Good morning, and welcome to Enbridge's 2019 Investor Conference. My name is Jonathan Morgan. I'm Vice President, Investor Relations. It's my pleasure to kick our day off today here in New York, and thanks to you that have joined us here today in person, as well as those of you that are listening online. This is an important day for us, and we look forward to it each year as we update our strategic plan and priorities for managing and growing the business. Before we get to that, a few housekeeping items to take care of first. It's our practice at Enbridge to begin each meeting with a safety moment, and I'll use the opportunity here today to cover off our evacuation procedures for the building in the event that we need to use them.
In the event there's a fire, you'll hear an alarm, and if necessary, this will be followed by an announcement to evacuate the building. There are two stairwells in the building. There's one behind me, stairwell A, and there's another out the door behind you, stairwell B. I'll ask the front half of the room to follow me through stairwell A, and back half of the room will go to stairwell B. In terms of muster point, I think it probably makes sense for us just to meet at 55th and Fifth, and we can wait there for further instruction from the building personnel. In terms of agenda, we're going to follow the same format that we followed in past years. We'll have presentation followed by Q&A for each section, and you're going to hear from many members of our executive team here today.
For Q&A, we'll have a microphone circulating. We ask that you wait for the microphone before asking your question and introduce yourself when doing so. We're going to try and stick to schedule today. We ask that you ask one question plus a follow-up. We have a break planned for 10:15, and we look to wrap up this session by 12:30 today. Once we're done, lunch is available, and we ask that you stick around and engage with our executive team, who are all here today. Finally, the legal team would like me to remind you that our comments today may refer to forward-looking statements or non-GAAP measures. With that, I'll pass it over to Al Monaco, President and CEO, to kick things off with his strategic overview.
Thanks, Jon. Good morning, everybody. I'm going to start off by apologizing for my underwater voice. Nevertheless, we are excited to be here today to talk about the story. We have refinements to our plan every year, but the 2020 plan is really based on the same founded elements of our longstanding value proposition. The plan essentially is characterized by the three things that you see on this side: resilience, discipline, and growth. It's those three themes that we hope you take away from today. The management team is confident that those principles will deliver good value for shareholders in any business and capital markets environment. I'm going to set the context today by speaking to our resilience and the energy fundamentals that drive our strategies.
While the fundamentals are positive, and I've already chatted with a couple of you this morning, we know that the energy space is very challenging. I'll talk about how we've adapted our approach ahead of the curve. Talk about how we allocate capital in our medium and long-term outlook. Our business leaders will review how they'll build their franchises. Bill Yardley will talk gas transmission, Cynthia Hansen will talk about gas distribution and storage, Guy Jarvis and Vern Yu will tag team on liquids pipelines. Colin Gruending will bring this together at the end with his financial review. Before we get to that, this slide summarizes this morning's release. We expect to see the midpoint of our 2019 guidance range of CAD 4.30-CAD 4.60 DCF per share, which affirms what we said on the Q3 call.
Debt to EBITDA should come in at the lower end of our range at 4.6. 2020 guidance is CAD 4.50-CAD 4.80 a share, which reflects stronger business performance and assumes no contribution from Line 3 on the U.S. portion. That's a very good outcome, as stronger performance from the businesses partially offsets the delay in Line 3 cash flows. We increased the dividend, as you saw, by 9.8% in line with last year the plan, 2017, 2019 plan period. As you know, our dividend is based on our predictable DCF per share profile, our multi-year outlook, and for 2020, improved business performance that I mentioned. After 2020, we estimate we can grow DCF per share at 5%-7% on average, and that's consistent with what we said last year.
In the near term, I'll call that through 2022, this outlook is driven by the embedded growth in secured capital projects we have underway, including the U.S. portion of Line 3. Once Line 3 does come into service, debt to EBITDA should actually be below the 4.5, the bottom end of that 4.5-5 range. Longer term, we see DCF per share of 5%-7% growth coming from the carry forward of embedded opportunities within the business, plus newly secured opportunities. As for funding, growth will be financed from cash from available investment and 100% self-funded within that debt to EBITDA range. In terms of the business update today, as you saw, we're advancing our Gulf Coast strategy centered around Seaway and new export infrastructure.
On Line 3, we put the Canadian segment into service last week. Great outcome for our customers and ourselves. Two items actually yesterday on Line 3 U.S., late-breaking news, the Department of Commerce submitted their amended final environmental impact statement, with the spill modeling, recall, that the court ordered, and there was no issues coming out from that modeling. After that, the PUC initiated a public comment process for three things: the adequacy of the FEIS, the certificate of need, and the routing permit. There will be a one-day session, oral session, on December 19th, where people can provide their views, and the public comment period closes on January 16th. We think it is a good outcome that the PUC is going to have a comment period related to all three of those items.
It doesn't change our approach in that we're not providing any specific guidance on an in-service date. That's obviously a good positive outcome here, I think. We've sent a letter in as well to the Canadian Energy Regulator indicating that we'll be filing our Mainline contracting application before the end of the year. Today, we're going to be talking about our future, but I'll spend a minute on how we've positioned Enbridge for that future. If you look at the slide here from 2010 to 2016, we built out the liquids business, which made up about three-quarters of the EBITDA at that point and growing from there. These were highly accretive projects that led to this, which solidified the position that we have and extended the reach all the way into the Gulf Coast.
That's actually turned out a lot better than we even imagined at the time, given where oil exports are headed, and today, liquids is generating record results. While that was happening, we saw the future of natural gas as overwhelmingly positive. Buying Spectra at a reasonable price diversified our opportunity set and our geography. Today, in our view, it's even clearer that accelerating that gas strategy and expanding the U.S. footprint was clearly the right thing to do. It also gave us, and sometimes we forget about this, a big gas distribution utility, another one in Ontario, in a critical long-haul gas business in BC. Both are growing nicely.
In a nutshell then, what the slide says is that we captured the liquids opportunities that were there in front of us, and there are more of those to come, by the way, and reposition the business in line of our view of the fundamentals. Today, we're well-diversified with reach and scale and the optionality to grow in a lot of areas. We move roughly a quarter of all the crude oil and 20% of the natural gas in North America, and we have the largest natural gas utility. We've established as well, let's call it an emerging renewables business that fits our model. Bottom line, if you look at the map, we've unparalleled infrastructure franchises that are absolutely essential to driving the North American economy. We all know that the way society is looking at conventional energy is changing.
Let me illustrate the resilience of these assets. The lifeblood of the three franchises you see here is one thing: end-use customer demand and last-mile connectivity. Liquid serves, if you add up the circles there, 12 MMbpd of refining capacity, and that's comprised of globally competitive refiners. It's a great combination for our liquids business. What it means is that the system's going to be continuing to be heavily utilized for a very long time, especially now since it's connected to export markets. Gas transmission pipes feeds markets totaling 170 million people and key industrial, commercial, and power gen load. And our gas utility serves the fifth largest population center, and as Cynthia will tell you, gas cost advantage of 60% versus other fuels. Three things that really speak to the resiliency here.
These customers and markets aren't going anywhere. Our pipes are going to be around for a very long time. Our cash flow outlook is not dependent on specific supply and drilling profiles. A bigger gas business diversifies our overall risk. The other part of resiliency is our low-risk model. I'm sure lots of people stand in front of you and say they have the lowest risk profile in the business. Here's why we say it. Our assets generate low volatility, long-life cash flows, and that shows up in the tightness of our guidance ranges. With the sale of the G&P business, virtually all of our EBITDA comes from low-risk commercial structures. Our customers are the strongest in the industry. Whether they're energy companies or utility companies, the likes of Imperial, Exxon, BP, Suncor, Chevron, Con Ed, National Grid, Florida Power & Light.
There's a bunch of others, and they're not going anywhere either. The balance sheet is strong, and especially when you consider the utility-like asset base that we have. Again, we don't believe there's a lower risk profile out there, and we plan to keep it that way. It's not going to be front of mind for you every day as it is for us, but certainly the number one priority for us is safety and reliability. Everybody at Enbridge, so whether it's management team or our people out in the field, believe that this is the number one thing they're responsible for. Our business relies on the public's trust in what we're doing. The goal is to protect them, our people, and make sure that we're delivering reliably for our customers.
It starts with what we call lifecycle integrity management, and maintenance plans for each asset. This is not just a year-by-year exercise where we're trying to estimate how much it's going to cost to maintain the system. It's a long-lived approach where we dedicate enough resources to make sure we plan for the capital to be there. Now, people think that energy is not a technology business, but they couldn't be more wrong. We're using the most advanced tools, we invest in research, and we use it to identify and manage risk. Technology also helps manage massive amounts of data that come from the tool runs and applying algorithms to better and more quickly interpret data that's coming at us. Most importantly, we use technology to optimize the system, whether that's power utilization, maintenance planning, or managing the flow within our large terminals.
Even making small changes to those three areas can have big bottom-line impacts. This chart here is for the liquids group, and as you can see, we run the most in-line inspection tools in the industry, and that correlates pretty well, as you can see, with the releases in the liquids system that are in the very good end of this chart on the left. Obviously, we are not perfect. We had a serious incident in Kentucky this year and one in BC last year, but we are doing what we need to to make sure that doesn't happen again. Safety and reliability, in our view, is a differentiator in this business. Another one, though, is ESG. Now, ESG is gaining a lot of prominence, and I'm sure it's top of mind for you. Frankly, this is not a new concept for us at all.
We were focused on ESG well before this acronym was coined. On the E, even though we're not a large emitter, we set targets and we met them, lowering direct emissions by 21% since 1990. Our conservation programs reduced emissions equivalent to taking 9 million cars off the road, and we're investing in renewable natural gas. Cynthia will explain that. We're at the forefront of disclosure and testing our resilience to climate change. On the S, we've certainly learned a lot about indigenous engagement and developed a critical skill set here. It really comes down to one simple thing on this front, understanding indigenous connection to water and land and ensuring our people represent our values in the field. We had a huge success, which you probably didn't hear much about, resulting in partnerships on Line 3 Canada yielding CAD 450 million of indigenous economic opportunities.
We set diversity and inclusion targets across Enbridge, something we've been working pretty hard on. That part extends actually to the G, where we have an excellent board diversity and tenure. Our comp programs are aligned with shareholders, and they include safety and environmental performance. As part of that as well, management, as you know, is heavily invested in this company. The next slide shows briefly why we have a good story on ESG. I'm not going to go through all of this, obviously, but you can tell at a glance that it's clear that we match up very well against our peers. The next slide recaps the progress we've had on our priorities since last Enbridge Day. First and foremost, operating and financial performance has been strong.
The Spectra assets have now been fully integrated. We captured the targeted synergies and a little bit more. Project execution has been good, which delivered increased cash flow. Obviously, we were disappointed by the Line 3 delay in Minnesota. Ultimately, as we've said to you before, this segment needs to be replaced. We have great support in the community and tribal nations along the route. This has been the most comprehensive regulatory and permitting review ever. Asset sales accelerated deleveraging from the large CapEx program over the last few years. We rolled up four sponsored vehicles, which simplified the structure, the credit profile, and improved our overall payout look. Of course, we're self-funded, including getting rid of our DRIP. All in, we've grown DCF per share while delevering, selling non-core assets, bringing in the SVs, and continuing to invest in the business.
Now I want to switch gears to the fundamentals. We usually cover this at Enbridge Day, and the business leaders will do that as well. It couldn't be more important than it is today, because we'd all agree that, as I said earlier, the business is changing, and we'd all agree as well that we need to reduce energy intensity globally. I'm going to use the most recent IEA base case that came out a couple of weeks ago here to talk about this, because I think it's conservative on demand, and it includes the GHG policies that are in place today and the ones that are targeted.
