Enbridge Inc Q1 FY2020 Earnings Call

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. 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 Gruending, 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 and podcast of the call will be available today and a transcript will be posted to the website shortly after. In terms of Q&A, we will prioritize calls from the investment community. And if you are 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 there is 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 to Slide 2, 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.

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 analogues 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 has 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. In the same way, I'm extremely proud of how our own front lines have responded, the women and men at 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 ensure we stay that way. What's guiding us through this period are three cornerstones. The health and safety of our people and the reliability of our systems, that's number one. Maintaining a strong balance sheet with ample liquidity and hitting our financial targets to support a 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 in terms of the pace of the recovery. So we're watching the signpost very closely. With that context, I'm going to start with Q1 highlights and explain what 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 and the financial position, and the 2020 outlook. And as Jonathan said, we will 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 4, 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. Operationally, our businesses ran very well. Distributable cash flow is 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 ensure 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. We've already boosted excess liquidity by $5 billion to $14 billion to provide even more of a 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. 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 Slide here, EBITDA came in at $3.8 billion, and DCF at $2.7 billion or $1.03 for a share. That's a very good result, especially given the weather drag in the utilities and narrow 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, we expect to be within the guidance range of $4.50 to $4.80 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 6. 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 counter-clockwise, 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. 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 take-or-pay, 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 is contracted take-or-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. Then 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. Almost 30% of our EBITDA comes from gas transmission. 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 that predictability of the business is that we just recontracted 99% of available Texas Eastern capacity for term. 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. 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 where we're currently operating under incentive framework. We're earning a very solid ROE due to the synergy capture from the amalgamation of our two utilities. The majority of our load here is residential and we have long-term contracts underpinning industrial volume. Again, we don't expect to see much impact from COVID. The utilities should perform in line with our expectations, weather adjusted. Moving to Slide 9, and 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 guarantee of pricing. 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. 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 mainline is flanked upstream by long-term contracted pipes and downstream 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 mainline. Let me now shift to the outlook for crude oil on Slide 11. Obviously, we're living through an unprecedented level of demand disruption. 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 that 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 traffic 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. After accounting for storage build and exports, the forecast we have is about 3 million to 4 million barrels per day of shut-ins across North America, which 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 throughout 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 purple squares that you see here have held up better than overall refinery demand. In April, the Chicago area and Minnesota refineries 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 showed you here the Nelson index, and in this case, a higher number is better. Same story in PADD II, 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. 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 million to 2.85 million barrels over the last decade, through low cost expansions, and optimizations we’ve tracked those through the years. We've increased capacity and maximized utilization for the last six years 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 delivered to the best markets and we're directly tied to the strongest refineries. In the case of our PADD II and 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 million 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 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 given 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 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 400,000 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. Colin will go through more of this in a few minutes. Given the strength of the mainline position and the refinery toll, once demand picks up, we'd expect volumes to return to previous levels. All that illustrates the diversification and strength across the business, including other parts of liquids, making 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. 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 systems. 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. 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 PADD II and PADD III refiners and our physical connection to those markets, the competitiveness of our toll, and the fact that shippers representing about 75% of our 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 PADD II 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 1 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 with 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 road permit. This took a bit longer than expected, but it is a good outcome. On permitting, in late February, the Pollution 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 Corp are making progress and the Corps concluded their supplemental public comment period. Once these agencies are done their process, the PUC will be in a 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 of $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.

