Welcome to the Enbridge Inc. First Quarter 2020 Financial Results Conference Call. My name is Patrice and I'll be your operator for today's call. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question and answer session for the investment community. During the question and answer session, if you have a question, please press star one on your touch-tone phone. Please note that this conference is being recorded. I will now turn the call over to Jonathan Morgan, Vice President, Investor Relations. Jonathan, you may begin.
Thank you, Patrice. Good morning and welcome to the Enbridge Inc. earnings call for the first quarter 2020. I hope you're all doing healthy and well. Joining me this morning are Al Monaco, President and Chief Executive Officer, Colin 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 of the call will be available today, and a transcript will be posted to the website shortly after. In terms of Q&A, we'll prioritize calls from the investment community, and if you're a member of the media, please direct your questions to our communications team, who will be happy to respond immediately. Generally, we target to keep these calls to roughly one hour.
We recognize there's a lot of information to cover during these unprecedented times, so we'll be a little more flexible this morning. In order to answer as many questions as possible, please try to limit your questions to one plus a follow-up. As always, our investor relations team is available for your detailed follow-up questions afterwards. On slide two, I'll remind you that we will be referring to forward-looking information on today's call. By its nature, this information contains forecast assumptions and expectations about future outcomes, which are subject to the risks and uncertainties outlined here and discussed more fully in our public disclosure documents. We'll also be referring to the non-GAAP measures summarized below. With that, I'll turn it over to Al Monaco.
Okay. Thanks, Jonathan. Good morning, everybody. I'm going to open this up with a few comments on the COVID crisis and how we're approaching it. Everybody is searching for analogs to figure out where society, the economy, and capital markets are headed. The reality is we've never lived through something like this, and certainly not in energy, at least in my 35+ years in the industry. COVID has threatened millions of people, and it's hit fast and wide. One of my best days recently was the news that most of our few staff impacted by COVID were fully recovered. We all recognize that healthcare workers and emergency responders are the heroes. In the same way, I'm extremely proud of how our own front lines have responded. The women and men of Enbridge who've kept our systems running normally in the face of their own anxieties.
That's especially true for our people who remain on the job site, like in control centers, operations, field staff, and support functions. I want to thank our people for their sheer dedication they've shown to their work, our customers, and to the people that consume energy every day. In terms of our response, we implemented our business continuity plans very early on with the priority of protecting our people. For critical functions, we've put in additional safety protocols to maintain full service. On our approach to managing this downturn, our resilient business model and the actions we took over the last three years put us in a strong position coming into the year. That's going to allow us to weather this storm as the vast majority of our EBITDA is unaffected, and that's why we're maintaining our guidance, and we're stressing that outlook with various scenarios.
Even though we're resilient, we're staying ahead of the game and taking action to make sure we stay that way. What's guiding us through this period are three cornerstones, the health and safety of our people and reliability of our systems, that's number one. Maintaining a strong balance sheet with ample liquidity, and hitting our financial targets to support our conservative payout ratio and further growth. We're starting to see more positive economic signs. None of us for sure has a crystal ball on this in terms of the pace of the recovery. We're watching the signposts very closely. With that context, I'm going to start with Q1 highlights and explain what exactly we mean by resiliency. 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.
As Jonathan said, we'll be a bit longer to get through our remarks today because there's a lot to cover. Moving to the Q1 highlights on slide four. The first quarter seems a long time ago now, and we're all focused on the rest of the year, but there are a few things that are relevant to that. Operationally, our businesses ran very well. Distributable cash flow was strong and exceeded our Q1 budget. While COVID was a focus, we also advanced the priorities we laid out for you at Enbridge Day. Continuing with disciplined capital allocation, we sold CAD 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. 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 CAD 300 million. That includes salary rollbacks across the organization, including myself, senior management, and the board. We've already boosted excess liquidity by CAD 5 billion to CAD 14 billion to provide even more buffer in case debt capital markets shut down for an extended period. We've refined our 2020 capital execution schedules in light of COVID. We expect about CAD 1 billion of capital will be naturally deferred to next year without changing schedules in terms of our EBITDA uptick. First, EBITDA on the next slide now, on five here. EBITDA came in at CAD 3.8 billion and DCF at CAD 2.7 billion or CAD 1.34 a share.