First, there's not much doubt, and you can see this on the bars on the left, that global energy demand is going to increase somewhere in the order of 25% by 2040, and that's because three things are sure to happen. You're going to have population growth of about 2 billion people. There's going to be greater urbanization, up to 64%, and improved living standards, which will bump the middle class by about 2 billion people. All of that means more energy. What's noteworthy about that bar on the left-hand side is that consumption would actually be 12% higher if not for the progress on efficiency, conservation, building codes, fuel standards, and so on. We know that the rate of energy growth is now about half of GDP growth. A few takeaways on the left here.
To meet energy demand, it's very clear we're going to need all sources of supply. Renewables grow at the fastest rate because it's starting from a small base, natural gas will play the biggest role, up 36%. Also in terms of reducing emissions. To make a major impact, if that's what we really want to do, we need more natural gas globally. The U.S. is the poster child for this. GHGs came down to below 1990 while the economy grew by 80% in the U.S. There's no reason why we can't see that same outcome globally. That's the big picture. It's very positive. Now, what about North America? Different story here, but still strong for another reason.
I think we'd all agree that North American demand for crude is going to be flattish, but on gas, it will be increasing because of power gen load, and Bill will be speaking to that. Liquids and gas production grow nicely, driven by low-cost supply to serve export markets. The U.S. and Canada have a great opportunity here to gain market share, That's why a strategic push for us is export infrastructure. Before I get to the priorities that we have in the 2020 plan, let me speak to how we look at this broader midstream space and the challenges we have and how we've adapted our approach. Starting from the 12 o'clock position, this set of circles basically tries to outline what the issues at play are in this changing landscape. Energy fundamentals are positive. That's great. You saw that.
Growing global demand and low-cost North American supply, that means we can provide more for exports. All of that bodes well for what we have in the ground today and our export opportunities. Again, the midstream landscape is way more challenging today than just five or 10 years ago. This company lives this literally every day. Climate change, regulatory and permitting delays, and in many cases, we are, as midstreamers, the point of attack. We've seen these issues, you all have as well, on Line 3 and Line 5 that has created significant headlines. Yes, it's tougher to get things done, which is why we have to develop and have developed a unique execution capability and skill set that is built for this environment. While we also think carefully about capital allocation and ensuring a return on and of capital on existing and new investments.
The challenge that we set for the team is: how do we capitalize on these great fundamentals in front of us while managing the broader risks? In terms of how we grow the business, the approach is that we're going to focus on projects that optimize and expand the existing footprint, diversifying our opportunity set, again, especially on exports. On capital allocation, we'll prioritize enhancing returns, highly executable projects, and minimizing at-risk development capital, all within a self-funding model. With that context, here's the snapshot of our priorities. In the medium term, again, let's call that through 2022, we'll concentrate on optimizing the great base we have, executing our secured projects that we have going on right now, and building out the organic hopper to secure long-term growth. That's the third box on the right.
The base growth is driven by two things: embedded revenue and contracted volume escalators and continuing cost and process efficiencies that we've begun several years ago and are paying a lot of dividends. Secondly, executing on a secured capital program, and that's the CAD 11 billion in projects you see here. It includes Line 3 U.S., Bill's gas transmission projects, utility expansions, and power. In the longer term, we plan to grow organically with the same types of enhancements and expansions of the franchises. Liquids and LNG exports and offshore wind opportunities that we've secured, but not yet FID'd. As you can see here, these investments are right down the middle of our fairway. Here's how that translates numerically. Again, 1%-2% from optimizing the base is what we see in terms of post-2020 growth, 4%-5% from organic growth, both secured and new opportunities.
In the near term, call that to 2022, the growth rate's driven by what we have in secured execution today, and then beyond that, it'll be new opportunities. As I alluded to earlier, once Line 3 comes in, we should be below the lower end of that debt-to-EBITDA range. We'll have more financial flexibility to extend growth well into the future. Before I get to post-2020 opportunities, I'll talk about the capital allocation lens that we use when we're thinking about putting capital to work. The first part of the lens is on establishing the broad constraints. What's the self-funding capacity? What's the leverage, returns, and dividend payout? After we complete the secured capital program, we expect to have investment capacity annually of about CAD 5 billion-CAD 6 billion.
That's comprised of annual free cash flow after deducting maintenance, capital, and dividends, plus any financing capacity from EBITDA that we're generating by then. Colin will take you through that in more detail. We're comfortable with the debt-to-EBITDA range of 4.5 to 5. The long-term dividend payout is approximately 65% of distributable cash flow. With our available reinvestment envelope, we look at the various options that you see in the circles here. We're going to be disciplined about how we allocate capital in this environment and triangulate these options to maximize long-term value. The factors we look at in that decision-making are going to be how capital moves our strategies and sustains our growth, creating additional financial flexibility, and return of capital. That's the broad framework we use. Now let me show you how that translates into priorities in the next little while.
You probably surmised by now that the first priority is to preserve financial strength while we grow. That means being within the target debt-to-EBITDA range and maintaining BBB high credit ratings. The balance sheet, as we said, is in good shape, we'll always look to create additional financial flexibility where it makes sense. For example, if there's an opportunity to monetize an asset at a great valuation, we will create some dry powder. Second part of the value proposition is returning capital. For us right now, that's growing the dividend. We always look at share buybacks as an option compared to organic growth, creating some additional financial flexibility or other options. We're going to more actively consider buybacks once we execute our capital program, the biggest part of that is the remainder of Line 3, not too far away.
Third in the batting order and tied to sustaining dividend growth is to grow the base business organically, and again, optimize, extend, and expand the existing businesses. Size-wise, we'll be looking at singles and doubles in this category, which carry less relative permitting risk and deliver enhanced returns. Let's take a quick high-level look at the organic opportunities, and we're going to start with natural gas. That's in blue here. Texas Eastern is really well-positioned to feed growing industrial and power gen load in the U.S. Northeast. No secret at all that this part of the U.S. requires more pipe. There are challenges there, which Bill is going to solve. The U.S. Southeast looks very good for gas-fired power generation. TETCO also feeds the U.S. Gulf Coast pet chems, and we're nicely positioned along the coast to capitalize on LNG exports and, of course, Mexican exports.
The West coast system is best situated to meet growing local demand, but there's a bigger prize here, an opportunity on both that system and for new pipes on LNG. All in, let's call it potential opportunities in Bill's area on gas transmission of about CAD 2 billion per year. On gas distribution, we see significant customer adds, expanding new communities and the Dawn-Parkway System. That totals up about CAD 1 billion a year. There's more optimization to be had on liquids, and Mainline contracting will position us well for the future. Now with Gray Oak, our Mid-Continent pipes, Seaway, and our Gulf Coast strategy really now I think is taking shape, as you saw. We found a very capital-efficient way to develop the entire light and heavy value chain, and Guy's going to go through that in more detail.
Let's call this another CAD 2 billion or so per year in opportunities from liquids. On offshore wind, we have one project in construction in Europe and three that are developed that could come into play after 2020. Call that about CAD 1 billion per year. That gives you a quick feel of the organic opportunities that we're working on. Here's now how that translates again to summarize our growth. Again, 1%-2% that's embedded in the base, which carries through from the medium-term to the longer term. In terms of organic growth then, we've got the capacity to put CAD 5 billion-CAD 6 billion to work, which could generate 4%-5% DCF per share growth. Those two sources come to the 5%-7% we're talking about.
Before I conclude here on this and we get to questions, there are a few issues that we considered actually in developing this plan and that you may have raised in your own minds already. We've outlined a few key questions here, and we can go through more after, obviously. As to whether we change the risk profile to achieve accelerated growth. The answer to that is no. We've had many opportunities to do that in the past several years, and even more recently, and we've passed on them. The reality is that utility investments and pipeline utility category generally offer very good commercial underpinning for us, and it's what we do best. Other capital allocation options would be available to us rather than stretching the risk profile. A related question to that is whether we'd stretch the balance sheet to hit the growth targets.
That's actually a shorter answer. It's no. We've worked very hard to get it to where we want it, and we're happy with it where it is. I guess I should move forward here. On the asset mix, we're happy with the current split between liquids and gas with an emerging presence in renewables. The fact is that we're so well-diversified on both liquids and gas, we're positioned to grow in a number of areas, so we're very happy with the current split that we have today. Another thought is around M&A. You can imagine we monitor every possibility out there very closely. To be clear, we have no plans in this area. That's because we've already repositioned the business with the Spectra acquisition. We've got plenty of organic opportunities in front of us, as you saw. Further clarity on buybacks.
We return currently about CAD 6 billion through the dividend, and it'll be higher next year. We still have some capital projects to execute. It's certainly something we'll look at, but less likely until we get through our capital program. We obviously revisit this all the time, though, depending on what the share price is and our relative valuation. As to whether we would invest more internationally, I think other than the select European offshore wind projects that fit that model really well, it's not something that we're immediately planning to do. I'm glad to expand on any of this or we'll get into more questions later on. Just to wrap up here. This value proposition triangle has been here for a long time. It hasn't changed.
It basically combines high-quality assets, a low-risk business model, and organic-driven growth to ensure we provide a very strong return of capital. That's essentially the value-creating formula we use, and that's what we want to stick to. We like it because it's resilient to whatever the capital markets or the business environment throws at us. I think that's been borne out over the last couple of years. You might call this boring, but the low-risk business model generates stable and predictable cash flows that allows us to plan and deliver predictable results. If you look at this story from 50,000 ft, despite the Line 3 delay, deleveraging, and sponsored vehicle takeouts, we've put up solid results in 2019 and growing from here. That's essentially what we mean by resilient. Now, it's what the management team is going to be constantly focused on is delivering those results.
On that note, we spend a lot of time on succession and planning development. This happens continuously and at all levels of the company. For senior management, and particularly myself, the goal is pretty simple. We want to have at least one ready-now person to take over every senior position. You saw that happen with our organizational changes this year. At that time, we also took an opportunity to expand the leadership team, and we brought in some external talent as well on many fronts. This is a team, and they're all here today except for David Bryson. That's actually an interesting story. He moved from the cold climate of Calgary to Houston to work with Bill and his business. We actually had Allen Capps go the other way, which was more unusual. Where's Allen? Allen's here. He went from Houston to Calgary.
He likes the cold. Please take an opportunity to meet these people today, and join them at the break or over lunch. To wrap up my comments before Q&A, the midstream space has been challenging, obviously, in the last few years, but the resilience that we have and how we've evolved our approach and adapted to what the environment is going to allow us to withstand these challenges. We've delivered very strong dividend growth, as you can see, we're proud of this history, and solid TSR for shareholders over a very long period of time. Believe me, we understand the importance of continuing to earn the trust of our shareholders and confidence by extending this track record. That is the overview today. I think at this point, we're going to open it up for questions. Yes. All right. The mics will be coming around.
There's a question there. Yes.
Hi. Good morning. Rob Catellier from CIBC. You talked a bit about capital allocation in your presentation. I'm curious about two aspects there. First is, how are you building in ESG considerations into your capital allocation? On a similar vein, how has the implementation of Bill C-69 impacted capital allocation decisions in Canada?
Okay. Well, on the first part of it, on ESG and how we build that into capital allocation, Colin's going to go through a fairly detailed review later of the screening process that we use in our investment review model. A big part of that is ESG. I think the biggest chunk of it is likely going to be, Rob, in terms of how we evaluate permitting and regulatory risk. We'll take a lot of time to do that before we actually proceed with the project. A lot of that is getting out to the community ahead of time, seeing what their views are on energy infrastructure. That relates to the fact that most of the issues that we face are solved at the local and community level. There's lots of noise broadly about energy and opposition and climate change and so forth.