Thanks, Al, and good morning, everyone. I'll start off with our financial results, discuss our financial position, including bolstering actions, and then finish with our outlook. Pick up on Slide 20, our financial results came in better than expected. The results highlight the resiliency and diversity of our business. I'll run through the results in an abbreviated manner. Liquids pipelines had a very strong first quarter. Adjusted EBITDA increased $190 million. The mainline system was once again full and oversubscribed, delivering an average of 2.84 million barrels per day reflecting the capacity optimization work conducted in 2019, in which we talked a lot about last year. We also benefited from a full quarter of the $0.20 tariff surcharge from the Line 3 Canadian segment, which entered service in December. The Gulf Coast and Mid-Con systems, and the Bakken system all had another strong quarter as well, continuing the trends over the sequential quarters. In gas transmission, EBITDA was up around $60 million. Most of this is from incremental revenues on Texas Eastern from its recent rate settlement effective June of last year. The settlement provides approximately Canadian $120 million of annualized EBITDA uptick to us, which is a little better than we previously guided. Gas distribution EBITDA was down at $84 million compared to last year. This is largely a function of warmer weather this year and colder than usual weather last year. Further, we continue to grow the utility rate base through customer growth in the area of 40,000 to 50,000 new customers per year, and we're achieving our targets synergies from the amalgamation. Our power business was down slightly for the quarter. EBITDA was positively impacted by our German offshore wind farm being placed in service late last year, and its adjacent expansion placed into service in January. However, these contributions were offset by lower EBITDA at Canadian wind farms due to less favorable wind resources. Energy services was down $189 million from the first quarter of last year. As we mentioned before, Q1 of last year was exceptionally strong, whereas the small loss we're seeing in the first quarter of this year reflects narrower location differentials and limited storage opportunities that didn't fully cover some of the facility demand charges. So, that's why this quarter's contribution is slightly negative. Finally, eliminations and other was $25 million favorable compared to the first quarter of last year. This is primarily due to higher realized foreign exchange hedge settlements, as well as the timing of O&A cost recoveries from the business. Moving on to Slide 21, DCF for the first quarter was $1.34 per share compared with $1.37 last year. As we just discussed, EBITDA is fairly consistent quarter-over-quarter. As you look through the rest of these drivers, they consist of a number of smaller puts and takes. Collectively financing costs, maintenance costs, and taxes are trending as we have been expecting, just some timing difference is showing up during the quarter. So, in summary, we're ahead of where we expected to be at this point in the year. I'll then move on to Slide 22, and discuss our secured growth portfolio. Executing on our secured growth program remains a priority. This now $10 billion portfolio of high-quality projects is well diversified, commercially straightforward, and generates strong returns. Of the $10 billion capital program overall, and I think some overlook this, about $4.5 billion is spent already or will be project financed, leaving a very manageable $5.5 billion to spend. We've got ample capacity to fund this within our equity self-funding model. Turning to execution, we've put health protocols in place in the field, and execution of the program overall is continuing to progress well. However, we expect COVID and regulatory slowdown to delay planned spending in our few select areas by about $1 billion in 2020. Importantly, there are no cancellations in this list. It's really more so a shift by weeks or months of spend. For example, for COVID-related matters, deferral of our utility customer adds until next year due to temporary housing construction, pause in the GTA. In the permitting category, we were seeing delays on PennEast. As we discussed, we received our Line 3 U.S. Minnesota PUC written order, but it was delayed a little bit. So we can see spending shift by six weeks or so as we refine our construction plan. As a reminder, we conservatively planned in 2020 being substantially the entire rest of the Line 3 U.S. stand of $2 billion. So consider this about a $300 million refinement down to 1.7 for Line 3 U.S., for example. Importantly, we don’t anticipate any material impact to in-service dates, given the flexibility and contingency built into our project plans and prior guidance. Once in service, the secured growth will add an incremental $2.5 billion of highly reliable cash flows and advance our strategic priorities. So execution pace is obviously still our objective. On to Slide 23, we came into 2020 with the balance sheet in great shape and ample liquidity to fund our growth program. In Q1, we've taken additional actions to further bolster excess liquidity. We've proactively issued $4 billion of term debt at attractive rates through April of this year, including an issuance from our A-rated utility, which was the second or third issuer post-COVID, which helped to follow the Canadian debt capital markets. We also added $3 billion of committed credit facilities from our large banking group in early April. After considering Q1 maturities and capital spending, our available liquidity now stands at about $14 billion. This liquidity gives us plenty of access to funds all the way through 2021 without tapping the debt capital markets. And remember, we're in an equity self-funding mode too, so our equity component is being funded internally. In terms of balance sheet metrics, for the full year, we continue to expect debt-to-EBITDA to be well ahead our 4.5 to 5 times target range. Turning to Slide 24, we’ve sold another $400 million of assets this year as we continue to recycle or high-grade our capital. This includes the sale of the Montana-Alberta Tie Line and the Ozark Gas system, which combined total about a $0.25 billion. Neither of these assets were core to our strategy, but we're attracted to others, so we fetched good value again. We've also announced a further step in our partnership with CPPIB, whereby they've purchased a 49% interest in our 50% share of three offshore wind French projects, which are in development. The