Enbridge Inc. (ENB) Q1 2020 Earnings Report, Transcript and Summary

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. [Operator Instructions] 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 an 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 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 on this 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 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 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, 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 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 discipline 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. 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 that 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 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 take or 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 mainlines competitive position. Another factor though, 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 to start. 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 recontract 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 plus we have long-term contracts underpinning industrial volume. 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, 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 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, boost 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 and 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 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 diesel was 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 yearend, 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 bounce the market. And 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, 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 main line 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 refineries were still running near their normal heavy crude slate or about 90% of their normal main line 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 say 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. And it means that we're more resilient -- 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 main line, and the market access pipes into those two critical regions. So the next slide proves that out and shows why our main line 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. And for the last six years we've increased capacity and maximize 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 delivered to the best markets and we're directly tied to the strongest refineries. In the case of our PADD II 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 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 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 has 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 a 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. And 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 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 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. 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 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 taker 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 by 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 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 that concluded that our construction plans meet its standards so that's important to. 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 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. And as well 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 the 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 can 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 down the fairway and generates strong returns. Of the $10 billion [ph] 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. And 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 plan spending in our few select areas by about $1 billion in 2020. Importantly, there are no cancellations in this list. It's really more or 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. And 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. And 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 advanced 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. Now 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 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 in a 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. As a reminder, these are not gathering lines, those have been divested. 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. And 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. And 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 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 or an involuntary basis in this environment, and the salary reductions are a shared communal lifts so to speak. Our team is up for it and we're aligned with customers and investors. And moreover, we will be even more resilient over the long-term as many of these costs action 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. Well, that is our expectation. We've further stress tested the business given uncertainties, and there's a cushion to handle of 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, 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, what this all -- see this all means for our 2020 DCF for share guidance. Combined, our tailwinds and bolstering actions are expect 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 DCP distribution reduction. But these businesses at fully budgeted levels combined our 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. So, 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 last. 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 where needed on the Q&A. So onto that section, please.

[Operator Instructions] 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. And 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 also being able to be sustained into 2021?

Yes. And the first part of the question 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.

All right. That's helpful. Thank you.

Thanks, Rob.

Patrick Kenny from National Bank Financial is online with the question.

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 - based on this decision on the nationwide 12 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 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. And 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. And 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.

Okay. Thanks.

Robert Kwan with RBC Capital Markets is online for a question.

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] [ph] 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. And I think your second part of that question was, there are a number of those shippers who are interested in even more space than they are currently shipping, just because of volume ramp-ups or changing refinery configurations.

And Vern, they've reconfirmed that they're still interested based on what they said in the original letters of support in terms of more than what they're shipping?

Yes. It will vary customer-by-customer, but the support and the levels are very strong.

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 are 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.

Great. Thank you very much.

Shneur Gershuni from UBS is online with a question.

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. And the explanation about rail being impacted first and coming back last definitely makes sense. But, I’m trying to navigate these 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. But I'm wondering if you can sort of talk about how this could be different or how you're thinking about it from a modeling perspective? But when the refiners start up and they get to closer to full utilization, is there a scenario where the heavier crudes are actually favored by the refiners and there can actually be a bigger pool out of the Western Canadian production than you would typically expect in normal circumstances? And I’m trying to understand how that impacts or colors your outlook for Mainline volumes for this year?

Well Shneur, its 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 that's where, just given where we are on throughput today is 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 crew 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?

Well, maybe I'll go first and then on the rate comparison Vern you can address that, I think. But firstly, I would say Shneur that I think you're aware, we've always assumed that XL would go forward in our projections. And I think that was the prudent thing to do. And our view is that even in that scenario, we still see a lot of demand for access to our system and to be contracted. And it goes back to what we were saying about direct connections and minimal alternatives. And that's the 3 million barrels a day that we were talking about that is directly connected or as downstream toll. So, the combination of that with our lower tolls and us accessing the most competitive markets, I think that puts us in very good position. The other part of this, of course, is after -- whether it was three or four or five years of lack of e-gas, I think one thing that that XL coming on, on its schedule and TMX does, it does allow for additional production volumes to come on. Obviously, investment has been curtailed, particularly over the last two, three months in the oil sands, just like the Permian and other spots. But I think that could unleash some new volumes coming onto the basin that would certainly, further bolster what we're doing on contracting. So that's the big picture. And then on rates Vern?

