, everybody. I'm going to open this up with a few comments on the COVID crisis and how we're approaching it. Everybody is searching for analogs to figure out where society, the economy, and capital markets are headed. The reality is we've never lived through something like this, and certainly not in energy, at least in my 35-plus years in the industry. COVID has threatened millions of people, and it's hit fast and wide. One of my best days recently was the news that most of our few staff impacted by COVID were fully recovered. We all recognize that healthcare workers and emergency responders are the heroes of In the same way, I'm extremely proud of how our own front lines have responded. The women and men of Enbridge who've kept our systems running normally in the face of their own anxieties. That's especially true for our people who remain on the job site, like in control centers, operations, field staff, and support functions. I want to thank our people for their sheer dedication they've shown to their work, our customers, and to the people that consume energy every day. In terms of our response, we implemented our business continuity plans very early on with the priority of protecting our people. For critical functions, we put in additional safety protocols to maintain full service. On our approach to managing this downturn, our resilient business model and the actions we took over the last three years put us in a strong position coming into the year, That's going to allow us to weather this storm as the vast majority of our EBITDA is unaffected, and that's why we're maintaining our guidance, and we're stressing that outlook with various scenarios. Even though we're resilient, we're staying ahead of the game and taking action to make sure we stay that way. What's guiding us through this period are three cornerstones. The health and safety of our people and reliability of our systems, that's number one. maintaining a strong balance sheet with ample liquidity, and hitting our financial targets to support our conservative payout ratio and further growth. We're starting to see more positive economic signs, but none of us for sure has a crystal ball on this in terms of the pace of the recovery, so we're watching the signposts very closely. With that context, I'm going to start with Q1 highlights and explain what exactly we mean by resiliency. Then I'll cover how we see the North American crude oil fundamentals and our liquids mainline outlook. Colin's going to review the Q1 results, the financial position, and the 2020 outlook. And as Jonathan said, we'll be a bit longer to get through our remarks today because there's a lot to cover. So moving to the Q1 highlights on slide four. So the first quarter seems a long time ago now, and we're all focused on the rest of the year, but there are a few things that are relevant to that. Operationally, our businesses ran very well. Distributable cash flow was strong and exceeded our Q1 budget. While COVID was a focus, we also advanced the priorities we laid out for you at Enbridge Day. Continuing with disciplined capital allocation, we sold $400 million in assets at very good valuations. This includes today's announcement that we're selling 49% of our equity interest in three French offshore wind projects to our financial partner. More on that later. The Texas eastern rate settlement took effect, and we made headway on Line 3 permitting in Minnesota. To prepare for any economic scenario and make sure we stay ahead of the game, we're taking further bolstering actions. We're reducing 2020 costs by $300 million. That includes salary rollbacks across the organization, including myself, senior management, and the board. And we've already boosted excess liquidity by $5 billion to $14 billion to provide even more buffer in case debt capital markets shut down for an extended period. And we've refined our 2020 capital execution schedules in light of COVID-19 We expect about $1 billion of capital will be naturally deferred to next year without changing schedules in terms of our EBITDA uptick. First, EBITDA on the next slide now, on five here, EBITDA came in at $3.8 billion and DCF at $2.7 billion or $1.34 a share. That's a very good result, especially given the weather drag in the utilities. and narrower basis differentials in energy services relative to last year. We did very well this quarter in both of our core pipeline businesses. Liquids had record mainline volumes and higher throughput on our Gulf Coast access pipes, and gas transmission saw higher revenue than the new TETCO rates. Because of that, DCF per share was about $0.05 higher than budget, which is a plus in terms of how we're looking at the full year. Colin will get to the outlook, including the various puts and takes we see for 2020, but bottom line, as I mentioned, is that we expect to be within the guidance range of 450 to 480 of DCF per share for the year. That expectation stems from the resiliency of our business I referred to, so let me speak briefly to that on slide six. This group would have seen this slide before, which illustrates our low-risk pipeline utility model, but we've expanded it a bit here to show the various commercial structures and put our liquids mainline in the bigger picture Enbridge context. Starting from the top left box here and going counterclockwise, we have over 40 different sources of EBITDA, diversified by business line, commodity, size, and geography. The common thread is that virtually all of our cash flows are driven by market pull, with direct connections to end-use markets. 95% of our customers are investment-grade with strong balance sheets, and you've seen our list before. We've got good conservative financial policies reflecting the stability and predictability of our cash flow and low business risk. On the top right, 98% of our EBITDA is underpinned by cost of service, long-term taker pays, or similar structures. We include the mainline CTS agreement in this category, and here's why. CTS has been in place for nine years now and has worked extremely well for customers, us, and others through commodity and economic downturns. We're protected from any normal volume disruption because of the very strong supply fundamentals and the mainline's competitive position. Another factor, though, is contractor taker pays, both upstream and downstream, that effectively push and pull volume through the mainline. And ultimately, if needed, we have cost of service backstop, but our customers haven't wanted us to go in that direction. I'm going to expand on those issues in a few minutes when we discuss the mainline outlook and contracting. But first, let me speak to the resiliency