proceeds represent a promote and their share of expenditures incurred to date, and then they'll contribute proportionate capital going forward as we develop these projects with our other local partner EDF. To be clear, we still like these assets and this business. This transaction will boost our return, syndicate our development risk, and expand our partnership with CPPIB, who are also keen to grow this business. Together, these three asset sales reflect our continued focus on capital allocation discipline and further reinforce our financial flexibility. Let's move to Slide 25 now, where I'll highlight another key component of our financial strength, mainly our customer base, which is 95% investment grade. Individually, as you can see, each business is very strong with over 95% investment grade customers, respectively. But our best credit assurance is that we deliver to end-use markets, as mentioned, where our last-mile transport is typically scarce and valuable to whomever holds it. Our customers are generally comprised of utilities, refiners, integrated companies, and our own utilities' end users. One thematic credit area that we are monitoring closely is some of the gas producing community, who ship on our interstate and provincial systems. As mentioned, we carry very good collateral. However, if more drastic action was required, we expect we could remarket our long-haul capacity with others at or near existing rates. On the whole, we believe this customer credit strength differentiates us from the peer group and ensures we're financially resilient. Now turning to Slide 26, our rating agencies value our financial strength and resiliency too. All of the agencies assess our business risk as either A or excellent, which is among the best in our sector and reflective of our low-risk pipeline utility model. Let me spend a minute on this as it's an important input into ratings. Our diversity, scale, competitive position, commercial model, and simplified structure all matter a lot in this environment and in this risk determination. They're all things that are dear to us and it’s actually how we run the business. Some forget we have a big utility in the portfolio, an A-rated utility, which can’t be forgettable. It is unique in our midstream space. Our other operating companies are similarly well-rated. Texas Eastern, for example, was recently upgraded by one of the agencies to A credit last month. We've actively strengthened our financial credit metrics too, and believe they firmly support strong investment-grade ratings at the BBB plus level. We continue to be in regular contact with each agency providing ongoing business updates. Based on our discussions, we have no reason to believe that their assessments have changed either. In fact, Fitch just reaffirmed Enbridge’s BBB plus credit rating in mid-April. On Slide 27, in addition to bolstering our financial strength and liquidity, we're reducing costs by $300 million for the remainder of 2020. We believe it's prudent to do so under the circumstances with the unique volume situation and given uncertain industry times. We've combed through the business over the last eight weeks, looked at everything, and identified several actionable areas of focus for cost reduction as you can see on the slide. These include reductions to outside services and supply chain costs, companywide salary reductions, and finally, a voluntary workforce reduction program. Combined, our approach to operating cost actions have been carefully targeted. We aren't intending on eliminating jobs on an involuntary basis in this environment, and the salary reductions are a shared communal lift, so to speak. Our team is up for it, and we're aligned with customers and investors. Moreover, we will be even more resilient over the long-term as many of these cost actions sustain. Moving now to Slide 28, where I'll bring it together with some of the financial sensitivities that have informed our 2020 outlook. Let's begin on the left where you'll see we've provided approximate EBITDA impacts for various Mainline volume scenarios. We provided you a few here to help translate barrels to dollars. As discussed earlier, we currently expect as much as roughly 300,000 barrels per day on average of lower throughput on the Mainline over the last three quarters of this year. It reflects a trough in the second quarter and a recovery over the balance of the year. This translates into a reduction to our 2020 EBITDA of about $300 million, or about 2% of our consolidated EBITDA. While that is our expectation, we've further stress tested the business given uncertainties, and there's a cushion to handle a further 200,000 barrels per day of volume loss on average for the balance of the year and still maintain guidance. For example, at 500,000 barrels per day, under the stress test, this is roughly 3.5% of consolidated EBITDA. In terms of tailwind sensitivities, we're benefiting from a stronger U.S. dollar foreign exchange rate and our considerable U.S. dollar EBITDA, which even after our hedging program could yield as much as $0.10 per share at current exchange rates for the remainder of the year. Lower interest rates will help too on both our new issuances and our floating-rate exposure. For example, we're setting rate resets on our preferred shares, with historically attractive coupons in the 3% even territory. Also, our strong first quarter exceeded our plan, providing an additional $0.05 running start, and cost management actions provide approximately $0.15 per share of bolstering support. So, let's move to Slide 29 and see what this all means for our 2020 DCF for share guidance. Combined, our tailwinds and bolstering actions are expected to largely if not fully offset our headwinds. To recap, there are some strong tailwinds for the remainder of the year. Our first quarter, Texas Eastern, they announced cost reductions, stronger U.S. dollar, and lower interest rates. On the headwind side, a small impact from our commodity-sensitive businesses, Aux Sable, Energy Services, and the DCP distribution reduction. But these businesses at fully budgeted levels combined are less than 2% of EBITDA. For the Mainline, we're allowing conservatively for that bigger up to 500,000 barrels per day sensitivity. So, if the pace of recovery is slower than we are currently forecasting, we should have some room to absorb that within guidance. Stepping back, looking at things today, when you add all up, we remain very confident that we'll generate DCF within our original guidance range of $4.50 to $4.80 per share. Al, back over to you to wrap up.