That's a very good result, especially given the weather drag in the utility and narrower basis differentials in energy services relative to last year. We did very well this quarter in both of our core pipeline businesses. Liquids had record mainline volumes and higher throughput on our Gulf Coast access pipes, and Gas Transmission saw higher revenue from the new TETCO rates. Because of that, DCF per share was about CAD 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. Bottom line, as I mentioned, is that we expect to be within the guidance range of CAD 4.50-CAD 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 six. This group would've seen this slide before, which illustrates our low-risk pipeline utility model, but we've expanded it a bit here to show the various commercial structures and put our liquids mainline in the bigger picture Enbridge context. Starting from the top left box here and going counterclockwise, we have over 40 different sources of EBITDA diversified by business line, commodity, size, and geography. The common thread is that virtually all of our cash flows are driven by market pull with direct connections to end-use markets. 95% of our customers are investment-grade with strong balance sheets, and you've seen our list before. We've got good, conservative financial policies reflecting the stability and predictability of our cashflow 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. Here's why. CTS has been in place for nine years now and has worked extremely well for customers, us, and others through commodity and economic downturns. We're protected from any normal volume disruption because of the very strong supply fundamentals and the mainline's competitive position. Another factor, though, is contracted take-or- pays, both upstream and downstream, that effectively push and pull volume through the mainline. Ultimately, if needed, we have cost of service backstop, but our customers haven't wanted us to go in that direction. I'm going to expand on those issues in a few minutes when we discuss the mainline outlook and contracting.
First, let me speak to the resiliency of the other parts of our business on slide seven 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 the 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. Early 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, 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 eight. Enbridge Gas makes up 13% of our EBITDA, and it serves a market of about 14 million. It's essentially regulated cost of service, but we're currently operating under incentive framework. We're earning a very solid ROE due to synergy capture from the amalgamation of our two utilities. The majority of our load here is residential, plus we have long-term contracts underpinning industrial volume. Again, we don't expect to see much impact from COVID, and the utility should perform in line with our expectations, weather adjusted. Moving to slide nine in our renewable power business, which generates about 5% of our consolidated EBITDA. This business is built on the same type of commercial underpinning I just went through.
Projects are backed by long-term PPAs, which provide guaranteed offtake and pricing, and we have strong investment-grade customers there as well. We remain on track to meet our budget this year. We also have a good European growth hopper supported by excellent fundamentals and well-developed supply chains now in this business. We now have three large offshore wind farms in operation and several in development, and bringing in the financial investor I mentioned on the three French offshore projects boosts our return here nicely and minimizes our capital outlay. 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.
The mainline is flanked on the upstream end by long-term contracted pipes and on the downstream end with our contracted market access pipes. The contracted lines give us solid cash flow on their own, those contracts essentially push and pull volumes through the mainline. Let me now shift to the outlook for crude oil on slide 11. 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. As you can see on the slide here, diesel has actually fared slightly better as large transport vehicles, rail, and shipping are still moving, which is why heavy and medium crude demand has held up better than light. The chart shows 2020 North American crude demand pre and post-COVID.
The trough that you see in Q2 is expected to be roughly 6 million barrels per day off, with April and May being the worst, 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-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'll continue to put pressure on oil prices through 2020. 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%-50% since January. This is not a homogeneous refinery market. If you look at the core markets we serve in the Midwest, Eastern Canada, and the US Gulf, mainline deliveries, these are the purple squares that you see here, have held up better than overall refinery demand. In April, the Chicago area and Minnesota 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. We've 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. 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-2.85 million barrels over the last decade through low-cost expansions and optimizations. You've tracked those through the years. For the last six years, we've increased capacity and maximized utilization, even in the 2009 financial crisis and the 2015 commodity downturn. In fact, we've had to turn away volumes, particularly heavy barrels, with 40%-50% apportionment in the last three years. Again, that's because we deliver to the best markets, and we're directly tied to the strongest refineries. In the case of our 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. The uniqueness and depth of this downturn means everybody's affected. Let's get to the mainline outlook on slide 14. Obviously, Western Canadian producers have been hit hard.