We have found that the solutions really are at the local level and addressing those concerns. We'll look at that in our investment review process. We'll build in extra time for that because that's certainly going to be an outcome. It's going to cost more to build projects, including the time it takes, longer time, more AFUDC in that process. Where there is a direct carbon price in the region that we're working, we'll build that into the economics as well. We've covered that gamut fully within our investment review process. When we screen, we're making sure we're taking that to account. We may determine that based on ESG concerns or factors that we can't proceed with the project. On Bill C-69, that's a good question.
I'd have to say that generally speaking, the day-to-day work should continue unchanged in terms of how we interact with the regulator. Where C-69 comes in has probably more to do with very large projects. Our view is at the moment in Canada, there's likely to be very few that fit into that big category going forward. So it's probably not as big a factor, at least in our view, unless there's a major project. The key on C-69, in my view, is that we need transparency to ensure that if we get regulatory approval, that we actually have the license to build the project. I think the concern with C-69 is that there's some uncertainty around whether or not you're actually going to be able to build, even though you have a regulatory approval, and you actually saw that in Northern Gateway.
We'll be very conscious of that under C-69.
Thank you.
Thank you. Oh, I think, can we just go there first and then we'll come back to Linda?
Thanks. Andrew Kuske, Credit Suisse.
Andrew.
On the slide where you had key questions that you posed to the audience, you noted it was large scale M&A. Maybe if you could just talk a little bit about the build versus buy options in the market, in particular, where you don't have asset exposure and you lack the physical footprint. Is the build option really appropriate there, or is it really a buy situation?
A good example of this is probably the U.S. Gulf Coast strategy, which you saw us talk to yesterday in the news release. There's probably lots of opportunities to buy assets and larger scale M&A that probably would give us instantaneous position. We chose instead to be, as I referred to earlier, more capital efficient. Where we can use an existing asset to extend our reach, and build organically, I think that's still our preference. You can't always do that, and if it's a smaller scale idea that helps extend, expand, then we'd consider that. There's so many things, as you know, that have to line up with M&A. Is it going to be accretive to near-term cash flow? Is it going to have the risk-reward model that you have in your existing business? Is it going to be growth accretive?
Generally speaking, the probability of all that coming together versus your ability to build organically or extend an existing asset, is less likely.
Maybe the obvious follow-up is, what's the definition of large scale versus smaller scale?
Well, probably up to CAD 5 billion, I would call small, medium scale. Yep. I think we're here. Over here to Linda.
Thank you. Just to expand on that, I am wondering how JVs might also help you be somewhat capital efficient if you don't bring something yourselves to the table, like competency, an asset that a partner might have. I guess part B to the question is, where else might a JV make sense? For example, if a financial partner, like a pension fund or private equity, might have cost of capital advantages or other attributes that they bring to a table. Can you comment on how JVs can be used to-
Sure
Forward your strategy and maximize shareholder value?
Okay. Great question. I'm glad you brought that up. On JV-ing, again, I have to go to the example of our partnership with Enterprise. We've got a great partner who has last-mile connectivity. We essentially levered that relationship. We brought heavy barrels to the U.S. Gulf Coast on Flanagan. They brought this last-mile connectivity. We've now put it together where, as a JV, we can be stronger together rather than working independently. Absolutely right, JVs are part of the strategy. The issue, in some cases, is that you don't have full control when sometimes you'd like to. On the other hand, where you can be more capital efficient, we think it makes a lot of sense.
Where we can use it in terms of capital efficiency more broadly is on the West C oast of Canada, and there's good opportunities there for big LNG pipes still on the come and it's possible there. You bring somebody in with a lower cost of capital. That's always the most likely type of scenario. You bring down your capital investment, and you focus really on the return on that investment as opposed to just the ultimate size of it. I think we'd use it in that situation.
Just as a follow-up, to maximize shareholder value, if you're seeing a systemic disconnect between the public and the private capital markets, have you put thought to how you might close that arb sooner rather than later?
Yeah. I think a good example of that was last year when we sold our assets. That was a little bit of a different situation because we wanted to clean up the G&P business. It just so happened that we were able to get great valuations for those. We do think about that a lot, and we continually look at all of our assets. We don't have a lot in the non-core category, but if there was something that we could do around the edges, we'd certainly have to entertain that. We're always looking to see whether there's compelling value and whether we can optimize the overall picture by selling an asset at a super good valuation, and redeploying that capital into those options that we showed. Yes.
Shneur Gershuni with UBS.
Shneur .
In your prepared remarks and in some of your responses, you have talked about capital efficiency, capital light type of strategy. Outside of the existing projects like Line 3, Line 5, the VLCC terminal yesterday, as we think about new projects being added, should we be thinking that they're going to be more shorter time cycles, less permitting issues, lower multiple higher return projects? What are the marching orders to the team right now in terms of how you think about CapEx for the next two years?
I sure hope they're shorter. It's easy to say, "Well, guys, just go away and focus on the short-term stuff." The reality is most things take a long time. I think where we can shorten the cycle is clearly where we have an expansion, an extension of our existing assets, where we're working within our franchise. For example, liquids business has done a lot of work on DRA, which improves volumes at very minimal capital investment and really doesn't require a lot in terms of permitting and regulatory issues. Those are the kinds of things that we'll be focused on. Improve returns, focus on the franchise that you have where you can minimize timelines. There are always going to be some issues in terms of delays and so forth. I'm not sure if that.
Yep. Helpful. Just as a quick follow-up, you'd mentioned in one of your comments earlier that once Line 3 is in service, you would expect your leverage to actually be below your targeted 4.5-5 range.
Yeah.
Would you use buybacks then to toggle back into the range? Is that the way we should be thinking about it?
It could be. I think that once Line 3 comes in, as we said, we'll be below. That gives us some pretty good flexibility. We'd have to decide at the time whether or not using some of that extra dry powder. It would depend on whether we had another organic opportunity that we could use that we saw would be great value for us in terms of extending the business, extending the growth rate, advancing the strategy, versus a buyback program. That's not out of the realm. I think it'll depend on what we see at the time. We wouldn't hesitate to do a buyback program if we don't see opportunities. One proviso, we need to be able to sustain a buyback program as well, and rather than have just sporadic buybacks. That's another factor we'd look at.
Thank you.
Becca?
Thanks. Becca Followill, U.S. Capital Advisors. In line with the buybacks, can you quantify the magnitude of what you could see in a buyback, and how you would look at the trade-off between growing the dividend, say, at the 10% you're growing this year versus buybacks?
Yeah. Well, as I said earlier, I think the mantra of the company has always been to deliver sustainable growing dividends. That's sort of our preference. In terms of the buyback magnitude, the way I think about it is, each 0.1 of a turn on debt to EBITDA is sort of in that range of CAD 1 billion, CAD 1.3 billion, in terms of cash available to buy back shares, if that's the way you want to look at it. It's probably in that range for each 0.1 of a turn that's available. As I said, it would depend at that time whether or not we saw an opportunity to do an organic investment. Which frankly, would take a little bit more time to generate the EBITDA from.
It's the play between investing in your shares, which could be a good opportunity at time, versus an organic project that may come with more growth with it going forward.
Just right here.
Oh. Al?
Al. Right here.
Sorry, I was looking over here. Rob, go ahead.
Yeah. Good. There's a pretty big focus here on trying to find shorter timeline, easy-to-build stuff. Can you just talk about how do you address, then, when you look at some of the larger projects that may be more difficult? What types of hurdle rate premiums are you looking at, or is it really just a time value calculation within the IRR and the NPV?
Yeah. Well, for sure it's CapEx risk in terms of not just timelines. One thing we found, for example, on Line 3, there's a lot more engagement with communities, whether it's indigenous or other types of communities. There's a lot more engagement with the public generally, a lot more engagement with regulators. That all costs more money. If there is an element of CapEx risk related to those items, we can quantify that. If you think about your financial model and how you'd work that through on your equity IRR, you can pretty well easily figure out how much of a difference that's going to make. We tend to build those kinds of premiums into the hurdle rate. You start with a hurdle rate that has a, let's call it, a base return or riskless return.
Add to it the premium that you need to generate good value for the shareholder. Then we'll do these add-ons. That's how we usually handle it in the hurdle rate. We try and identify and quantify the risk financially, and then build that into the hurdle rate.
As an example for something like Line 3, how much of a premium would've been built in versus something that was quick and easy to build?
Well, maybe the way to answer that, Robert. Let me back up. First, on Line 3, a good chunk of the capital's already been spent. CAD 5 billion in Canada. There's another three or so to go on the U.S. portion, one of which has already been spent. You're dealing with CAD 2 billion, and you have to spend. The variability around that, even if you have Well, we will have an increase on that part. We've run the economics on this a lot, and it really doesn't change the fact that Line 3 is still a very strong returning project. It's not going to make a difference to the economics on Line 3. I'd have to go back and see what we actually built in for the hurdle rate at that point.
If I could just finish with the question on M&A. When you're looking at small to medium-sized M&As, is your real kind of eye on accelerating the growth above that 5%-7% range as we go forward? Is it more about the ability to extend, give you that visibility on that growth? As it comes to financing, is that something, again, under that CAD 5 billion number, something you'd look to be able to have that balance sheet capacity, or would you?
Yeah.
Would you be looking at equity?
It's the latter. Rather than accelerating the growth rate, it would be something that we could always look at to extend. It would have to be within the self-funding envelope. We're not excited about using our equity for something like that. The big picture here is that it's just not a big priority unless we see something that really makes a lot of sense to expand, extend the core business, and help its growth rate, if we can fit it within the financial policies that we've set.
Thank you.
Okay. Okay, I think we're Yves.
Yeah. Thank you. Just to think about, in the spirit of returns, how do you think about the risk on the offshore wind? If you look forward 5 to 10 years, how big a slice of the pie do you think renewables can be?
Well, the biggest issues on offshore wind. Let's start with the fact that we're not going to be a merchant generator on offshore wind. It's going to have to have a long-term PPA with it. You've got volume protection and you've got price- volume except for obviously wind variations. The biggest issues that come into play there are CapEx risk. Generally, what we find is we can pretty much lock down the capital costs beforehand on our offshore wind projects. That's because the industry has developed the supply chain now, and it's still difficult to build, but not rocket science per se. I think there's a lot of experience around the supply chain now for delivering projects within good capital. If we can lock down 75%-80% of the capital before we make an FID, then we're very happy with that.
The residual CapEx risk is not going to be substantial. On the second part of your question with respect to how big could the slice be, I think the way we're looking at offshore wind is we'll march along here with the three or four projects we've got in development, and I said it's probably CAD 1 billion a year. Remember, those are project finance as well, so the equity is lower. It's hard to see how at that pace, at least in the near term, we're going to change the pies that you saw earlier in a material way. I'm not going to put a percentage on it as to what we want it to be as far as the rest of the pies.
I think if we can march along in a conservative way here and build good projects with good cash flow predictability, that's the main goal.
Al, right here.
We'll go here. Yes.
Al, Michael Lapides from Goldman.
Michael.
Just when you're giving the targets and talking about net debt to EBITDA going below 4.5x and talking about potential returns on capital via buybacks after Line 3 comes online, what's in the assumption for what happens with the Canadian Mainline toll in all of that? How are you thinking through how much the change in that toll, whenever it goes into effect, mid 2021 or later, how are you thinking about how much the change in that toll could impact either capital returns or impact net debt to EBITDA longer term?
Yeah, I think, Mike, it's a good question. The reality is, I don't think it's going to really change the outcome. You know that the Mainline toll assumption that we've used, which was the outcome of a big negotiation over the last 18 months with our shippers, is pretty much the exit toll that we're using in 2021 from the previous commercial structure. Really, it's not going to make a significant enough change to really impact what you said about debt to EBITDA and your availability of cash at the time. Even if the toll was different, it just wouldn't be material to the bigger Enbridge cash flow projection. Yes.