Okay. Thank you, Colin. So, what is in the face of probably the worst economic and energy downturn in history, our resilience has once again protected us. The diversification of assets, cash flows, and commercial underpinnings allow us to weather this storm well. But we haven't just been standing around watching this, we've been taking action to preserve our flexibility, no matter how long the downturn lasts. Given the strength and stability of our business and the factors that Colin just reviewed, we are maintaining that DCF guidance range of $4.50 to $4.80. Finally, we are not losing sight of the future either. We remain very focused on executing our secure capital program that will drive near-term and medium-term growth in EBITDA and a growing dividend. So we're now into the Q&A. Just given we're not on the same location here and to keep things moving, I'll do some handoffs as needed on the Q&A. So onto that section, please.

Rob Hope from Scotiabank is online with a question.

Good morning, everyone. First question is just on the movement of capital from 2020 into 2021 for Line 3. And I just want to get a sense, is this being driven by a view that permitting is going to take longer in the COVID-19 world? Or is it that you're baking in some additional contingency on the construction side there?

Hey, good morning, Rob. It's Colin. Yes, it's fairly mechanical. So we favorably received the Minnesota PUC written order here last week, although it took a little bit longer. So as you recall, we had budgeted and guided for the full span during this year on what I'll call the best plausible timeline. Recognizing that six-week delay, if you like, in the order, we're just basically moving that six-week spend from '20 into '21 mechanically. $300 million. Yes.

Alright. And then when we take a look at $300 million of cost savings, were any of those realized in Q1? And do you have a sense of how much could be sustained into 2021?

Yes. And the first part of the question is zero basically in Q1. These programs are all coming into effect here immediately. On the sustaining question, I think a good part of it could sustain. We'll have to see some of it, but I would ballpark it at about two-thirds at this time.

Yes. Good morning, everybody. Just with respect to the Army Corps permits still required for Line 3, and I guess the Line 5 tunnel as well, any concerns on being able to obtain these permits, just given the recent decision in Montana on Keystone? Just wondering if you see any negative read-through there for your approvals?

I'll hand that one to Vern.

Okay, thanks. We don't see any material impact on the nationwide permit based on this decision on the nationwide permit. Each project has different permitting requirements by the Corps. So the Corps can either choose to use a local permit or a nationwide permit. For the vast majority of everything that we're doing, we're all under local permit. So this decision from the Montana Corps doesn't impact the schedule.

Okay, great. And then just looking at the Mainline volumes here, I appreciate the detail, quarterly outlook here. Just wondering if you could provide an update on what the split is between lights and heavies moving down the system? And how you might be able to optimize volumes through any blending opportunities given the current space right now?

Vern?