Our estimate is that 1 million- 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. Local refinery demand is impacted, and then our 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. We absorbed about 400,000 barrels of the estimated 1.1 million barrels of shut-in I talked about, relative to our Q1 average throughput.
Based on what we see today, we're expecting the average Q2 Mainline impact to be in the range of 400,000-600,000 barrels per day, with the 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 pull, once demand picks up, we'd expect volumes to return to previous levels. All that to illustrate the diversification and strength across the business, including other parts of liquids, makes the impact to the mainline manageable.
Let's now move to another subject of interest, which is Mainline contract offering on the next slide. We filed our contracting application late last year, including letters of strong support from shippers who make up about 75% of throughput. Based on very recent customer soundings, these shippers remain supportive and will participate in the hearing. That's important because after two years of negotiation, those shippers are essentially saying that the commercial deal we struck, including tolls, works for them, and they want to commit volumes in an open season. It wasn't easy getting there at all, but we landed on a good balance, and the deal benefits everybody, producers, integrated companies, and refiners. In the case of refiners and integrated producers, contracting gives them access to reliable feedstock at stable and competitive tolls.
Producers get guaranteed access to our system, 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. 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 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 and Ontario demand, nearly all of this is heavy refining capability.
These refiners rely on our system and have limited alternatives. 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. 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. The CER is addressing submissions. We filed our response to those submissions on May 1. We expect a decision sometime in May.
I'd encourage you to read that filing. Hopefully, we'll see a clear timeline soon so we can get the process moving again. Switching gears now, still with Liquids now to the progress on the Minnesota permitting and regulatory process for Line 3. This is on slide 18. This is our usual update on the two tracks. A couple of more items checked off, as you can see here since Q1. On the regulatory track, last Friday, the PUC issued its official orders confirming the recertifications of the EIS certificate of need and route permit. This took a bit longer than expected. 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. It concluded that our construction plans meets its standards. That's important, too.
They're now considering the public comments before making a certification decision. The DNR and Army Corps are making progress, and the Corps concluded their supplemental public comment period. Once these agencies are done their process, the PUC will be in position to issue an authorization to construct. 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. 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 CAD 300 million. We've increased excess liquidity to CAD 14 billion, and because of some slowdowns related to COVID, about CAD 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. Now over to Colin for the financial review.
Thanks, Al. Good morning, everyone. I'll start off with our financial results, discuss our financial position, including bolstering actions, and then finish with our outlook. Peeking 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 by CAD 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 CAD 0.20 tariff surcharge from the Line 3 Canadian segment, which entered service in December.
As well, the Gulf Coast, 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 CAD 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 CAD 120 million of annualized EBITDA uptick to us, which is a little better than we previously guided. Gas distribution EBITDA was down CAD 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 40,000-50,000 new customers per year, and we're achieving our target 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 into service late last year and its adjacent expansion placed into service in January. These contributions were offset by low EBITDA at our Canadian wind farms due to less favorable wind resources. Energy services was down CAD 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. That's why this quarter's contribution is slightly negative. Finally, eliminations and other was CAD 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&M cost recoveries from the business.
Moving on to slide 21. DCF for the first quarter was CAD 1.34 per share compared with CAD 1.37 last year. We just discussed, EBITDA is fairly consistent quarter-over-quarter. 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 differences showing up during the quarter. In summary, we're ahead of where we expected to be at this point in the year. I'll move on to slide 22 and discuss our secured growth portfolio. Executing on our secured growth program remains a priority. This now CAD 10 billion portfolio of high-quality projects is well-diversified, commercially down the fairway, and generates strong returns.
Of the CAD 10 billion capital program overall, and I think some overlook this, about CAD 4.5 billion is spent already or will be project financed, leaving a very manageable CAD 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 a regulatory slowdown to delay planned spending in a few select areas by about CAD 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, a deferral of our utility customer adds until next year due to temporary housing construction pause in the GTA.