I think this will be the last question.
Thanks. Praneeth Satish, Wells Fargo. Just curious about your views on the NGL market, specifically in Western Canada, and whether there's any opportunities for you to gain market share there or maybe participate in the exports that are taking place there.
Well, we're not going to be a big NGL player. Obviously, we have Alliance, which is a heavy liquids-rich line. We've benefited from that for many years. There's some expansion possibility there. We're going to have to do something on the Westc oast Mainline system, Bill's going to talk about this, our Frontier Project, in terms of removing liquids content from that stream. That could bring into play the need to move that volume to markets either east or west. That's a possibility, but I would say, we're not focused on NGL per se in terms of gathering and processing, for example. It's probably more constrained to what we have and what we need to do on the West coast system. Could we work in one more if there is? Yes.
Hi. It's Ben Pham, BMO Capital Markets. Just following up on the last question. LNG export, U.S. Gulf Coast, any interest there? I know you're thinking of expanding the liquids value chain opportunity. What about LNG export?
Just to clarify your question, Ben, are you referring to LNG pipes or LNG facilities?
The facilities.
Okay. Generally not. If there is an opportunity to make a small investment that would help us win a pipeline project, and if the LNG facility had a commercial model that fits with our own business model, i.e., long-term contracts with specified tariffs in it, I suppose that's a possibility. There's probably not that many of those opportunities that are going to come forward given the commercial models that we see for LNG on the Gulf right now. Low probability, I would say. Possible if under the right conditions. I need a last question. Last question. Bill. Yes. Right here. Can you make it?
He can make it.
All right.
Thanks, Al. Pat Kenny, National Bank. You mentioned you won't be increasing risk profile to chase growth. Have you adjusted your return expectations down for the lower-risk projects? Maybe you can also comment on potentially reintroducing some corporate complexity to achieve growth.
Okay. Well, the last one's easier. The answer is no, we don't want corporate complexity. It's one of those things where for many years it probably made sense to have sponsored vehicles because they could attract capital at lower rates. Obviously, that's not the case. We like the simplicity. I got to tell you, we've got enough things on the horizon to manage without adding corporate complexity and all the things that go with that. The answer is no to that. On the first part of your question, which was returns?
Just adjusting the return expectations down.
I would say on that, in theory, you're going to move your hurdle rates up or down depending on the risk that you see out there. I think it also has to do with your competitive position. We'll be prudent about that. If we need to adjust to reflect a different competitive landscape, then we might. Generally speaking, I think the returns have stayed pretty much the same because we generally have very good competitive positions. We look at that as well in terms of what will be acceptable for a project hurdle rate.
Would the access to the debt markets influence the return expectations, whether it be being able to finance the liquids pipeline projects with longer-term debt versus, say, some of the more renewable or gas-oriented projects?
Well, we tend to look at financing for the company overall. We'll create project hurdle rates and look at debt costs for each project. I wouldn't say we're going to get into streaming directly funding for particular projects. Offshore wind is probably an exception because we tend to project finance those. Yes, the lower interest rates are certainly helping on that front and the availability of capital. Okay. Now I'm going to turn it over to Bill Yardley on gas transmission. Bill.
Thank you, sir. Thanks, Al. Hello, everyone. Thanks for joining us today. Always happy to be back in New York City. Love everything about it except the sports teams. Really pleased to be able to discuss with all of you the very solid footing that our gas transmission enjoys, as well as the methodical growth that we do see in our business unit. Our pipeline assets are foundational to providing the energy that North America needs. We continue to prove out the resiliency of our business throughout any economic conditions. As consistent as you've known our business to be, 2019 has really been a transformational year.
With the settlement filing on the Texas Eastern rate case, we began a period of what's likely to be several years of proceedings to true up the cost of doing business on our pipelines as we continue to make modernizing investments to set each asset up for the longer term. This model, combined with the increasing demand for natural gas in North America, makes us a sustainable portion of the Enbridge portfolio really for decades to come. As about a third of the earnings of the corporation, we're representative of the resilience, the discipline, and growth of the overall enterprise. While we did encounter challenges this year with our incident in Kentucky, we're resolved to make our system the safest in the industry.
Additive to the resilient base business, we've got a portfolio of already secured projects that we'll be constructing over the next few years, in addition to that ramp-up of system-wide modernization efforts. This is a fundamental change in our path forward, yet it's in lockstep with our regulatory approach and our commitment to customer service. I'm referring to the capability to earn on and recover expenses related to system improvements that will serve to make our pipelines and related facilities going strong for decades into the future without losing our competitive position. This sets us up really well to meet increasing demand for natural gas over the long term.
Over the course of this past year, I think we've demonstrated our ability to execute growth projects and really seize opportunities as we've placed a lot of key market access projects into service and the acquisition of the Generation Pipeline in Ohio. I think you'd agree that it's difficult to find a more stable foundation of low volatility EBITDA in our space. There's lots of ways you can tell the strength of the base business of a set of pipeline assets, and one of them is geography. It's not just a bunch of lines on a map, it's where those lines are. They go into where gas is demanded, where homes and businesses literally can't survive without them. Is it going to where critical electric generation is? On top of that, the lines emanate from reliable and prolific supply. We've got all of that.
We've got that last-mile demand in the Northeast U.S., the Southeast U.S., the Gulf Coast, Pacific Northwest, and British Columbia. Whether you say that we go to where the lights are or simply just eyeball the major cities, towns, and industrial centers that we deliver to on this map, I think you'll see the power of where we go geographically. Just like Cynthia's distribution assets on Ontario and the connectivity of Guy's industry-leading liquids lines, the business that we run and gas transmission is a critical, must-run, stable business. In the Northeast U.S., moratoriums on new gas service to homes and businesses dot the landscape. That's a clear need, a cry for new pipeline infrastructure into that region. Good opportunity for us to reinforce what we already have there, which is an industry-leading position.
In the Southeast, a conscious choice of gas for power generation has been made, and the pipelines serving that region are full and fully contracted. Another great opportunity for us. Our BC Pipeline is full into Vancouver and into the Pacific Northwest and has had consistent expansion projects to these demand centers. The Enbridge gas transmission assets continue to remain well-positioned, not just as one of the largest gas transmission footprints in North America, but as the best. The markets that we connect to need us to expand to meet their future demands. We're playing our part in the fundamental shift in natural gas markets on this continent as well as globally.
2019 has seen an increase in the permitting and the sanctioning of LNG export projects. We're leveraging our coastal position in North America to secure expansion opportunities to supply feed gas to several of these facilities. We've executed on multiple opportunities, as you've seen already this year. We really like where we are, and we're proud of our accomplishments in 2019. A strong contract renewal rate of over 99%, with customers on our major pipelines. Substantial settlement with the FERC and our customers of the rate case on Texas Eastern, the first in 28 years, seeing a significant enhancement to EBITDA and setting us up well for investments in the modernization of the Texas Eastern system. Then third, an advancement of our LNG supply strategy, both through the execution of already secured projects and the development of new ones.
Let's take a minute to look at the fundamentals of natural gas. Just a few slides on general confidence in our future. The success that we've enjoyed and the opportunities that lie ahead of us are really brought about by the intersection of our footprint and the fundamentals of natural gas. First, on the left, I'll spend all of 10 seconds confirming for you that supply is there. Producers have successfully turned the production of natural gas into a manufacturing process, and there's overwhelming evidence that we're awash in supply from Texas to Louisiana, to British Columbia and Appalachia. In this environment, it really all comes down to demand. Are we going to see continued growth in the consumption of natural gas, both for domestic use and for export? Yes.
In fact, in the next 20 years, demand for natural gas is expected to grow by more than 20 BCF a day in domestic markets alone, with half of that for power generation needs. There's so much talk about the growth in domestic renewables for power generation that gas is often ignored. Projected growth in gas demand is unanimous among the leading prognosticators. Honestly, we are seeing it day in and day out, most notably on the peak day and especially on that peak hour. If you add to this the demand for the exports, another probably over 15 BCF a day by 2040, that's a big number, and our assets are strategically placed to take advantage of the great opportunities presented by this growing demand throughout North America. Fortunately for us, the largest demand increases are exactly where we sit geographically.
The biggest increases over the next 20 years are in the Gulf Coast and in British Columbia for industrial use and, of course, for LNG export. Selected areas of the Northeast, the Southeast, and the Midwest, much of which will be driven by power generation, is an opportunity for us as well, right along the footprint. We're the number one or number two supplier in most of these areas. I've got a couple of comments on specific areas that are representative of this gas demand. Let's look at U.S. Northeast power generation, one of my favorite subjects. Gas is currently the chosen fuel for replacement and for incremental generation needs, which are on track to grow by about that 10 BCF a day over the next two decades.
Yeah, we hear a lot about wind and solar generation, and we're an active participant globally in the renewable space. We've seen coal, oil, and even a number of nuclear-generating assets retired. As that's happened, natural gas has been the main fuel to fill that void. There's an overwhelming economic reliability and geographical footprint advantage that gas for power generation enjoys. Now, here in the U.S. Northeast, natural gas is consistently the marginal fuel after the base load nuclear generation and a small percentage of hydro and wind that's already in place. Over the past decade in New England, virtually all coal-fired generation has been shuttered. Within the past five years. About 1,300 MW of nuclear has been retired. Throughout all this, although renewables are a consistent part of the energy discussion, and they really should be, especially in this region.
It would be blind not to notice the statistics and the dominance that natural gas continues to build in the power gen market in the Northeast. This on the right here, this is from the ISO New England's website. Feel free to pop it open as I'm talking. It's probably a lot more interesting than listening to me, but iso-ne.com, and it is under real-time maps and charts. These are just the real-time numbers I was using when I put it together. It's actually a little warmer day today, so these numbers might be a bit different. You can see that on a typical day, gas is generating roughly half of the electricity. Nuclear gets base loaded at around 30%. I do, I pop this open a lot. A good amount of hydro, usually 10%, give or take, and then renewables.
If you look at the breakout, typically more than half of the renewables number is wood and refuse. There's a little bit of wind there now, about a third of that 9%. Generally, when I pop it open, wind is generating anywhere from 1% or 2%- 7% or 8%. If New England states are going to reach their stated goals, there's going to have to be a massive ramp-up in wind resources. The increased use of renewable electric power generation, particularly wind, requires backup power to firm the generation from these intermittent sources of electricity. You can't count on the 7% or 8%, you can only count on the one or two. Natural gas-fired generation is the logical low-cost choice for providing this backup firming capability.
We've got a long way to go, decades before we displace any material fraction of the gas-fired generation in this area, and that's before we even get to the projected growth with the move towards electrification, which is coming in that region. 15 years ago, this wasn't a problem. Gas for power generation was 10%, 15% of the overall mix. Not anymore. Now it's well over 50. Fortunately, we are a pipeline company that's had a great deal of success in expanding our system in this region. We touch the majority of the generators that are currently operating. This is true elsewhere as well. If you look in the Southeast market, as a major recipient of gas on the sold-out Gulfstream pipeline, NextEra, or Florida Power & Light, signed up for 20+ year contracts and helped build the Sabal Trail pipeline.
They're our partner, of course, in Sabal Trail as well. I just don't think one of the leaders in renewable power would have done that if they thought that gas was going away anytime soon. LNG. Our North American gas supply, quite robust with low production cost and the relative ease of getting it to coastal markets, is dramatically changing the global energy landscape too. Natural gas for exports growing across the board, but nowhere more than in North America with an expected 15 BCF a day or more increase over the current levels over the next 20 years. Marcellus and Utica production has been the mainstay, but more recently, as we all know, associated gas from the Permian, the resurgence in the Haynesville, they've all enhanced North America's competitiveness from a supply standpoint. Similarly, in Western Canada, the Montney and the Duvernay are doing the same thing.