I think, as we always are on a proportionate basis moving more heavy than light and we expect that to continue over time. As refinery demand picks up in the U.S. Midwest and elsewhere on our system, we expect that the demand for heavy will pick up first. So there are some opportunities for us to move more medium-grade crudes by blending lights and heavies as the economy recovers, if we see a slower pickup in lights, so that is a slight benefit for us as we move forward.

I think, Pat, if you just look at the crack spreads over the last month or two here to go to Vern's point, the heavies have held up pretty good. And so that's why we were saying earlier on that when things return, those should even be in better position. So that's how we look at them.

And on this recent initiative to store barrels down the Mainline, any other near-term opportunities for downstream storage? Or perhaps if storage congestion does last into 2021 after the old Line 3 is decommissioned, how are you thinking about optimizing storage later into 2021?

Maybe I'll go first on that, Pat. We've got basically two segments of storage in the business. It's a fairly large storage position overall, but the majority of it relates to operational storage that we need to manage the Mainline. I think we're in very good shape there, and it's critical that we maintain that flexibility in that operational storage. On the other parts of it though, we do have, let's call it commercial storage within the energy services business. A good chunk of that, though, is contracted for term at fixed fees. But there are parts of it, though, that we do have some opportunity to gain from the contango that you're seeing right now. And we'll see what happens this quarter on that. We should do okay, I think. But, in the bigger picture of Enbridge, of course, it's not a huge business. But yes, there are some opportunities that we're trying to capture in energy services.

Okay, that's great. I'll jump back in the queue. Thanks.

Good morning. Maybe just to start on the Mainline. Just wondering if you could talk about what the current flows and what the main nominations are, but just even higher level as you think about contracting? Can you reconfirm with the 13 shippers that submitted the letter of support that they are still absolutely on-board and specifically as well that there is potential as they initially stated to take even more volume than they're currently shipping?

Go ahead, Vern. You want to take the first shot at that?

Okay, sure. Hi, Robert. With respect to May volumes, I think we don't generally talk about what we're seeing interim month just because of commercial and market sensitivities. But I think it's fair to say that you're seeing refinery utilization tracking upwards, as we progress through April and into May. With respect to Mainline contracting on our 13 shippers, we have absolutely reconfirmed with them that they are still highly interested in Mainline contracting. In fact, all of them have reconfirmed, and most of them did provide commentary at the CER on April 24, to that effect, saying that they would like the Mainline contracting hearing process to continue and pick up the pace.

Great. If I can just finish with a question on the guidance, I guess in typical Enbridge forum, you've got the arrows, both tailwind and headwinds about the same. So overall, kind of still tracking roughly to the midpoint of guidance and at a higher level, what's the biggest risk or uncertainty in your view? Is it really Mainline volumes or is there something else?

Hey, Robert. Yes, it's Colin. So there is some artistic depiction there, but it's intentional. It's a fairly narrow range, honestly to begin with, right? It's basically a $13.5 billion EBITDA business with a guidance range of plus or minus 3%. So we feel that's fairly tight already. I'm not going to make specific commentary on where in the range, we have a range. And I think you put your finger on it, I think Mainline volume sensitivity is probably obviously the biggest moving part there. So we've stress tested it as is noted.

Hi, good morning, everyone. Good to hear everyone is safe and well. I really appreciated the detailed outlook on the Mainline that you tried to present today. The explanation about rail being impacted first and coming back last definitely makes sense. I'm trying to navigate this unprecedented environment for North American crude markets. Typically, investors have looked at transportation differentials to figure out when the call on crude actually will occur and so forth.

Well Shneur, it’s Al here, and I'll hand it off to Vern and I'll go first. I think the answer is yes. Where they've got some capacity to move heavy processing up they'll do that. I think as we referred to, that's where the margins are greatest. And just given where we are on throughput today, it's probably a good opportunity for them to ramp up and fully utilize that access to heavy barrels. So, I think that's one angle. The other one is, of course, as I said, production is likely to lag here, the demand part of the curve. And so given that we've got a lot of storage pent up in Western Canada, I think we'll be able to utilize as much of that increased demand that refiners want through this period here. So that's how we see it at a high level. But Vern, you can add if you like.