In the permitting category, we're seeing delays on PennEast. As we discussed, we received our Line 3 US Minnesota PUC written order, but it was delayed a little bit, so we could see spending shift by six weeks or so as we refine our construction plans. As a reminder, we conservatively planned in 2020 substantially the entire rest of the Line 3 US spend of $2 billion. Consider this About a $300 million refinement down to $1.7 billion for Line 3 US, 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, this secured growth will add an incremental $2.5 billion of highly reliable cash flows and advance our strategic priorities. 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 CAD 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, excuse me, or third issuer post-COVID, which helped to thaw the Canadian debt capital markets. We also added CAD 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 CAD 14 billion. This liquidity gives us plenty of access to funds all the way through 2021 without tapping the debt capital markets. Remember, we're in 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 within our 4.5x- 5x target range. Turning to slide 24. We've sold another CAD 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 CAD 0.25 billion. Neither of these assets were core to our strategy, but were attractive 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, namely 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.
Our best credit assurance is that we deliver to end-use markets as mentioned, where our last mile of 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, interprovincial 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. 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 central to how we run the business. Some forget we have a big utility in the portfolio, an A-rated utility, which can 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+ 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+ credit rating in mid-April. On to slide 27. In addition to bolstering our financial strength and liquidity, we're reducing costs by CAD 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, 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, company-wide 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, and moreover, we'll 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. Now, 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.
This 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 CAD 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 on our considerable U.S. dollar EBITDA, which even after our hedging program could yield as much as CAD 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 at historically attractive coupons in the 3% even territory. Also, our strong first quarter exceeded our plan, providing an additional CAD 0.05 running start and cost management actions provide approximately CAD 0.15 per share of bolstering support. Let's move to slide 29, see what this all means for our 2020 DCF per 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, the 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.
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. 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 it all up, we remain very confident that we'll generate DCF within our original guidance range of CAD 4.50- CAD 4.80 per share. Al, back over to you to wrap up.
Okay. Thank you, Colin. 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. 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 CAD 4.50-CAD 4.80. Finally, we are not losing sight of the future either. We remain very focused on executing our secured capital program that will drive near-term and medium-term growth in EBITDA and a growing dividend. We're now into the Q&A.
Just given we're not all in the same location here, and to keep things moving, I'll do some handoffs where needed on the Q&A. On to that section, please.
If you have a question, please press star one on your touch-tone phone. If you wish to be removed from the queue, please press the pound sign or the hash key. If you are using a speakerphone, you may need to pick up the handset before pressing the numbers. Once again, if you have a question, please press star one on your touch-tone phone. Rob Hope from Scotiabank is online with a question.
Morning, everyone. First question is just on the move of capital from 2020 into 2021 for Line 3. I just want to get a sense, is this being driven by a view that permitting is going to take longer in a COVID-19 world? Is it that you're baking in some additional contingency on the construction side there?
Hey, good morning, Rob. It's Colin. Yeah, it's fairly mechanical. We favorably received the Minnesota PUC written order here last week, although it took a little bit longer. As you recall, we had budgeted and guided for the full spend 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 2020 into 2021 mechanically.
All right. That's helpful.
It's about CAD 300 million. Yeah.
All right. When we take a look at the CAD 300 million of cost savings, were any of those realized in Q1? Do you have a sense of how much could be also being able to be sustained into 2021?
Yeah, on 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 on some of it. 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 a question.
Yeah. Good morning, everybody. 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, given the recent decision in Montana on Keystone? 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 based on this decision on the Nationwide Permit 12. Each project has different permitting requirements by the Corps. 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 permits, this decision from the Montana court doesn't impact schedule.
Okay, great. Then just looking at the mainline volumes here, appreciate the detailed 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 we are, 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. 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 light. 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. That's why we were saying earlier on that when things return, those should even be in better position. That's how we look at them.
On this recent initiative to store barrels down the mainline, any other near-term opportunities for downstream storage? 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, Rob-- or, sorry, 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 and 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. 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. In the bigger picture of Enbridge, of course, it's not a huge business.
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, Pat.