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

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

Absolutely.

Perfect. Thank you very much, guys. I really appreciate the colors today and stay safe.

Thank you.

Linda Ezergailis from TD Securities is online for a question.

Thank you. I appreciate all the fulsome update today on the Mainline especially. I realized there's still a lot of uncertainty and a lot of moving factors. But I'm just wondering how the Management and Board is revisiting? How you're going to execute on your strategic priorities over the next couple of years? And specifically, I'm wondering if there might be some sort of a shift in how you approach your U.S. Gulf Coast and export strategy. I know that was a focus and an interesting possibility, still that that is unfolding for you. And also, I'm just wondering, with, your $5 billion to $6 billion of capital capacity for investment annually. I know your priority is to grow organically. But I'm just wondering, at what point to the extent that organic growth might dissipate in this environment? Whether or not -- like what factors would need to change? And what would need to be in place for Enbridge to consider acquisitions?

Okay, it's Al here, Linda. So, first of all, great question on the overall strategic priorities that Management and the Board's thinking about. I think, I would break it down into two pieces, Linda. For sure, we're very focused on the near-term and medium-term in terms of protecting the business. So, as I said earlier, the cornerstones are in this next -- rest of the year, let's call it, the safety of the people and reliability of the system that's critical, making sure that the balance sheet is strong, and at the same time, making sure that we continue to move our execution program along. So, I think it's making sure that we keep resilient is the first priority. But I think at the same time, we also have an eye on making sure that we continue to sustain the growth in the business. And you mentioned the export strategy, at this point, unless you believe that we're not going to return to the basic fundamentals that we’re driving exports in the first place, which is global demand for energy, and that's stemming from, as you know, very well population growth, urbanization, standards of living. I think, we could see a bit of a slowdown, let's just say in growth. But generally speaking, I think our view is that we're going to 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, its $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 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. So 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 off shore French win to CPP, shows a 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 maybe 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.

Great. Thank you.

Okay, thanks Linda.

Jeremy Tonet from JP Morgan is online with the question.

Hi. Good morning. Just wanted to take a step back here and looking at the first quarter. It looks like, operations came in pretty good, better than we were expecting. And 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 like kind of a normalized world and potentially when Line 3 eventually gets in line in effect, gives you to 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 years 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 he and his team have 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 maybe just expand on this? I think it's a good point.

Yes. I think, I appreciate the boring comment. The business really has started to turn a little bit towards its roots, which is a regulated entity. And we've got an awful lot of capital going into the business. And so you see from the Texas Eastern rate case, that provides some -- I wouldn't -- I guess you'd call it a growth opportunity here on. And then the business even in this environment, Jeremy, we're only down maybe 5% on a demand basis. And as you know, it doesn't affect us because we're all reservation-based system. And most of our areas be it Gulf export, whether it's Mexico or LNG, even some of the Northeast utilities where it's challenging to build anything new small increments of growth crop up. So I feel as though from protecting that base with re contracting, which hasn't been that challenging to investing in the bones of the system to then these expansion opportunities that we still see even in this environment. I do feel like that's fine, we'll be boring and under the radar, but turnout some nice 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. I mean, they move 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.

That's helpful. That's it for me. Thanks.

Okay. Thanks, Jeremy.

Ben Pham from BMO is online with the question.

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. And the reason for that being -- and I think we've been talking about our view about energy transition, which is obviously going to take a number of decades here moving forward. But we think this is a very good way to focus on some part of our business on lower carbon. It's been a very good business for us. We've built up a very good capability. And I will say we have a pretty good inventory of projects in development in Europe. And that's our focus right now. The fundamentals there are very strong. And what I mean by that is, obviously people have a big demand for renewable power in Europe. But bigger thing these days I found is that the supply chain is really well-developed. We've joined this partnership with CPPIB. And I do feel that, the fact that we've built up our capability here with them, and make us a real player and developer in this space. So, I think if you're referring to the transaction we were talking about, that was purely about boosting the return on assets. And frankly, I like the idea of us developing projects, bringing people in and then having some promote value in that. I think that's a good spot to be in. You've seen other large players in renewable use similar models. And I think that's a good capital allocation move, but it does not indicate whatsoever that we want it to be a smaller part of the business. I think we're very keen on developing and growing it.