Sure. I think the big issue is with COVID, it's really been a refinery and transportation fuel demand issue for what crude is required where. So as the economy picks up and as transportation fuels begin to return to normal, you will see refinery demand go up. And you're absolutely right, heavy crude will be the first crude pulled, because that type of crude provides the best refinery margins or crack spreads for each of our refineries. So, we'll see the PADD II and PADD III heavy refiners move up in utilization a lot quicker than you'll see light crude refineries move up in utilization.

Perfect. That makes perfect sense. And then maybe as a follow-up question. With the Keystone XL approval and so forth, I’m trying to understand if and how it could potentially impact your Mainline recontracting process. At a high level, are you able to share with us whether you believe your proposed rates are competitive with the Keystone XL rates moving forward? And so, shippers would continue to support your process. Is that a fair way to think about it? Any color on that would be helpful?

I can begin by saying that we have always assumed XL would be included in our projections, which we believe is the right approach. Even with that assumption, we anticipate strong demand for access to our system and contracts. This relates to the 3 million barrels a day that are either directly connected or come from downstream tolls. Our competitive position is strengthened by our lower tolls and access to the best markets. Additionally, with XL and TMX coming online, we expect to see increased production volumes, despite recent investment slowdowns in the oil sands and other regions. This could lead to new volumes entering the basin and further enhance our contracting efforts. Now, Vern, would you like to address the rates?

Yes. I would say that we are very competitive with all markets. We feel like we'll definitely have the lowest toll into the U.S. Midwest and Eastern Canada. From both of those markets, there are almost no alternatives but the Enbridge system. Downstream markets at Patoka, Cushing, and the U.S. Gulf Coast, we are very competitive. In fact, our U.S. Gulf Coast tolls should be the lowest tolls available.

Okay. So what you're effectively saying is that it wouldn't be an impediment and you have a very good offering for your shippers?

Absolutely.

Thank you. I appreciate the comprehensive update today, particularly on the Mainline. I understand there are still many uncertainties and various influencing factors. I'm curious about how the Management and Board are reassessing your execution of strategic priorities for the next few years. Specifically, will there be a shift in your approach to the U.S. Gulf Coast and export strategy? I know that was a focus for you and remains an interesting prospect. Also, with your annual capital capacity of $5 billion to $6 billion for investments, while I recognize that your priority is organic growth, I wonder at what point organic growth might decline in the current environment. What factors would need to change, and what would be required for Enbridge to consider acquisitions?

It's Al here, Linda. First of all, that's a great question regarding the strategic priorities that Management and the Board are considering. I would break it down into two parts. We are definitely focused on the near-term and medium-term goals of safeguarding the business. The key aspects for the remainder of the year include ensuring the safety of our people, the reliability of our systems, maintaining a strong balance sheet, and simultaneously advancing our execution program. Ensuring our resilience is the first priority. However, we also need to keep an eye on sustaining the business's growth. Regarding the export strategy, unless there's a belief that the basic fundamentals driving exports, such as global energy demand stemming from population growth, urbanization, and rising living standards, will not return, we might experience a slight slowdown in growth. Nonetheless, we believe that we will ultimately get back on track. As to the capital investment you referred to the $5 billion to $6 billion. Again, I think, obviously, with potentially a slowdown in the economy, you could see overall growth slowdown in energy. I think from our point of view, in that environment if that happens, we're not going to be chasing growth at all costs if things don't fit we won’t pursue them, but that being said, I actually think we’re very well-positioned for a downturn here. If you look at the asset base and the opportunity set that comes out of it, and you circle back to the $5 billion to $6 billion per year, it's $1 billion to $2 billion for each of our main businesses, which I think is very achievable. On the gas side, again, very focused on LNG, we’re well-positioned there. Expansions of our existing systems, valley crossing, Sable Trail, Bill's got a bunch of modernization capital on the shelf there that needs to move forward. The utility through additions and expansions of the communities is there. And then, of course, on the liquid side. I actually think on the organic side, we're pretty well-positioned and I don't see major disruption in that flow. In terms of M&A, I think it's a good question. Obviously, we're scouring things all the time, that's what our corporate development people get charged with. But I would say that's pretty low on the list for us. As you know very well, we essentially repositioned and did what we needed to do about three years ago now with the Spectra transaction. So I'd say in terms of capital deployment, it's not very high on the list. We're going to be very disciplined in the next three to five years, as we have been in the past.