Robert Kwan with RBC Capital Markets is online for a question.
Great. 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 the 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.
Yeah.
Hi, Robert. With respect to May volumes, I think we don't generally talk about what we're seeing intermonth just because of commercial and market sensitivities. I think it's fair to say that you're seeing refinery utilization tracking upwards as we've progressed 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 24th to that effect, saying that they would like the mainline contracting hearing process to continue and pick up its pace. I think your second part to that question was, there are a number of those shippers who are interested in even more space than they're currently shipping, just because of volume ramp-ups or changing refinery configurations.
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'll 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 form, you've got the arrows, both tailwinds and headwinds are about the same. Overall, 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. Yeah, it's Colin. 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 CAD 13.5 billion EBITDA business with a guidance range of ±3%. We feel that's fairly tight already. I'm not going to make specific commentary on where in the range. We have a range. I think you put your finger on it. I think the Mainline volume sensitivity is probably obviously the biggest moving part there. We've stress tested it, as noted.
That's great. Thank you very much.
Thanks Robert.
Shneur Gershuni from UBS is online with a question.
Hi, good morning, everyone. Good to hear everyone is safe and well. 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. 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. 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. When the refiners start up and they get 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 pull out of the Western Canadian production than you would typically expect in normal circumstances?
I'm trying to understand how that impacts or colors your outlook for mainline volumes for this year.
Shneur, it's Al here, then I'll hand it off to Vern. 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, there's probably a good opportunity for them to ramp up and fully utilize that access to heavy barrels. 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. 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. That's how we see it at a high level.
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. As the economy picks up and as transportation fuels begin to return to normal, you will see refinery demand go up. 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. 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. Maybe as a follow-up question, with the Keystone XL approval and so forth, 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, shippers would continue to support your process. Is that a fair way to think about it? Just any color around that would be helpful.
Well, maybe I'll go first, then on the rate comparison, Vern, you can address that, I think. Firstly, I would say, Shneur, that I think you're aware, we've always assumed that XL would go forward in our projections. I think that was the prudent thing to do. Our view is that even in that scenario, we still see a lot of demand for access to our system and to be contracted. It goes back to what we were saying about direct connections and minimal alternatives. That's the three million barrels a day that we were talking about that is directly connected or is downstream pull. 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, what was it?
Three or four or five years of lack of egress, I think one thing that XL coming on its schedule, and TMX does is 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. I think that could unleash some new volumes coming out of the basin that would certainly further bolster what we're doing on contracting. That's the big picture. And then on rates, Vern?
Yeah, I would say that we are very competitive to all markets. We feel like we'll definitely have the lowest toll into the US Midwest and Eastern Canada. In fact, from both of those markets, there are almost no alternatives but the Enbridge system. To the downstream markets and Patoka, Cushing, and the US Gulf Coast, we are very competitive. In fact, our US Gulf Coast tolls should be the lowest tolls available.
What you're effectively saying is that it wouldn't be an impediment and you have a very good offering for your shippers.
Absolutely.
Perfect. Thank you very much, guys. Really appreciate the call today and stay safe.
Okay, thank you.
Thanks, Shneur.
Linda Ezergailis from TD Securities is on line for a question.
Thank you. Appreciate all the fulsome update today on the Mainline, especially. I realize 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. 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 is unfolding for you.
I'm just wondering, with your CAD 5 billion-CAD 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, 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. 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. 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. I think it's making sure that we keep resilient is the first priority. I think at the same time, we also have an eye on making sure that we continue to sustain the growth in the business.
You mentioned the export strategy. At this point, unless you believe that we're not going to return to the basic fundamentals that were 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. 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 CAD 5 billion-CAD 6 billion, again, I think, obviously with potentially a slowdown in the economy, you could see overall growth slow down 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.
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 CAD 5 billion-CAD 6 billion per year, it's CAD 1 billion-CAD 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, Sabal 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. Then of course, on the liquid side. I actually think on the organic side, we're pretty well-positioned, and I don't see a 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. 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. 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. Just as a follow-up, with your sale of your interest in your offshore French wind to CPPIB, 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 the types of assets that you hold?