of the other parts of our business on slide 7 to start. Almost 30% of our EBITDA comes from gas transmissions. These pipes connect directly to the largest end-use markets you see on the map here. We love this business because it's utility-like. Virtually all of our cash flows come from reservation-based revenue contracts, and over 90% of our customers are investment-grade, mostly utilities. A great example of the predictability of the business is that we just recontracted 99% of available Texas Eastern capacity for terms. Over the balance of this year, we don't expect much impact from COVID on this business. Earlier this week, we had an incident on Texas Eastern, but thankfully nobody was injured. The line has been shut down and we're working to assess the cause. We'll keep you posted on that one as we find out more. Another slice of the pie and absolutely great and underappreciated business in our view is the gas distribution utility, one of North America's largest and fastest-growing businesses. This is now on slide 8. Enbridge Gas makes up 13% of our EBITDA, and it serves a market of about $14 million. It's essentially regulated cost of service, but we're currently operating under incentive framework. We're earning a very solid ROE due to synergy capture from the amalgamation of our two utilities. The majority of our load here is residential, plus we have long-term contracts underpinning industrial volumes. Again, we don't expect to see much impact from COVID, and the utilities should perform in line with our expectations, weather adjusted. Moving to slide 9 in our renewable power business, which generates about 5% of our consolidated EBITDA. This business is built on the same type of commercial underpinning I just went through. Projects are backed by long-term PPAs, which provide guaranteed offtake and pricing. and we have strong investment-grade customers there as well. We remain on track to meet our budget this year. We also have a good European growth hopper supported by excellent fundamentals and well-developed supply chains now in this business. We now have three large offshore wind farms in operation and several in development, and bringing in the financial investor I mentioned on the three French offshore projects boosts our return here nicely, and minimizes our capital outlay. Now moving to liquids pipelines on slide 10. Nobody argues that we have North America's premier liquids pipeline system. It gives customers a full path solution from Western Canada to key refining markets in the Midwest, the Gulf, and Eastern Canada. Roughly 90% of the revenues come from refiners and integrated producers that rely on our system for feedstock. Importantly, the main line is flanked on the upstream end by long-term contracted pipes and on the downstream end with our contracted market access pipes. The contracted lines give a solid cash flow on their own, but those contracts essentially push and pull volumes through the main line. Let me now shift to the outlook for crude oil on slide 11. Obviously, we're living through an unprecedented level of demand disruptions. It's being driven by a severe pullback in product consumption from the lockdown, virtually no air travel, significantly reduced miles driven and negative economic growth. So you can see on the slide here, diesel has actually fared slightly better as large transport vehicles, rail and shipping are still moving, which is why heavy and medium crude demand has held up better than light. The chart shows 2020 North American crude demand pre and post COVID. The trough that you see in Q2 is expected to be roughly 6 million barrels per day off, with April and May being the worst, and then recovering gradually. This return assumes that various measures put in place are lifted over the balance of the year, and a staged reopening of retail and services in Q2, lifting border restrictions by the fall and travel restrictions by year-end. That's what goes into those numbers that you see. Given the magnitude of the demand hit and storage levels getting close to full, producers, as you all know, have cut capital and are shutting in barrels to balance the market. And after accounting for storage build and exports, the forecast we have is about 3 to 4 million barrels per day of shut-ins across North America actually happened a little bit faster than we had anticipated. Storage will undoubtedly take time to be worked down, but even though that provides steady feed for pipelines, it will continue to put pressure on oil prices through 2020. So in this outlook, production lags recovery in demand perhaps into 2021 before it's restored to previous levels. At least that's our view. Slide 12 shows how we see this impacting our core markets. Overall, refinery utilization is down sharply, as you know, by about 30% to 50% since January. But this is not a homogenous refinery market. If you look at the core markets we serve in the Midwest, Eastern Canada, and the U.S. Gulf, mainline deliveries, these are the purple squares that you see here, have held up better than overall refinery demand. In April, the Chicago area and Minnesota refiners were still running near their normal heavy crude slate, or about 90% of their normal mainline take. The reason for that is those customers run highly competitive and complex refineries. So we've showed you here the Nelson Index, and in this case, a higher number is better. Same story in Pad 2. That's an export region, of course, so the Nelson Index compares favorably to global refiners. This competitiveness that we're talking about here comes from the scale, coking capability, and reliable access to heavy crude supply. which drives better margins. And it means that they're more resilient to the downturn and first to recover when demand picks up. The reason I'm talking about all of this now is to illustrate the criticality of our mainline and the market access pipes into those two critical regions. So the next slide proves that out and shows why our mainline has always been heavily utilized in virtually all market conditions. throughput increased from 1.5 to 2.85 million barrels over the last decade through low-cost expansions and optimizations. You've tracked those through the years. And for the last six years, we've increased capacity and maximized utilization, even in the 2009 financial crisis and the 2015 commodity downturn. In fact, we've had to turn away volumes, particularly heavy barrels, with 40% to 50% apportionment in the last three years. Again, that's because we deliver to the best markets and we're directly tied to the strongest refineries. In the case of our Pad 2 in Ontario markets, they also lack sufficient storage