These are long-life basins, plenty of runway ahead of them. Check marks across the board for North America's LNG export competitiveness. You'll see this slide a few more times in the other business units, and it's consistent with the approach of the corporation and guys in Cynthia's businesses. We seek to optimize our base, execute on those project promises that we've already made, and seek new growth that's real complementary to our existing footprint. We're really pleased where gas transmission sits as we conclude a transformational 2019. We knew we needed to begin rate proceedings again after a multi-decade hiatus. Refreshing rates to reflect the current rate base and the operating costs.
It sets us up really well as we're going to be back in the regulatory arena with some frequency as we look to modernize many of our pipeline systems and as we invest in the integrity of the system for the long term. We've got a stable of mid-sized executable projects that are in some phase of execution, and as for future growth, we knew we'd be competing intensely for new pipeline projects to serve the anticipated LNG market. We've worked tirelessly on all three of these fronts, and we're seeing good success in each one. The following slides take a quick look at each one of these. First, the base. As I mentioned, not all pipeline asset mixes are created equal. In this environment, I think it's really important for you to know what our base consists of. We're not big gatherers or processors.
We don't like any substantive volume or commodity exposure. We like term. We like reservation-based revenues. We like good credit. Demand-pull utilities and long-term producer arrangements. Please study this chart with me for a second. There's a lot going on here. I'll just guide you to a couple of things. One is the blue bars. That's the percentage of revenue on a given asset that we get on that pipeline, whether or not our customers flow any gas at all. 95%, 98%, 98%, 97%, et cetera. That's all firm revenue coming in. That's representative of the maximum rate that we could possibly charge for 100% of the volume. 95% of that being reservation based on the Texas Eastern system. The term numbers. Long terms, again, with utilities and select producers, eight years, 23 years, 11 years, et cetera.
The peak days reached, I point this out because we just keep hitting new highs year after year, which is demonstrating the need for these assets as well as our ability to find pocket capacity here and there to serve unique loads. Even though we get paid either way, it's really kind of nice to know these contracts are being heavily utilized. Our customers like what we sell to them. As I mentioned, out of about CAD 500 million of contracts that could have been noticed this past October 31st, 99.5% of it was renewed or resold at that maximum rate. We enjoy a really good mix of cost of service and long-term negotiated rate agreements. Protecting and optimizing this base is in many ways it's our blocking and tackling, right?
I mean, customer service and reliability leading to contract renewals, cost control and efficiency, and the regulatory management that I'm talking about around rate proceedings. As we've added incremental infrastructure to the portfolio, whether it's through modernization, pipeline integrity improvements, or incremental projects to reach new demand, we do so with that same solid financial footing that the base enjoys. Modernization. I use the word transformational to describe that shift towards engaging in more rate proceedings, and here's why. An important component to our base business is the coming modernization of many of our pipelines. We've had a great track record of providing reliable service to shippers across Texas Eastern and our other systems for the last several decades. One thing arising out of the last few years is that we know we got to keep getting better along this front.
Many of these investments are simply to ensure compliance with regulatory requirements, like the compressor station replacements that we're doing for air emissions limitations. We've got to do more, like ensuring reliability by modernizing meter stations. Ensuring pipeline integrity by running more sophisticated tools, gathering more data. Reducing the carbon footprint of our assets by limiting any methane emissions at our stations and limiting blowdowns. These are what actually wins the day, not just for us as Enbridge, but also for our industry. The better we do it, the more it sets us apart from our competitors. It's a lot of effort, and it's going to take a lot of investment. Recovering these costs where feasible through the general system rates is core to our regulatory strategy, and that started last year. We're not going to shy away from these investments.
At the end of the day, all of us that speak today, along with all of our fellow Enbridge employees, have one critical role to play: safely and reliably deliver energy to our customers. We're focused on that every minute of every day. These investments in modernization help us achieve that. We need to make sure that we earn on the capital and recover the operating costs that are associated with doing this. When we began preparations for the Texas Eastern rate case settlement or the rate settlement last year, we could foresee these modernization costs coming. With our flagship pipeline, after 28 years without a rate case, we're on our way to what should be the first of many settlements on this and our other cost of service pipelines across our U.S. systems.
It's in some ways modeled after our successful track record in British Columbia with the BC Pipeline. We've had 20 years or more of annual settlements on that system. We believe that the process we just went through on Texas Eastern sets us up well for working with FERC and working with the customers. That's a few slides on the base, consistent, stable, and investment worthy. Okay. We've made good progress here. We'll see some modest growth in the base just by executing on these prudent investments in modernization and system integrity. The second way we're building on this base in the short to medium term is by completing the current inventory of CAD 4 billion worth of projects that we have already in execution. We're making really good progress on these, building on a very successful track record.
Last year, we completed Valley Crossing and NEXUS. Valley Crossing fully sold out to the Mexican utility, CFE. Volumes have been steadily ramping up as the downstream capacity into Mexico has come on. Within months of bringing NEXUS into service, we acquired the Generation Pipeline, further boosting the last-mile connectivity. Generation's a 20+ mile natural gas pipeline serving the power generation needs and the industrial loads in that Toledo area. It'll provide really good last-mile opportunities for NEXUS and provide gas directly to that Toledo corridor. The asset already enjoys, by the way, long-term reservation-based contracts, which are obviously in line with our business model. Great bolt-on opportunity for NEXUS. This year, the build-out continues. In the Northeast, we completed the latest phase of the Atlantic Bridge Project this year. That was sort of the pipeline lift and relay components, through New York and Connecticut.
After recently receiving our FERC notice to proceed for the Weymouth Compressor Station, we're under construction, and we expect to have the final phase of this project complete and in service by the middle of next year. We also received approval from the Canadian Energy Regulator, CER, to move forward with our CAD 1 billion T-South reliability and expansion project. We got that approval about a month ago. This is a great investment on T-South to serve both growing demand of domestic needs in Vancouver and the Pacific Northwest, but also an LNG export market, and it's all under a cost-of-service framework. The ability to advance both of these projects, despite opposition, which we're all well aware of, and the high regulatory hurdles, it really underscores what Al was referring to, both the net market need and our permitting capability.
We expect the T-South Project to come online late in 2021, by the way, about the same time as we get our CAD 0.5 billion Spruce Ridge Project going. It's an expansion in T-North, which provides a lot of needed access for the Montney Basin producers trying to reach export markets. In the Gulf Coast, build-out to LNG export terminals continues. Our Stratton Ridge Project is ready for service, and it'll be ready to supply Freeport's Train 3 when it comes on in 2020. Up the coast, we're also advancing 750,000 Mcf a day, CAD 150 million Cameron extension project, which is going to serve Venture Global's Calcasieu Pass LNG facility. These are both really strong projects and obviously leverage our incumbent position and geography. It's enough on what we got on the go currently, but what's next? We continue to focus on these four regions.
You've all seen this map before. Each supported by the strong fundamentals that I opened with. The asset base is clearly well-positioned, in all four of these areas, and we'll continue to leverage the footprint for buildable, capital-efficient, higher-return extensions and expansion of the system. When we point to our geographic footprint as an asset in these regions, nowhere is the power of that connectivity and the existing asset base more apparent than in the Northeast U.S., the West C oast of Canada, and the U.S. Gulf Coast. It allows us to offer real competitive rates and better assurance of completion, which is critical these days. I'll focus on two where we have the most going on, the Gulf Coast and Canada. Okay. Our pipelines serving the Gulf Coast are already large-scale players in the burgeoning LNG export market.
We provide substantial service to Cheniere's Sabine Pass, as well as the Sempra Cameron facility, and of course, we'll serve Freeport's Train Three. We're currently moving well over a Bcf a day for export, with more coming soon when Freeport's Train Three is online. In addition to the Cameron expansion project, which I mentioned for Venture Global, we're also providing a Bcf and a half of feed gas. We've contracted to do this when their Plaquemines LNG facility comes on through the reversal of our existing Venice Lateral and other facilities on Texas Eastern. These two Venture Global projects, Plaquemines and Calcasieu, it represents over CAD 500 million of investment for us right along our line and another two Bcf a day to be provided for LNG export. These are great examples of the power of that footprint as both these laterals are being reversed.
We're making really good progress on pipeline projects to serve Brownsville. NextDecade, for their proposed Rio Grande terminal in the Brownsville area. We're really proud to be working with the NextDecade team and look forward to leveraging our pretty vast experience and recent experience in South Texas to help them succeed. Taking advantage of what our existing footprint is and the knowledge that we bring from permitting in South Texas to pursue CAD 2 billion in opportunities to feed the growing export market in Brownsville. NextDecade, we're working with Annova LNG and Texas LNG. We'll be very well prepared for the Brownsville export market to mature. All the while, once again, ensuring that all these terms that we're negotiating fit with our utility-like commercial model. On to Western Canada.
World-class supply, proximity to Asia really makes Western Canada ideal for LNG export projects. Our T-North and T-South pipelines are playing a really significant role already by providing upstream transportation for LNG Canada and for Woodfibre LNG, their project down south. We've more than doubled our investment over the last several years in T-North and T-South. We see expansions of both these pipes continuing for years to come. A key area of focus as well is the continued development of the Westcoast Connector Gas Transmission pipeline. Westcoast Connector's been on the books for a while. It's got a nicely developed route to Prince Rupert. It's scalable, it's cost-effective, and really any of the next phase LNG export projects that have Prince Rupert in their sights are talking to us with regard to the Westcoast Connector.
That's been good. We're also exploring, as the question was asked earlier, the development of natural gas liquids infrastructure in Western Canada. Again, this is not G&P, but it's really so that our customers can fully monetize the liquids that are currently entrained in the gas stream and don't have an outlet. Again, it'll be contracted in a manner that's consistent with the rest of our business. You may have seen that we filed a project description with the BC Environmental Assessment Office for a project called Project Frontier. That would basically involve building an NGL extraction plant, a pipeline, and a bunch of associated facilities in Northeastern British Columbia. Pretty early stages for that project, but worth mentioning since it was out there and in service could be as early as 2024.
As I highlighted earlier, we see gas as having a really long runway in North America as North America phases out coal-fired generators and advances renewable projects. As both nations' fuel mix gets cleaner, the attributes of gas-fired generation will fill the void left by coal, and it really ensures the resiliency of the grid as intermittent sources are added. So much is already attached to our system and awaiting firm capacity. We talked at length about the Northeast, so I won't go back there again. I'll just mention that PJM projects an increase of 16 gigawatts of gas-fired generation over the next few years, again, resulting from coal retirements. At the end of the day, whether it's New York, whether it's New England, PJM or MISO, natural gas is going to be a core component of the fuel mix. Okay. Favorite slide.
No investor presentation is complete without the picture of a butterfly. I really just wanted to give you a couple of examples and build on some things that Al said about how ESG is really woven into what we do and how we do it. One example is the butterfly. It was done during the execution of Valley Crossing, the pollinator pathway. It was designing our right of way for Valley Crossing to help in the proliferation of the monarch butterfly in South Texas. It's a joint effort between, I see a lot of smiles, Enbridge, the King Ranch, and a lot of other stakeholders, to really lead the educational and the outreach activities and support local research. This initiative is really important because it allows us to advance the knowledge of pipeline right of way restoration, which is misunderstood.