That's a good point. 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. 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 tracking and see what's out there for us to capitalize on when we see it.
Great. Thank you.
Okay. Thanks, Linda.
Jeremy Tonet from JP Morgan Chase & Co. is online with a question.
Hi. Good morning. Just wanted to take a step back here, and looking at the first quarter, it looked like operations came in pretty good, better than we were expecting. Appreciate that there's kind of these headwinds ahead of us, as you've talked about on the call. If I'm just kind of thinking through this on the other side, when we get back to kind of a normalized world and potentially when Line 3 eventually gets in line and 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?
Yeah, I think, Jeremy, I'll start then Colin can add. I think I'll take you back to Enbridge Day here, which wasn't that long ago really, it feels longer. 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. I think that's the way we're looking at this good first quarter. We've got some bolstering actions that'll help us stay in the range. I think that's important.
From there, I see more or less a progression and execution of that three-year plan that we laid out. I think we're pretty much on track with what we thought.
The only thing I think I'll add, Jeremy, and you're very close to this, is in Bill's business. I think it's a subtle point, 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 in kind of a boring way. I think you're right. It should be diversified, solid contribution. We had a pretty good Q1 continuing all the trends that you've seen. 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 just 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 other opportunities right now. Maybe Bill, can you maybe just expand on this? I think it's a good point.
I appreciate the boring comment. The business really has started to turn a little bit towards its roots, which is a regulated entity. We've got an awful lot of capital going into the business. You see it from a Texas Eastern rate case that provides some I guess you'd call it a growth opportunity, one. The business, even in this environment, Jeremy, we're only down maybe 5% on a demand basis. As you know, it doesn't affect us because we're all reservation-based system. 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.
I feel as though from protecting that base with recontracting, 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 churn out some nice growth.
Thanks, Bill.
Yeah, that sounds right. If Boston didn't prefer Russian LNG, it seems like you'd have some nice opportunities there. Just want to follow up on my second question real quick with regards to DCP, I'm on the other side there. With them retracting the guide here, just wondering, updated thoughts there as far as portfolio management. Is that something that after write-downs here is something to exit at this point, or are they going to need any help? I appreciate it's an extremely small part of your business, but just wanted to get any thoughts there.
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, it would be consistent with the fact that we sold the rest of our G&P businesses. 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, that at this point, we're very supportive of management's actions. They've moved forward pretty quickly on reducing capital. They're making inroads on the operating costs and certainly on overhead. 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 a question.
Okay, thanks. Good morning. On the renewables business, I'm curious, where does that fit in your overall strategy now, your long-term? It seems like that business is getting smaller over time, and the other segments are getting bigger here as well. Are you still bullish on renewables and how it fits in your portfolio?
The short answer is yes, Ben. Reason for that being, 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. 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. The bigger thing these days I've found is that the supply chain is really well-developed.
We've joined this partnership with CPPIB. 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. I think if you're referring to the transaction we were talking about, that was purely about boosting the return on assets. 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. I think that's a good capital allocation move. 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. My second question, maybe cleaning up on the mainline sensitivities and peeling Q2 a bit on that variance you put out there at that range, 400,000-600,000 barrels. Can you confirm, looking at 600,000 barrels, it looks like you're feeding in 1.5 million barrels a day? I wanted to check that, I guess that suggests that at June, you're probably looking at 1 million down on mainline volumes.
Go ahead, Vern. Yep.
Hey, Ben, can you explain your question again? I'm having trouble following it.
Yeah, sure. Absolutely. I was 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. The way I'm thinking about it specifically is you got April in the bag, 400,000-1 million, and then you probably have a good sense of May, and then you put up 600,000. I'm just solving for June.
Okay. I see where your point is. I think the 400,000- 600,000 barrels is in a range for the average on the quarter. There's no real midpoint for that range. It's designed to be something that's possible. Again, that's dependent on whether it's 1 million- 1.5 million barrels in overall Western Canadian
Basin production declines. At this point, in April and May, we're not close to that 1.5 million barrels at this point.