directly in the region and depend on the mainline to deliver feedstock in all market cycles just in time. But the uniqueness and depth of this downturn means everybody's affected. So let's get to the mainline outlook on slide 14. Obviously, Western Canadian producers have been hit hard. Our estimate is that 1 to 1.5 million barrels of production comes off in Q2. April was about 1 million, as you can see here, followed by gradual recovery. How that reduction, though, gets spread out depends on a number of things. Rail usually comes off first and fast, given a higher cost. Then local refinery demand is impacted, and then ex-Alberta pipes. As the largest pipeline out of the basin, not much of a surprise we're affected with this scale of demand disruption. In April, the mainline ran at about $2,450,000. barrels on average, so we absorbed about 400,000 of the estimated 1.1 of shut-in I talked about relative to our Q1 average throughput. Based on what we see today, we're expecting the average Q2 mainline impact to be in the range of 4,000 to 600,000 barrels per day, with a gap to normal volumes tapering as we move through the year. Along with the rest of the year shown here, this outlook translates to throughput about 300,000 barrels per day lower than Q1 on average for the next nine months. At a high level, 300,000 barrels per day of volume for the next nine months works out to about 2% of consolidated EBITDA, and Colin will go through more of this in a few minutes. Given the strength of the mainline position and the refinery pull once demand picks up, we'd expect volumes to return to previous levels. All that to illustrate the diversification and strength across the business, including other parts of liquids, makes the impact to the mainline manageable. Let's now move to another subject of interest, which is mainline contract offering on the next slide. We filed our contracting application late last year, including letters of strong support from shippers who make up about 75% of throughput. Based on very recent customer soundings, these shippers remain supportive and will participate in the hearing. That's important because after two years of negotiation, those shippers are essentially saying that the commercial deal we struck, including tolls, works for them, and they want to commit volumes in an open season. It wasn't easy getting there at all, but we landed on a good balance, and the deal benefits everybody, producers, integrated companies, and refiners. In the case of refiners and integrated producers, contracting gives them access to reliable feedstock at stable and competitive tolls. Producers get guaranteed access to our system, so while many haven't historically been shippers, the offering allows them to balance the playing field with refiners, which is usually the issue that we hear about. And by the way, they'd be securing access to the most competitive refining market in North America. So we believe we will receive significant and sufficient commitments to contract the mainline for three reasons. The strength of Pad 2 and Pad 3 refiners and our physical connection to those markets, the competitiveness of our tolls, and the fact that shippers representing about 75% of current throughput support the offering. To illustrate that a bit further on slide 16, in total, we have 3.1 million barrels of volume being pulled by premium markets. We're directly connected to about 1.9 million of PAD2 in Ontario demand, and nearly all of this is heavy refining capability. These refiners rely on our system and have limited alternatives, so they're keen to lock down access to Canadian heavy barrels. We also have a million barrels per day of downstream take-or-pay contracts that draw barrels down the mainline through to Quebec, Patoka, Cushing, and full path to the Gulf Coast. The Gulf is hungry for Canadian heavy as Venezuela and Mexico volumes are in decline, so We've got an opportunity here over the next decade for Canada to gain market share. Slide 17 shows the status of the regulatory process and the milestones. In late February, the CER issued the process for participation in the hearing and broadly defined the scope of it. This would normally have been followed by a hearing order and timeline, but the CER is addressing submissions. We filed a response to those submissions on May 1, and we expect a decision sometime in May. I'd encourage you to read that filing, and hopefully we'll see a clear timeline soon so we can get the process moving again. Switching gears now, but still with liquids now, to the progress on the Minnesota permitting and regulatory process for Line 3. This is on slide 18. This is our usual update on the two tracks. A couple of more items checked off, as you can see here, since Q1. On the regulatory track, last Friday the PUC issued its official orders confirming the recertifications of the EIS Certificate of Need and Route Permit. This took a bit longer than expected, but it is a good outcome. On permitting in late February, the Predolution Control Agency issued the Draft 401 and closed their public comment period in April. The draft permit was comprehensive and concluded that our construction plans meet its standards, so that's important too. They're now considering the public comments before making a certification decision. The DNR and Army Corps are making progress and the Corps concluded their supplemental public comment period. Once these agencies are done their process, the PUC will be in position to issue an authorization to construct. And we've said this before, but Once we have better clarity on the final timing of permits, we'll be able to provide an ISD estimate. And again, once we land on the permits, we've said construction should take between six to nine months. My final comment on the business update is to summarize the priorities. This is now on slide 19. Since the outset of COVID and related oil price shock about eight weeks ago, We've scrubbed the entire business to make sure we stay strong and prepared for an extended shutdown if that happens. The priorities we outlined at Enbridge Day are the same, but we're also taking some near-term actions. The first, as I mentioned, is to protect the health and safety of our people and the operational liability of our assets so we keep running well, and that's in very good shape. We're reducing costs by $300 million. We've increased excess liquidity to $14 billion. And because of some slowdowns related to COVID, about $1 billion of capital spend will be deferred into the next year. These actions, along with our low-risk approach to the business, will make us even more resilient. So now over to Colin for the financial review.