It enables successful restoration of future pipeline rights of way proposed for similar ecosystems, not just in Texas, but across our footprint where we will be building. Also shows we can work together, researchers, the pipeline industry, private landowners, towards natural resources conservation solutions in tandem with energy development. Also related to Valley Crossing, we're building a reef for red snapper and game fish in the Gulf of Mexico. With respect to NEXUS, the FERC staff recently commented that the way our NEXUS team organized and executed the environmental compliance program is how FERC envisions an environmental compliance program is supposed to work, and wishes all projects could be executed as well as NEXUS. Very good. The competition is great, but the industry as a whole needs to up its game. We aren't just supplementing renewable power's intermittency with gas for power generation.
We're actually building renewable power ourselves to power our own facilities. Our solar self-project will generate electricity for a portion of our Texas Eastern compressor station load in Pennsylvania and New Jersey. That could be the beginning of quite a bit more to come. Finally, we're part of an industry commitment to reduce methane emissions at our operating facilities, which syncs up nicely with our modernization program. Last slide. We really do enjoy a fantastic solid-based business that's going to grow at about 1% a year through modernization and integrity work alone. We've got CAD 4 billion of secured constructible projects that'll be bringing us good growth in the short term, another 3% or 4% per year. We're furthering our growth strategies, especially leveraging off the coastal footprint to win LNG export pipeline deals, among other opportunities. That's it.
Thanks very much for listening today, and I'll be happy to take your questions, if there are any.
Hi, Robert Hope, Scotiabank.
Hey, Rob.
Just a question on the modernization. It's CAD 800 million in 2020, but wanted to get a sense of what the runway is there. Is this a multi-year program that we could see?
Yeah. I think modernization is, as I mentioned, it has very specific programs in some cases, and it's a bit ambiguous in others, right? There's kind of two components to it. Modernization, we've got a CAD a billion-dollar program, first year of which is embedded in that CAD 800 million that you mentioned for 2020. It's probably over the course of three years, that makes up a big chunk of that. I would say the ongoing modernization, plus some of our integrity work, probably is CAD 500 million a year or more.
All right. Just switching gears, just regarding the recontracting on the gas lines, how are you looking at some of the pains producers are feeling in terms of counterparty risk there?
Yeah. It's a great question, and it took me back about a decade where we looked at all the same factors. Interestingly, when I mentioned that we've sort of come through with a solid base under any economic conditions, that's kind of what I was thinking of was back in 2009, 2010. Similar. First thing you look at is, okay, where do these producers have contracts? That's probably the most critical thing you look at. Basically on every pipeline, save one, we would say that there is no threat even if one of these producers wanted to turn back their capacity or had to turn back their capacity, we couldn't remarket it at that rate. When you think about it, Rob, a lot of what we have in producer contracts emanate from Appalachia. Gas goes three ways, right? It goes south.
Those contracts are very cheap relative to other contracts. Not a whole lot of worry there for a couple BCF a day. It goes east. Eastern capacity is severely constrained. If they dropped it, somebody else would certainly pick it up for that rate. It goes west and north up through NEXUS. That's probably the one, because it's a new pipeline, that if we had one or two producers there, that'd be the only one we're probably concerned about. That's the first thing you look at is where are you? Where is your geography?
Rob Catellier, CIBC. Just a capital allocation question in the gas business. Outside of your in-franchise opportunities, which of the following two would you prefer? A large-scale investment in distribution or an LNG pipeline opportunity that might take several years to develop and construct?
Cynthia would snag any distribution opportunity away from me immediately. That really leaves me with one option. I think the choice between those two things would be a better question for Al. I would say that a large-scale LNG facility, frankly, there's only likely to be one or two of those because of the connectivity that we have in the Gulf Coast. I would say that it's unlikely to see something massive. A lot of things that I mentioned earlier, they're CAD 100 million, CAD 200 million, maybe up to CAD 500 million efforts today to Brownsville, greenfield probably, perhaps leveraging what we have today. That would start off at CAD 1 billion.
To the degree that Brownsville became a larger port, either for NextDecade, which has significant plans or if two or more of those facilities go with Annova and with Texas LNG, probably represents a starting point at CAD 1 billion or not. I wouldn't characterize it as major greenfield. Western Canada, potentially. Westcoast Connector Gas Transmission would be something that I would call large scale. We just have to look at it carefully and make sure we were building in all of the vagaries we see in building wide scale infrastructure today.
Bill.
Hey, Bill. Michael Lapides with Goldman. One of your first slides talked about Northeast power demand. Just curious, how are you all thinking about all the forecasts for gas demand in this part of the country, especially given the significant wave of offshore wind, pardon the pun there.
Yeah.
That seems to be coming four to five years from now and beyond, given all the state mandates. As you hear a lot more focus on energy efficiency, which has made a really big impact on the electric demand side, migrating even more so onto the gas demand side over the next five or seven years.
Yeah. Great question. There's no doubt that you can't look at today's landscape and say, "Okay. Well, whatever's retiring, it's going to go gas." We know efficiency has come in. We know that five years down the road, you're likely to start seeing some of these offshore projects actually materialize. I guess what I would point to is that with the retirements that we've seen, and with a good portion of that renewable power coming online, that will be not just intermittent, but I know a nameplate capacity says, "Okay, this should do 40% or 50%." That's on average, right? That's on average powering homes. We don't power our homes on average.
I think that the gas-fired generation, which is really the only source that's going to have the ability to ramp up and ramp down, is going to be the survivor and will be in a very good position for us to have our sort of isolated, we should call them reinforcement projects of our system rather than anything new greenfield. We touch about 60% of the generators in New England and a significant portion in New York. I think it's just firming up that load to make sure they have what they need when renewable power diminishes.
Jeremy Tonet, JPMorgan. Maybe building off that last point a bit here. It seems like the need for more natural gas in New England is quite obvious, as you stated here, yet for peak winter needs, they continue to prefer Russian LNG over Pennsylvania gas. Just wondering, what's it going to take to change that? Have you seen any signs of progress? Just any thoughts you could share there.
You and I have had this discussion before. This is one that will get my blood pressure going a little bit. First of all, despite Russian LNG, the LNG facilities in that region are extremely important. They are very good customers for us. Once the LNG comes off of the boat and gets into the terminal and gets vaporized, we have contracts with Repsol from Canaport. We've got contracts with Distrigas. We've got contracts with Excelerate. They make up a fairly significant portion of revenue on the Maritimes and the Algonquin systems. The fact is, there are vagaries involved with that. They have the same issue that we have as pipelines, which is unless generating market steps up and signs up for term, then you can't guarantee that a ship's going to show up. You can't guarantee that our pipeline capacity is going to be there.
I do think we're starting to see real cracks in the foundation. This isn't a generation example, but Jeremy, I think many of us are aware that Newport, Rhode Island, had an issue last year. I got to say, the pipelines in this region, we are jumping through hoops to try to get our local distribution companies and electric generators the gas that they need. Jumping through hoops. That's not being lost. When last year, we actually saw the pressure get so low at the intersection between our pipeline and the National Grid distribution territory in Southern Rhode Island. The pressure couldn't take it. It shut down, and thousands of customers were without gas. Coldest time of the year, obviously, because that's what happens.
That dynamic doesn't have to repeat itself too many times before I think you suddenly do start to feel the political pressure to get something done. I do believe that local distribution companies would be first. They have the ability to sign up for new transportation capacity. We're in discussions with all of the local distribution companies in New York and New England to try to get them expansions to our current system. I do think power generation will be next, but probably later. Wholesale, large-scale improvements through the state of New York or New Jersey might be a challenge. We've got to take what we can get. PennEast is a good example of this, too, where we're permitted through Pennsylvania, have a FERC certificate. We've got some holdups in New Jersey.
How can we get creative to have more reinforcements perhaps in New Jersey and New York to get that gas to where it needs to go?
My family in Rhode Island didn't appreciate that in the cold of winter. We hope you have good luck there. Maybe building on that with New Jersey. PennEast, wondering if you could provide a bit more commentary there. It seems like there's some issues. I don't know if you can provide more of an update.
Yeah, not much more color. It's basically we've got to look ourselves in the eyes as a project team. Remember, PennEast, it's not just us. We're 20% of the project from an equity standpoint, and there are four other partners, all of which are essentially off-takers and would benefit from this pipeline being built. Utilities. We probably, without giving away too much, we just have to look at the route that we're taking and the states that we're going through to say, where can we build greenfield, and where might we need to do some more reinforcing of our existing system to get as much volume to those customers as we possibly can? That's kind of a squishy update, but we're right in the middle of that analysis right now.
Great. Just one last one, if I could. With Frontier, just curious how you walk into that decision process with how deep do you want to get into the NGL business there? Does it make sense to in-house or outsource those needs? Any color you can provide there?
Yeah. We just want to help, right? We've got a situation that we actually have seen on other parts of our U.S. system as the gas mix has changed over the years, over the decade. Essentially, all we're trying to do is say, look, we could get to a point where the NGLs that are entrained in the gas stream are having an effect on gas quality. We saw this play out in other regions, as I mentioned, of the U.S. What we had to do is say, look, we're going to have to either develop or have a gas quality specification because downstream, that ultimately becomes a problem. Pilot lights start going out if you have your BTU content too high or if there's liquids in the gas and all that.
We're a long way away from that, but we can see it. Infrastructure doesn't pop up overnight. We can't just build it tomorrow. We feel as though we're part of the solution here. If we're not part of the solution, somebody ultimately will be, or there's going to have to be some governance on what gas can enter the system. Nobody wants that to happen. I don't think we're thinking of it like, oh, let's get into NGL infrastructure. I think we're just saying, look, there's a clear need. It's on our system. Ultimately, our customer's problem is our problem, so let's see if we can't solve that. Whether we own 100% of that or partner with folks that are more apt to that type of infrastructure, that's too early to say.
Hi. Shneur Gershuni with UBS. Just one question. In the 16 years that I've been in this job, there's always been a reluctance to file for rate cases between you, your peers, and so forth. You almost seem like you're embracing it right now. I was wondering if you can sort of talk through that process.
Yeah.
Are we that far behind on rate bases and OpEx in terms of being reflected in rates? Is there a change in the culture at the FERC? Should we see a wave of this from your peers as well, too?
Yeah.
Interested in the change.
What a fantastic question. Yes. I am excited about it, actually. I mean, look, yes, they can be contentious, especially if you haven't done one in 28 years. People have to sort of relearn or learn for the first time what's going on. They're also a really good opportunity to interact with your customers and to make sure that everybody understands what needs to be done. Generally, you reach that conclusion. What has to happen here? I mean, customers don't want us. Maybe a few do. Most of them want us to succeed, right? They're sitting at the end of our pipeline. The cost of service-average rate payer to us is a utility, and they have a very similar dynamic that goes on behind their system.
I would say that one point you brought up that I don't want to lose because I'll forget is this going to be more than just Enbridge? The answer is yes. I can't speak for all the other major pipeline companies, but I can say that a lot of what's driving this is that the cost of new equipment, the cost of addressing emissions requirements, putting in new compression, is vastly more expensive than it was five, 10, 15, 28 years ago. Refreshing all that on a periodic basis, I think will be required. You may have seen some of our peers, and frankly, ourselves included.
We try to get tracking mechanisms to say, if we've got a billion-dollar program or we're going to spend CAD 200 million a year to satisfy emissions requirements, build that in automatically. We don't have to go through this song and dance on that. It's a lot easier said than done, both the negotiation side of things and the FERC approval of that. It'd be great to get trackers that help us out, but I think it's going to lead to more pipelines actually having to go do rate cases because I walk in and say, "Well, we're going to spend a couple of hundred million CAD on four new compressor stations in Pennsylvania," I'm not going to get recovery on it for 28 years. That's a problem, right? I think we have to get into this cadence of routine rate cases.