Okay. I guess, in that range, you have sensitized down to 1.5 million barrels.
It's designed to be a range, and our outlook would be within that range.
Okay. All right. Okay. Thanks, guys.
Okay. 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 of quick clarifications. We have a very similar path on the mainline volumes that you've described, but maybe it took 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've 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. 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 drive the rate of throughput pickup for us. We're already up 1 million barrels a day in gasoline demand since the lows in early April, and it's trending the right direction. Our expectation is as 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 up borders or anything like that, but it's really driving patterns I think will be the biggest thing to watch.
Right. 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 year-end volume outlook?
No, we're 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. I'm wondering if that also includes the impact of COVID and what that might have on the practical realities that has on construction, or has that 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 most of the projects we're running right now in the field, those are generally working to schedule. A few more complications in how you work. 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, we haven't really seen much of that yet. Hopefully, I'm answering your question, that's the big picture.
Yeah, that was it. I just wondered about any construction changes to the construction activity that might result, but you answered the question. Thanks.
Yeah.
Okay.
Matthew Taylor from Tudor, Pickering, Holt & Co. is online with a question.
Hey, thanks for taking my question here. On slide 14, you highlighted the recovery in volumes 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 any 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 pull-driven because, prior to the COVID situation, we were 40% or 50% apportioned upstream. We don't expect the supply situation to impact 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. After that is drawn down a bit, then we would likely see a price increase in Western Canada. That would then result in more supply being brought back.
That's great. Thanks, Vern. Maybe just one last one here for Bill. On natural gas, as prices improve or potentially move to CAD 3 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? Either way, it seems constructive for your business, either more gas flows or healthy customers. Just wondering what type of opportunities you're kind of foreseeing in the future in a better pricing environment.
Yeah. I think, Matthew, it'll be interesting to see the LNG dynamics for one, for sure. I think we are already seeing the fundamentals for the projects that we're looking at for 2024 and beyond. They're pretty darn good. 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 we have a fair presence in Appalachia. In an odd way, it's kind of good from a contracting perspective. Yet we're not seeing the CAD 7, CAD 8, CAD 9, CAD 10 prices that might scare away demand. I think the outlook is pretty good when you're between the high CAD 1 and CAD 3.
Great. Thanks for the color there, Bill.
Andrew Kuske from Credit Suisse is online with a question.
Thank you. Good morning. I think the question's probably for Colin. Historically, you've always maintained ample liquidity, and it's no different this time around. You've bolstered your liquidity during the quarter. I guess just a confirmation on where your liquidity is right now, and then would you be able to, if the markets completely froze, access the Bank of Canada's Commercial Paper Purchase Program plan?
Yeah. Thanks, Andrew. We're at CAD 14 billion. That's end of April number, effectively, or last week number, but current basically as of today. That's a big number, it translates calendar-wise into a funding access sufficiency through the end of 2021, 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. I can confirm that Enbridge, as a strong-rated commercial paper issuer, could access the Canadian Program. I don't think we have really to date. We are issuing commercial paper. The market is thawing. I've been, I guess, pleasantly surprised by the collective actions of central banks, right? It looks like debt capital markets are thawing and reopening in a constructive manner.
I feel pretty good about funding our plan through next year, Andrew.
That's great. Appreciate the color. Then maybe one more narrow question, just with 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?
Can you clarify that a little bit? Specifically on 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?
Yeah, no. The answer to that is not really, Andrew. I think we still have 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 Corporation is online with a question.
Good morning. Thanks for the interesting details on slide 12, detailing PADD II and PADD III dynamic over the near term, PADD II 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.
Yeah, I'll go first. I think probably a couple 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. 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. A few reasons for that. One, I mentioned, but we are starting to see a few more barrels headed out of Cushing, down into the Gulf. Part of that is Strategic Petroleum Reserve has helped that out.
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 now expected to fill in May as well. Western Canada, I think if you read the published stats, 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. We figured out ways to add 3 million barrels of incremental storage to our customers. Really that comes from deferring some API tank expense inspections and working with the regulator to do that, changing our operating parameters for how we fill specific storage sites. That gives us more flexibility for our customers.