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. Yes.

Hey, Ben, can you explain your question again? I'm having trouble following it.

Yes, sure. Absolutely. I'm trying to clarify or confirm with you guys that you guys are also feeding in that 1.5 million production shut ins in Canada, as you triangulate down to your variance for Q2. And the way I'm thinking about it specifically is you got April in the bag, 400,000 to 1 million and you probably have a good sense of May and then you put up 600,000. So, I'm just solving for June?

Okay. I see your point is, I think the 400,000 to 600,000 is in range for the average on the quarter. And there's no real midpoint for that range. It's designed to be something that's possible. And again, 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.

Okay. All right. Okay. Thanks, guys.

Hey, thank you.

Robert Catellier from CIBC Capital Markets is online with a question.

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 are 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. So, we're already up a million barrels a day and gasoline demand since the lows in early April and it's trending in the right direction. So, 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. But it’s really driving patterns, I think that will be the biggest into watch.

Right. And in that sort of that 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.

Okay. Thanks for that. Just lastly on Line 3, what I heard from the comments is there's a little bit of a mechanical shift in the CapEx for 2020, seemingly based on the permitting timelines. But I'm wondering, if that also includes the impact of COVID and what that might have on your practical realities that has on construction or has not been included in your comments and your shift in capital timing?

I think, Rob, from a construction point of view, obviously that's not happening today and will happen later on, depending on when we get the permits. I'm not sure we see much of a construction impact. In fact, in most of the projects we're running right now in the field, those are generally working to schedule obviously a few more complications and how you work. So it's not so much the construction. I think really it has more to do with this eight week or so delay in getting those PUC orders. I suppose there could be some further COVID related issues through permitting, but we haven't really seen much of that yet. So I mean, hopefully, I'm answering your question but that's the big picture.

Yes, that was that. I just wondered about any construction changes to the construction activity that might result. But you answered the question. Thanks.

Matthew Taylor from Tudor, Pickering, Holt Company is online with the question.

Hey, thanks for taking my question here. On Slide 14, you highlighted the recovery in volume tied to demand outlook. And I think you've done a good job addressing that. I'm just wondering on the supply side, if you're anticipating barrels that were previously on the system to be structurally shut in or it would just be helpful to hear your comments on how you're thinking about supply ramping back up?

Vern?

Okay. Matthew, I think really our system and the demand in the near-term is going to be refinery demand pool driven, because prior to the COVID situation we were 40% or 50% apportioned upstream. So, we don't expect the supply situation to impact our volumes once demand picks up again. I think it'd be fair to say we would likely see storage in Western Canada to be drawn upon and then after that is drawn down a bit, then we would likely see a price increase in Western Canada and that would then result in more supply being brought back.

That's great. Thanks, Vern. And then maybe just one last one here for Bill. On natural gas, prices improve or potentially looked at three bucks at Henry Hub in 2021. I'm just curious, your expectation for customers. Do you think higher pricing will be for them to grow or for the delivery the way, I mean it seems constructive for your business, either more gas flows or healthy customers? Just wondering what types of opportunities you're seeing in the future in a better pricing environment.

Yes. I think Matthew, it'll be interesting to see the LNG dynamics for one for sure. I think we were already seeing the fundamentals for the projects that we're looking at for 2024 and beyond. They're pretty darn good. And, it doesn't feel likely to me that that type of a price change would really impact that. In an odd way, sort of shifting gears a bit, a slightly higher gas price strengthens a number of the producers that are contract holders on our system, especially in Appalachia, which is we had a fair presence in Appalachia. So, in an odd way, it's kind of good from a contracting perspective. And yet, we're not seeing the $7, $8, $9, $10 prices that might scare away demand. So, I think the outlook is pretty good when you're between the high $1s and $3.