I guess the factors are it's going to be, one, across the board, and two, it's just a reflection of higher costs. I'm sorry I'm talking so much on this question, but I think the other thing that led us to Texas Eastern was that we really had to refresh what we had there. If you remember, between FERC and first treatment of the Tax Cuts and Jobs Act and the influence that had on our rates, we started sort of in a hole, having to look at a reduced income tax rate and built up from that and still achieved CAD 50 million-CAD 70 million of incremental EBITDA.
Thank you.
I was rambling. I apologize for that. Hey, Linda.
Just as a follow-on. I know that you're very competitively positioned. A lot of settlements. This is not a near-term problem. The FERC has an NOI on ROE that your peers are quite confident should not be an issue. 10, 15 years from now, if you set a precedent where there's a surprise ROE that's lower than industry expected. Is that something that the industry is working on, or can you comment on your approach to how that might evolve?
Yeah.
Might it become a priority?
I don't know. 10 or 15 years is a long time. In the near future, I guess, sort of Texas Eastern rate case or rate settlement, it's a black box. It's difficult to distinguish what your ROE is from what you got for an interruptible credit. It's just one big settlement. The vast majority of rate cases will wind up either in a prepackaged file settlement or a settlement that we reach with our customers overall during the course of the case. I think ROE is a part of that. With Texas Eastern, I think we got a 12.75% ROE on future projects. You can guess whether that was embedded in the black box settlement or not, but generally it's something different. I don't look at it like the NOI is going to have a material impact.
I think, once again, we are likely to be in settlement discussions with the customers and settle on a whole number of things all at once.
It will be a negotiating point for them, like a data point.
It will be. It will be. There are other things that would fall in our favor on negotiations as well.
Okay. Thank you.
I think this will be the last one.
Thank you.
Thank you. Sunil Sibal from Seaport Global. My question was related to the Alliance Pipeline.
I believe you had been working on a project on that. Just wanted to see if you can update us on that. Especially, considering three years of remaining life on that.
Yeah, I wish we could. Alliance is full and it's in a great position to either take incremental Western Canadian Sedimentary Basin gas or Bakken gas. It's a unique asset in that it's really a wet line going into Aux Sable and into the Chicago markets. We tried for a long time to compete for Western Canadian supply to come down. We've really been focused much more on the Bakken lately. Haven't gotten anything quite yet germinating, but I think that's probably all I can say on that, is that we keep trying, and we believe that it will be a competitive project soon. Yeah. Yes, you can answer that? Yeah, you. Yeah.
I'd like to just come back to one question.
Yeah.
Okay. I think it was Rob that was trying to get us to choose between a gas distribution investment and an LNG pipeline. I thought that was a good question. Obviously, if you go back to what we said in the overview, our investment envelope is substantial enough here in the next little while, with CAD 5 billion-CAD 6 billion of available cash to reinvest to do both. Let me put it this way, if we had just the absolute choice, we would be doing gas distribution projects all day long for a whole bunch of reasons. The risk-reward there is very strong. On the other hand, the LNG opportunities that Bill's working on are right down the middle of the fairway as well. Our hope is that we could actually feather in those as well.
Remember, there's going to be some probably more permitting issues there, which we can accommodate with the hurdle rates that we set for those particular investments. The idea is that we should be able to do both, but certainly, the utilities are every bit is what we do in the business for sure. I guess the LNG pipes are not that much further behind.
Well, that sets up Cynthia quite well, I think. Over to you.
Well, thank you for that setup. That's fantastic. Good morning. I'm very happy to be here too. As you've heard, I run our Gas Distribution and Storage team, we'll talk about the gas utility a little bit now. In Ontario, natural gas has a sustainable economic advantage over other energy sources. We have an exceptional and growing residential and commercial customer base. Our regulatory construct allows us to drive strong returns by releasing synergies and capitalizing on growth in a low-risk environment. That's a unique offering within our pipeline peer group, but very much consistent with the overall Enbridge business model and value proposition. Our great people and great assets provide a platform for safe, reliable operations and support continued growth.
Based on our five-year regulatory deal with the Ontario Energy Board, on January 1st, 2019, we amalgamated Enbridge Gas Distribution and Union Gas into Enbridge Gas Inc. We have the largest and best-situated gas utility in Canada, supporting Ontario, Quebec, and the U.S. Northeast markets. We're number one by gas send-out in North America and we're the third largest by number of customers. Our expansive reach into over 12 million people and businesses through our 3.7 million meters ensures that we're well-positioned for growth. Our 280 BCF of storage assets are tied to large and growing demand centers in Canada and the U.S. and provide a critical link to low-cost natural gas supplies. We're already delivering significant synergies from the utility amalgamation this year, and we're well-positioned to capture more.
The regulatory regime is stable and allows us to earn a premium return over a traditional cost of service allowed ROE construct. The issuance of our 2019 rate decision by the OEB validated our growth capital recovery mechanism and lays the groundwork for attractive growth opportunities. As I mentioned earlier, our demand fundamentals remain very solid. We continue to see strong population growth in Ontario, driven by robust immigration. This drives condo and new neighborhood growth, and with virtually all new homes connecting to natural gas. On the commercial side, our franchise area generates 40% of Canada's GDP, which provides highly resilient demand for natural gas, including greenhouse and cannabis developments. Our five-year framework provides that stable distribution rates with access to abundant, low-cost gas that delivers the most cost-competitive energy source. Gas is 57% cheaper than electricity and 67% cheaper than heating oil.
The big news here is that the provincial government policies are providing opportunities to expand natural gas into new communities. As Bill mentioned, consistent with the other utilities, we've broken our priorities into these three buckets. Optimizing the base business, executing our secured projects, and growth. To optimize our base business, we will continue to drive even more synergies and as we grow our business. We have an exemplary record of executing on secured projects. We're on time and on budget, revitalizing our extensive distribution and transmission assets and supporting growth. We have a clear line of sight to that steady annual growth opportunities within our franchise as we add about 50,000 new customers each year.
Other growth will come from the continued need to expand our Dawn storage hub and gas transmission assets, as well as the opportunity to green our gas grid with complementary lower-carbon assets. That key element of optimizing the base business is extracting efficiencies from our operations. Each of our legacy utilities have been able to drive efficiencies through incentive regulation and earn above the allowed rate of return over the past decade. Doing this while maintaining our focus on safe and reliable operations. The amalgamation provides us a new opportunity to capture further efficiencies. An attractive feature of this new incentive-based regulatory framework is that Enbridge retains 100% of the savings achieved up to the first 150 basis points above the allowed ROE, and then we share 50/50 with our ratepayers on savings beyond that. We've developed a very clear execution plan to deliver these synergies and savings.
Our committed and engaged team is focused on eliminating role duplications, aligning our operating practices, moving to single platform, driving synergies, and providing that strong, stable financial result. We're targeting to earn over 100 basis points above the allowed ROE. Each 50 basis points equates to roughly CAD 30 million to CAD 40 million of EBITDA. The 2020 allowed ROE has been set at 8.52% according to the OEB's formula, that's a bit lower than previous years. Again, our incentive framework provides us the flexibility to earn more. In the next couple of slides, I'll just highlight where our growth capital opportunities are. As outlined on this slide, we're advancing several secured projects through the OEB approval process. We have the Dawn to Parkway expansion, the Windsor line, and Owen Sound reinforcement.
These are bread and butter projects that arise through the ongoing system renewals and the throughput growth over time. We have about CAD 0.4 billion of planned and approved projects coming into service over the next couple of years, and approximately CAD 500 million of annual normal course connections and reinforcements, call that core rate based growth. About CAD 1 billion in total secured projects that are underway. Looking forward, our regulated growth opportunities are consistent and transparent. I mentioned earlier that we add about 50,000 new customers each year, and that's an important way that we continue to optimize our base business and continue to drive growth. We're currently executing five community expansion projects and could potentially expand up to 50 new communities within our franchise area over the next coming years. Demand in these communities is really strong.
In our recent expansion at Fenelon Falls, our targeted number of customer connections was exceeded by over 200%. The growth in the franchise area drives the need for investments in system reinforcements to enhance capacity and ensure deliverability and redundancy of the overall network. This is an interesting contrast to what we are seeing in the U.S. Northeast. Importantly, all of this capital is effectively recovered under a low-risk cost of service framework that I'll highlight next. The over CAD 1 billion that we invest annually in capital earns a return under our regulatory framework in one of two ways, either base capital or incremental growth. The base capital is recovered through the escalating annual toll, and this covers renewals, replacements, reinforcements, new connections, and expansions. Our 10-year asset management plan provides that overview to the OEB.
The threshold for that base capital has been set based on our historical capital spend to safely operate and to grow. Our incremental growth projects are discrete and individually approved by the OEB with a cost of service toll surcharge in the year following completion. All of our ICM filings so far have been accepted by the OEB. Our storage assets at Dawn and Tecumseh and our transmission assets, including our Dawn to Parkway corridor, are critical to support regional gas distribution. They're always in high demand. Dawn is the second most liquid hub in North America. We're a market leader in highly reliable, competitively priced storage and transmission services. Our large storage serves Michigan LDCs as well as power generation markets in Ontario. We're continuing to grow the liquidity at Dawn, providing peak and seasonal services, leveraging that combined amalgamated asset base.
A CAD 1.5 billion build-out of the Dawn-Parkway System was completed in 2017. We're expanding again in 2021. There's also a strategic link to build NEXUS and Vector systems and ultimately growth in Marcellus and Utica, which provides us with growth opportunities for storage and transmissions over time. Lastly, in addition to these great traditional growth opportunities, we're prudently building out our lower carbon infrastructure within our rate base and with cost of service-like models. Greening our grid is currently a small component of the business, but it's a very important aspect of our resiliency to the changing business environment that Al has mentioned. A great example of this is the Dufferin RNG project that we're currently constructing with the City of Toronto.
This project captures RNG from the city's green bin program, and the gas is injected into our system, and that can be used to fuel the waste removal trucks that collect the refuse. We're currently working with municipalities, commercial operators to expand generation and capture of renewable natural gas associated with landfills, biodigesters, and other similar opportunities. CNG is a lower cost and lower carbon alternative for fueling heavy-haul transportation. We've installed CNG stations along key highways, and we're working with transport companies for expansion opportunities. Cities like Hamilton also use CNG for busing. We've also installed the first large-scale hydrogen power to gas fuel cell in North America. That's helping to balance the electrical load, and we're looking at hydrogen blending options within our network. We have other behind-the-meter solutions, including integrating gas and electric infrastructure.
We're not talking about big investments because we're still at early stages, but most of the work to date has been within our franchise area, but we do see opportunities that exist to expand outside our geographic footprint, and we'll do that once we're confident in the technology and we're comfortable with the various regulatory jurisdictions. In summary, we have great distribution and storage assets that are core to Enbridge's low risk and resilient business. We are a best-in-class utility, and we lead with operating and cost management. Our location in the major growth center in Canada and our low energy cost ensures that we have that steady demand pull. Over the near term, we're going to continue to drive value by optimizing our base business through the amalgamation synergies and streamlining our operations. This should deliver the 1%-2% annual base growth.
In addition, our reliable capital additions at almost CAD 1 billion a year makes a very meaningful contribution to Enbridge's annual growth. Over time, we'll continue to build out the franchise, green the gas grid, maximize synergies, leverage our large size, and safely operate while we deliver those strong and stable financial results. That was my overview, and I'm very happy to take any questions you have.
Hi. I apologize for this question. I'm confused. I'm going to ask the question.
No problem.