Thank you. And just as a follow-up, with your sale of your interest in your offshore French wind to CPP, that shows discipline in capital allocation and high grading. I'm just wondering if there are opportunities to continue to do that. What might be possible on that front, with potential financial partners maintaining partnership with you, or other ways that you could continue to high-grade and take advantage of strong demand for other types of assets that you hold?

Yes, that's a good point. Again, it's another thing we're scouring, and making sure we're always investigating. We certainly look at the three-year plan, and we always evaluate whether we can bring in financial partners. Maybe a little bit tougher in this current environment, just given some of the debt markets and so forth that are maybe less applicable for private equity these days. But we'll continue to do that. This, as you're pointing out, was a very good example. There may be a few more opportunities to do that throughout the entire business. We'll keep track and see what's out there for us to capitalize on this year.

Hi. Good morning. Just wanted to take a step back here. Looking at the first quarter, it looks like operations came in pretty good, better than we were expecting. I appreciate that there's kind of these headwinds ahead of us as you’ve talked about in the call. But if I'm just kind of thinking through this on the other side, when we get back to kind of a normalized world, potentially when Line 3 eventually gets in line in effect, gives you a full year contribution in 2021. Maybe I'm getting ahead of myself too much here. But just wondering what do you think the business looks like in that environment? And how that compares to I guess some of the prior guidance you had put out there, given how well things went in the first quarter?

Yes, I think Jeremy, I'll start, then Colin can add. I think I'll take it back to Enbridge Day here, which wasn't that long ago, really, it feels longer. But we had a three-year plan there that we unveiled, and you're familiar with it. I think we're pretty comfortable that under that three-year scenario we can still deliver on what we thought. I'm not sure the first quarter is going to tilt the balance either way on that three-year plan. I think as you're pointing out, Line 3 is a big part of that because it generates a lot of EBITDA. But I think that's the way we're looking at this. Good first quarter. We've got some bolstering actions that have helped us stay in the range. I think that's important. And then from there, I see more or less a progression in execution of that three-year plan that we laid out. So I think we're pretty much on track with what we thought.

The only thing I think I'll add, Jeremy, you're very close to this as in sales business. I think it's a subtle point, but his team has been advancing a number of rate cases on the various gas systems, which is quietly bolstering and stepping up our return on that business kind of a boring way. But I think you're right. It should be diversified solid contribution yet, we had a pretty good Q1 hitting all the trends that you've seen. So we'd like it to return to that world as soon as we can.

Actually, that's a very good point. And, given it's boring and so forth, as Colin just said, I might just ask Bill, to comment a little bit on that. Because I think the rate cases are a great point. But, the gas guys are working on so many there are other opportunities right now. So maybe, Bill, can you expand on this? I think it's a good point.

I appreciate the comment about being boring. The business has begun to revert to its core as a regulated entity. We're investing a significant amount of capital, as highlighted by the Texas Eastern rate case, which presents a growth opportunity. Currently, we're only seeing a 5% decrease in demand. However, this doesn't impact us much since we operate on a reservation-based system. Many of our markets, including Gulf export, Mexico, LNG, and some Northeast utilities, are facing challenges to develop new projects, yet small growth opportunities still arise. I believe that by focusing on re-contracting, which hasn't been overly difficult, and investing in the infrastructure of our system, we can continue to find expansion opportunities even in this environment. I am confident that we may be perceived as boring and under the radar, but we can still achieve substantial growth.

That sounds great. I mean, if Boston didn't prefer a rush in LNG, it seems like you'd have some nice opportunities there. But just want to follow up to my second question real quick. With regards to DCP, I'm kind of on the other side there. With them retracting the guide here, just wondering updated thought there as far as portfolio management. Is that something that after write down here is something to kind of exit at this point? Or are they going to need any help? I appreciate them, extremely small part of your business, but just wanted to get any thoughts there?