Finally, we're in the process of getting a piece of deactivated pipe associated with Legacy Line 3, approved by the CER, where we could put that into service as temporary storage for our customers as well. 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. From a broader industry perspective, as we emerge from this pandemic situation and assuming a lower demand curve, how do you see North America pipeline utilization evolving, Al? Does it essentially price out crude by rail for the medium term? Is it really a call on the export market at some point?
Do you want to take that, Vern, or?
Sure. Yeah, I think out of Western Canada, for sure, crude by rail will be the first to be hit. Given that crude by rail was moving at about 400,000 barrels a day prior to the demand destruction with COVID, we expect that pipeline utilization will come back first out of Western Canada for sure. Then we expect our heavy system to be very full, but when economic activity recovers, just because, as we mentioned before, heavy crude will 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 that has knock-on effects to the export market, just because the excess light crude out of North America has been exported and to some degree, is continuing to be exported as well.
Thank you.
Michael Lapides from Goldman Sachs Group, Inc. i s online with a question.
Thank you for doing this extended call and obviously for taking my question. I'm glad you're here. I'm looking at slide 10, and I'm looking at kind of some of the other pipes outside of the main line. I'm just curious, when you refer to them, and I'm thinking pipes like DAPL or Gray Oak and Express and Platte. When you say they're take-or-pay, are you saying they are 80%-90% take-or-pay and just the 10% walk up is open, or are they partially take-or-pay, significantly less than 90%, and the rest is more volumetric?
I don't know. Vern, do you want to take that?
Yeah, I think it's the latter, where it's 80% or 90% take-or-pay and about 10%-20% is spot or walk up. Those pipelines will see a minor impact on their revenues, but nothing significant.
Michael, just as a reminder, that spot capacity, the 10%, for example, that's usually by regulatory requirement. We don't have a lot of choice in that one.
No, understood. That's the walk up. Vern, can you talk a little bit about what you're seeing volume-wise? Meaning, have you seen dramatic volume changes on DAPL or on Gray Oak? Gray Oak's 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 for Gray Oak, obviously, that's 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, on DAPL, where the walk-up volumes will be lower.
Got it. Then last, and this may be a Colin question, can you just clarify what is growth CapEx for 2020?
Yeah. Michael, thanks. At Enbridge Day, the slide had total CapEx of CAD 6.5 billion, of which CAD 1 billion was maintenance. CAD 5.5 billion was our growth CapEx spend projection for this year. That's now down to CAD 4.5 billion. CAD 4.5 billion plus CAD 1 billion.
Got it. The CAD 1 billion that you're deferring, and you may have done this already, and apologies if I misunderstood it, can you put that CAD 1 billion into buckets? Meaning what percent is for X business or X type of asset, what percent is for Y?
Yeah, I'll give you a little bit more there. I think we talked about probably the biggest piece, which is about CAD 300 million of the CAD 1 billion, which was the mechanical, just best case time shift for Line 3 U.S. The rest of it is CAD 50 million here, CAD 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 CAD 200 million. That's about half of the CAD 1 billion together there, Line 3 and PennEast. The rest are smaller, like I mentioned, a little bit at the utility, call it CAD 100 million or a little bit more. A little bit of compressor modernization in Bill's business, maybe another CAD 100 million, CAD 150 million there. The rest is pretty small.
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. 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 under-earning your expectations at that pipe in the U.S.?
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 to be a positive impact. It's just too early to say what that could possibly be. We also have filings or settlements that we'd like to pursue over the next three months on East Tennessee, Alliance, Maritimes & Northeast. You got to keep in mind, these all pale in size and scope by comparison to Texas Eastern. While we may see positives, the Texas Eastern rate case and getting that behind us was by far the largest. I hope that's enough color. Maybe I'll add one more thing, and that 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.
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.
Thanks, Michael.
We have reached our time limit and are not able to take any further questions at this time. I will now turn the call over to Jonathan Morgan for final remarks.
Thank you, Patrice, and thank you to everyone for your time and joining us this morning. We appreciate your ongoing interest in Enbridge. 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.