Great. Thanks for the color there, Bill.

Andrew Kuske from Credit Suisse is online with the question.

Thank you. Good morning, guys. I think the question is probably for Colin. And historically, you've always maintained ample liquidity and it's no different this time around you bolstered liquidity during the quarter. So I guess, just the confirmation on where your liquidity is right now. And then would you be able to if the markets completely froze access to Bank of Canada's commercial paper purchase program plan?

Yes. Thanks, Andrew. So we're at $14 billion, that's end of April number effectively here last week number. But current, basically as of today, that's a big number. And it translates calendar wise into funding access efficiency through the end of '21, which is, basically by design it's a conservative outlook that potentially debt capital markets could be frozen until then they're not. They're basically back open, which is good. We'll see how that progresses. And I can confirm that that Enbridge as a strong rated commercial paper issuance work could access the Canadian program. I don't think we have really -- to-date we are issuing commercial paper. The market is fine. So I've been, I guess pleasantly surprised by the collective actions of central banks right? And so far, it looks like debt capital markets are thawing and reopening in a constructive manner. So, I feel pretty good about funding our plan through next year, Andrew.

That's great. I appreciate the color, and then maybe one more narrow question just with the write-down, the non-cash write-down on the DCP position. How do you think about the tax attributes and the benefits you have in the future either against income or capital gains? How do you think about using that?

Could you clarify that a little bit? Specifically in DCP or more broadly.

Just on the DCP position itself, is there any tax benefit that you anticipate rolling off that at this point in time?

Yes. No, the answer to that is not really, Andrew. I think we still have a generally a pretty low basis in our DCP tax position. So that's unchanged by the impairment down to market value.

Okay. That's great. Thank you.

Thanks Andrew.

Asit Sen from Bank of America is online with the question.

Good morning. Thanks for the interesting details on Slide 12 detailing PADD II and PADD III dynamic over the near-term, PADD III lacking storage, while PADD III has storage and export capacity. My question is on storage, thoughts on what you're seeing in the storage market both at the Cushing or PADD III or WCSB? How close are we to the tank top? That's number one.

Yes, I'll go first. I think probably a couple of weeks ago, maybe three, we would have been thinking that may looked like we could see getting pretty close to tank tops. I think you saw the inventories come out yesterday. There was a couple good numbers in there. So, I think our view right now is we probably don't see us getting close to that in May, probably think of it as a shift out into June. And few reasons for that, one I mentioned. But, we are starting to see a few more barrels headed out a Cushing down into the Gulf. And part of that is Strategic Petroleum Reserve has helped that out. So generally, we think of it as a shift about a month out in terms of criticality, let's put it that way to tank tops. Vern, I don't know if you want to comment on Western Canada or our own operational tankage at all?

Sure. I think Western Canada is not expected to fill in May as well. Western Canada, I think if you read the published stats we will be in that 75% full level by the end of May. For us, I think like many storage operators we have, as Al mentioned previously, operational storage and merchant storage. We've been actively looking to add storage to our system over the last month or so. In fact, we figured out ways to add 3 million barrels of incremental storage to our customers. Really, that comes from deferring some API tank and inspections and working with the regulator to do that. Changing our operating parameters or how we fill specific storage sites so that gives us more flexibility for our customers. And then finally, we're in the process of getting a piece of deactivated pipe associated with legacy Line 3, approved by the CERO. We could put that into surface as temporary storage for our customers as well. So, we like other companies are actively looking at our assets to see what we can do to help customers out with more storage.

Thanks for the color. And from a broader industry perspective as we emerged from this pandemic situation and assuming a lower demand curve. How do you see North America pipeline utilization evolving out? And does it essentially price out crude by rail for the medium-term? And is it really a call on the export market at some point?

Do you want to take that Vern?