Yes. You've got it right there. It's not huge for us. But on the other hand, we pay attention to all of our businesses. And we're certainly not happy about taking a distribution reduction there. I'd say at this moment, the exit part of your question, I mean, it would be consistent with the fact that we sold the rest of our G&P businesses. But I think as you'll recall, we've got a bit of a tax basis issue there that makes that more challenging. I would say, though, Jeremy, at this point, we're very supportive of management's actions. They moved forward pretty quickly on reducing capital. They're making inroads on the operating costs and certainly on overhead. So, I think that's the plan right now and we're supportive of that.

Okay. Thanks, and good morning. On the renewables business, I'm curious, where does that fit in your overall strategy now long-term? It seems like that business is getting smaller over time and the other segments are getting bigger here, as well as they're just a bullish on renewables and how it fits in your portfolio?

The short answer is yes, Ben. The reason for that is we've been discussing our perspective on energy transition, which will clearly take several decades moving forward. We believe this is a great opportunity to concentrate on lower carbon aspects of our business. It's been very successful for us, and we've developed strong capabilities in this area. I should mention that we have a solid inventory of projects in development in Europe, which is our current focus. The fundamentals there are very robust. There is a significant demand for renewable power in Europe, and the supply chain has become well-established. Our partnership with CPPIB has strengthened our position as a developer in this field. Regarding the transaction we mentioned earlier, it was specifically aimed at enhancing asset returns. Personally, I believe in developing projects, attracting partners, and then realizing some value from that development. This is a strong position for us to be in. Other large players in renewables have adopted similar strategies, and I see it as a smart capital allocation decision. However, it does not suggest that we intend for renewables to become a smaller part of our business. We are very committed to developing and expanding this sector.

Okay, that's great to hear. And then my second question maybe a clip on the Mainline sensitivities and unpeeling Q2 that on that variance you put out there that range 400,000 to 600,000. Can you confirm looking at 600,000, is that – it looks like you're feeding in 1.5 million barrels a day. I wanted to check that and I guess that suggests that at June, you're probably looking at a million down on Mainline volumes.

Go ahead, Vern.

Okay. I see your point. The 400,000 to 600,000 is in range for the average for the quarter. There's no real midpoint for that range. It's designed to be something that's possible. That's dependent on whether it's a million to a million and a half in overall Western Canadian basin production declines. So at this point, in April and May, we're not close to that 1.5 at this point.

Okay. And I guess in that range you have sensitized down to 1.5?

It's designed to be a range and our outlook would be within that range.

Hi, good morning, and thank you for the very detailed comments this morning, especially on the Mainline. Most of my questions have been answered at this point, but maybe just a couple quick clarifications. We have a very similar path from the Mainline volumes that you've described, but maybe a deeper decline. I'm more curious, though, about what you're assuming in the throughput recovery that you've outlined on Slide 14. I think you mentioned reopening the border and lifting travel restrictions. Are there any other economic or policy guideposts you're looking to there? I'm thinking maybe is there a refinery utilization recovery or rate you're expecting or a GDP recovery that's baked into your assumptions?

Vern, do you want to address that?

Sure. I think Robert, the big thing you should be looking at is gasoline demand. And I think gasoline demand right now is down 3 million barrels a day in North America. That will be the factor which will drive the rate of refinery utilization and then which will derive the rate of throughput pickup for us. We're already up a million barrels a day in gasoline demand since the lows in early April, and it's trending in the right direction. Our expectation is as our transportation fuel demand goes up, refinery demand will go up and then Mainline throughputs will go up. I don’t think we’re looking at anything about opening of borders or anything like that. It’s really driving patterns, I think that will be the biggest to watch.

Right. And in that sort of group of things you’re looking at, are you expecting a full recovery in those metrics to get to your yearend volume outlook?

No, we are not forecasting a full recovery.

We have reached our time limit and are not able to take any further questions at this time. I would now turn the call over to Jonathan Morgan for final remarks.

Thank you, Patrice, and thank you to everyone for your time and joining us this morning. We appreciate your ongoing interest in Enbridge. As always, our investor relations team is available to address any additional questions you may have. And so once again, thank you and have a great rest of your day.

Thank you, ladies and gentlemen. We appreciate your participation. This concludes today's conference. You may now disconnect.