Sure. Yes, I think out of Western Canada, for sure, crude by rail will be the first to be hit. And given that crude by rail is moving at about 400,000 barrels a day, prior to demand destruction with COVID, we expect that pipeline utilization will come back first out of Western Canada, for sure. And then we expect our heavy system to be very full but when economic activity recovers just because as we mentioned before, heavy crude oil provide the best margins for refiners across North America. I think you are right. The lighter crudes will have a longer ramp up to come back. And they're at more risk of not being entirely full. And it has knock on effects to the export markets just because the excess like crude out in North America has been exported and then to some degree is continuing to be exported as well.

Thank you.

Michael Lapides from Goldman Sachs is online with the question.

Thank you for doing this extended call and obviously for taking my question [indiscernible]. I'm looking at Slide 10, and I'm looking at kind of some of the other pipe gas out of the Mainline. Just curious, refer to them and I'm thinking pipes like Dapple or Gray Oak and expressing Platt. When you say there are take or pay, are you saying there are 80% to 90% take or pay and just the 10% walk up it is open? Or are they partially take or pay significantly less than any percent in the rest is more volumetric?

I don't know, Vern do you want to take that?

Yes. I think it's the latter where it's -- sorry, it's 80% or 90% take or pay and about 10% to 20% is spotter walk up. So, those pipelines will see a minor impact on their revenues, but nothing significant.

And Michael, just as a reminder, that spot capacity the 10%, for example, that's usually by regulatory requirements. So, we don't have a lot of choice in that one.

No, understood, that's a walk up. And Vern, can you talk a little bit about what you're seeing volume wise? Meaning, have you seen dramatic volume changes on Dapple or in Gray Oak? Gray Oak has not been operational that long. But just in the last month or so what you guys have seen in the near-term?

Well, I think, so Gray Oak obviously as a new pipeline. And again, it's predominantly take or pay. There is obviously, probably a small decline in the spot volume versus our expectations, similarly in Dapple where the walk up volumes will be lower.

Got it. And then last and this may be a Colin question. Can you just clarify what is growth CapEx for 2020?

Yes. Michael, thanks. So at Enbridge Day this slide had a total CapEx of $6.5 billion of which $1 billion was maintenance of $5.5 was our gross CapEx spend projection for this year. So that's now down to $4.5, so $4.5 plus one.

Got it. The $1 billion that you're deferring, can you put that and you may have done this already? And apologies if I misunderstood it. Can you put that $1 billion into buckets? Meaning what percent is for X business or X type of asset? What percent is for Y?

Yes. I’ll give you a little bit more there. So I think we talked about probably the biggest piece, which has about $300 million of the $1 billion, which was mechanical, just best case time shift for Line 3 U.S. The rest of it is $50 million here, $100 million there. The next biggest is, also probably in the permitting bucket would be around PennEast and some permit delays we've seen there that's probably $200 million. So that's about half of the $1 billion together there, Line 3 in PennEast. And then the rest are smaller like I mentioned a little bit at the utility call it a $100 million or a little bit more, a little bit of compressor modernization in Bill's business, maybe another $150 million there. And then the rest is pretty small. So it's probably about half in the permitting bucket and maybe half in the call it COVID construction delay bucket.

Got it. No, that's super helpful, Colin. And I hope you don't mind, I’ll cheat. I'd like to ask one more, and it's a Bill question, which is bill, after getting the successful TETCO rate case, do you have other pipelines you're looking at where you see a significant filing ahead because of kind of undermining your expectations at that pipe in the U.S.?

Well, I wouldn't want to front run any of them, Michael. But I would say we're very close to a settlement on Algonquin. And we would expect that could be a positive impact. It's just too early to say what that could possibly be. We also have filings or settlements that we would like to pursue over the next three months. East Tennessee Alliance, Maritimes, Northeast, you got to keep in mind these all pale in size and scope by comparison to Texas Eastern. So while we may see positives, the Texas Eastern rate case and getting that behind us was by far the largest. I hope that's a little enough color. Maybe I'll add one more thing in it, all of these pipeline systems, except for the very newest ones, the integrity work and the modernization emissions work that we're doing is significant. So I said boring earlier, but it's a very important part of our growth story.

Got it. Thank you, Bill. Thank you all for taking my questions.

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.