As it relates to deciding upon investing in Bill's group or your group, Al answered it, but you said that you have an 8.25% allowed ROE, plus you can earn another 100 basis points, I guess that brings you up to 9.25%. I thought Bill said that on his incremental projects, he could earn 12.75%. Did I get that wrong or I must be missing something?
The numbers are slightly different than what you mentioned. We have an allowed ROE of 8.5% right now. That varies, of course, based on the OEB formula. Our opportunity with our current deal is to earn up to 150 basis points above that, keeping 100% of those synergy capture savings, and then we would share 50/50 over that. There's no upper-end cap on that. It's just right now we're targeting with all the activities to earn approximately at least 100 basis points over that allowed amount. The other thing that we have in a utility is a very low-risk business model. I think that's what is so attractive. With that very transparent and steady growth, if you can replicate that fits into the overall Enbridge value proposition. As Al said, he's very keen to invest in Bill's business as well.
If Bill wanted to add something on his returns.
Yeah. The only thing I'd add, Steve, is that 12.75, that's what the embedded return would be. What we negotiate if we're doing a negotiated rate agreement might be higher or lower than that. It's not a guarantee of anything.
Did that help clear it up? Great.
Over the years, there's been ebbs and flows of, let's call it speculation around Enbridge and other entities' interest in investing in electric distribution in Ontario. I assume that the silence in your presentation implies there's nothing immediate. That would be my perception as well on other fronts. Can you comment on how that fits into the corporate strategic priorities in terms of beyond just squeezing out operating synergies? I don't know if this is a broader question for the broader group as well, electric transmission, how you guys talk and think about if that might make sense someday. I know you don't need to invest in that because you've got a lot of opportunities related to your core businesses, but there have been investments made by Enbridge over time.
Well, I'll talk about Ontario, and then I'll let Al talk about the bigger platform for electricity in North America. We do continue to monitor what's happening within the various LDCs in Ontario. Obviously, there may continue to be opportunities for us to look at how we could invest. There are also lots of opportunities for us to try and grab incremental synergies. When we're building our platform, for example, our new interface with our customers, our customer information system, we're building something that would be best-in-class for all utilities, looking to that future, so we'd be positioned for opportunities as they come along. There's nothing in the works right now, but we'd always be interested in that, because there would be, in Ontario, some obvious opportunities for synergy capture like that. Al, maybe you'd want to comment on the electricity platform overall.
Sure. Well, it's a good question, Linda. If you look at it, electric utility fits the same kind of business model as Cynthia's business. It's low risk. It's infrastructure that's required, lots of growth in it, and the fact that you've got an energy transition happening would make you think that that's a possibility, I think, in the longer term. I think it fits all of those parameters. I think at this point, we don't have anything on the plans that would push us to acquire electricity distribution utility, but certainly would fit in the bigger context longer term, I suppose. On the transmission side, probably no to that, just given the inherent challenges, especially if you're trying to build out a transmission business independently of a big utility. That's how we look at it right now.
All right. If there's no other questions, I think Jonathan's going to lead us into a break. Thank you.
Thank you, Cynthia. I think we're right on time here. It's 10:15 A.M. now. We've got a 15-minute break, so we'll come back at 10:30 A.M. and commence with liquids. Our executive team will be mingling, so please introduce yourself and engage. Thank you.
Okay, good morning, everyone. It's great to be back in Liquids Pipelines. I was last at Enbridge Day talking about liquids in 2013. It might surprise you to hear that I'm as excited today about liquids as I was back then. Our business is in great shape. The fundamentals are really strong. I'm going to spend most of my remarks talking about that, and then Guy's going to come up and talk about how those fundamentals drive our strategy and growth opportunities over the next several years. As you all know, our liquids platform is the largest network of pipelines and terminals in North America. We start in the oil sands, then we pick up production in the Rockies, the Bakken, and we move this crude to markets in the U.S. Midwest, eastern Canada, the Mid-Continent, and ultimately to the Gulf Coast.
Our system, as Al mentioned, is really a demand pull system. We're connected to three-quarters of the refineries in North America. That's almost 13 MMbpd of refining capacity. Obviously, liquids is a big part of Enbridge. We have all the features that Al mentioned. We're resilient, we're disciplined in our approach to spending capital. We have a large amount of embedded growth. Our system, in a little bit more detail, is directly connected to 2 million barrels of refining capacity in the U.S. Midwest and eastern Canada. That's been our historical core market. Over the years, we've extended our system further south. Now we have 1 MMbpd of directly connected pipeline demand to the U.S. Gulf Coast, to Cushing, and the Patoka market.
Because of this connectivity and our scale and our low-cost tolls, we're highly confident that our system will be highly utilized for decades to come. Over this year, I think we've made some great progress in our strategic priorities. We have had record throughput on the system. With the recent optimizations we put through this month, we now have capacity to move almost 3 MMbpd across the border. As Al mentioned, Line 3 Canada went into service a few weeks ago, and we're now earning some incremental revenue with the new toll surcharge. This is good for us, it's good for our customers, but most importantly, it improves the safety and reliability of our pipeline network. We're also having a record year on the pipeline safety front after having a record year last year.
If you think about the fact that we've moved almost over a billion barrels of oil this year, we've moved 99.9999% of that safely. That's quite remarkable that we can move that much crude safely and reliably. With that context, I'm going to talk a little bit about the fundamentals of our business. We all know that North America will be the primary source of global crude oil supply growth over the next few decades. Obviously, there's going to be significant opportunities for growth in the U.S. with the shale plays coming from the Permian, the Bakken, and the Rockies. We shouldn't forget that there's significant heavy crude growth coming from Canada as well. There are a series of projects under construction right now, and we have about 200,000 bpd of heavy crude being shut in with the curtailment policy in Alberta.
We also expect that if we get incremental pipeline egress, that will stimulate even further growth in Canadian heavy crude supply. We are actively working on near-term and medium-term capacity optimization to help spur this growth. Guy's going to speak to that a little bit more later today. As all this incremental crude is coming to the market, it's really all headed to the U.S. Gulf Coast now, as we've saturated the traditional North American refining markets further north with the North American supply. That's why we've been so hyper-focused on improving our footprint in the U.S. Gulf Coast. The refineries along the U.S. Gulf Coast have historically been really geared for heavy and medium crudes.
With the crude slates lightening up in North America, with declines in heavy crude coming from Latin America, I think this provides us with significant opportunities to provide more infrastructure to deal with those changes in supply. Once we see these refineries on the U.S. Gulf Coast fill up, really the next phase will be exports. Okay, let's just spend a few minutes talking about Canada. I think a lot of investors have slipped away from looking at Canada because we've seen a lot of challenges in the upstream sector here over the last few years. While these challenges have been going on, our customers have been making significant progress in both reducing their cost footprint as well as their environmental footprint.
Let's not forget that Canada still represents one of the largest supplies of potential crude oil supply globally, and it does have, on an aggregate basis when you look at ESG as a whole, the best track record of all these potential future supply sources. Let's dive a little bit deeper. It's been a tough market for our customers, but oil sands production has been resilient. We continue to see the industry strive for further improvement, and our customers have improved themselves in meaningful ways. They've strengthened their balance sheets. Many of them have integrated themselves with downstream refining assets. As I just mentioned, they've lowered their costs and lowered their emissions. If we can provide more egress, we think there's going to be some good growth opportunities for our customers. Let's just spend a few minutes on how the industry's improved.
There's two things I'm going to talk about, cost and emissions. We've seen the oil sands producers really take into account innovation and the application of new technologies and processes to lower both their costs and their emissions. If you look at the middle chart, you can see that our customers have really lowered their lifting costs. Now, for a new brownfield SAGD operation, you only need CAD 50 a barrel of WTI to make your appropriate returns, and that takes into account quality differentials and transportation differentials. On an operating cost basis, it's even lower. It's about CAD 20 a barrel on a WTI equivalent basis as well. This underpins the sustainability of the production coming out of Western Canada.
We saw in 2008 and again in 2014, even when crude oil prices collapsed, we saw that the oil sands were resilient and the operations didn't skip a beat. These assets are long-lived with very low decline rates. Perhaps even more important, we've seen very significant improvements in GHG emissions coming from the oil sands. On the chart on the far right, you can see that the emissions coming from the oil sands have gone down very dramatically over the last 5 to 10 years. Where today, on average, oil sands GHG emissions, when you compare it to other heavy crude sources, is well below the global median.
If you look at the newest production sources, if you look at Aspen or Kearl from Imperial and some of the new Suncor plants, you will see these new facilities will actually be on par on a GHG basis with your average overall crude oil production globally. I think we should be very proud of the fact that our customers continue to innovate their operations. Canadian supply is there, and it will grow if we can find the right egress opportunities. The opposite is happening with other heavy crude production globally. You can see that Venezuela and Mexico are obviously in significant declines as there hasn't been enough investment in this production over the last several years. Canada, over time, will become the dominant supply source for the U.S. Gulf Coast.
We expect in the next 10 years to provide over 50% of the heavy crude to the U.S. Gulf Coast. I'm going to now move a little bit to both egress and netbacks. Obviously today we're capacity short out of the basin. That is being met with rail and temporary production curtailments. We've balanced the market that way. That isn't sustainable or economic over the long term. We need to find more pipeline solutions. Line 3, when we put the U.S. portion of that project, will begin to solve that problem. Guy will importantly discuss that post Line 3, we'll have a number of low-cost, minimal permitting Mainline system expansion opportunities that can add more egress out of the basin. Our shippers obviously know the value of our system, and that's why they're eager to contract the Mainline for years to come.
Guy, in his remarks, will provide more context of the contracting situation. Suffice it to say that our network provides the best access, the best pricing, and optionality for both light and heavy crude. You can see on the chart on the right, if you're a Canadian producer, we get you the best netback, whether you're producing light crude or heavy crude. For light crude, the best netbacks happen if you're able to access the Eastern Canadian markets. You can only get there on the Enbridge system. After Eastern Canada, you want to get to Patoka. We have multiple ways of getting your light crude to Patoka. Once you fill those two markets, ultimately, you'll want to get to the U.S. Gulf Coast to export your light crude there. We obviously provide access there through Flanagan South and Seaway.
Moving to the heavy side, the best netback if you're a heavy Canadian producer is the U.S. Midwest. Those refineries are landlocked where they don't have a lot of alternatives versus Canadian heavy crude, so those refiners will pay the highest price for that crude. Once that market fills up, then you'll move to the U.S. Gulf Coast. Those refineries, as I just mentioned, have very significant requirements for heavy crude. Once those requirements fill up, which will take quite some time, at some point in the future, we'll also need to have the ability to export heavy crude off the U.S. Gulf Coast. These changing supply fundamentals are really going to impact infrastructure opportunities on the U.S. Gulf Coast. I think one of the things that people don't realize is that each refinery is very specific in its needs for a specific crude slate.
Many of these refineries have spent significant dollars on a kit that's designed to process heavy crude or a medium sour crude. With the change in how the supply dynamics are working in North America, where there's been a lightening of the overall supply mix with increased production coming from the Permian, Bakken, and the Rockies, and a heavy supply coming from Canada. There's been this rapid decline in offshore medium-type crudes. I think it's very important as we look at the Gulf Coast, that you have to think about how do we stage this crude to get the right crude slates to the right refineries. That's why we think our Jones Creek terminal is going to be a very significant opportunity.
It will be a major hub of getting those right crude slates to the right refineries in the U.S. Gulf Coast, and then become a central point to stage for exports. Ultimately, as crude supply increases on the U.S. Gulf Coast, it will become more important to get the most economic solution available to export that crude to the growing demand centers in Asia. Today, Aframax and Suezmax vessels work, but as we see supply continue to grow, we'll need better economies of scale to ensure that producers get the best netbacks for those exports. We think that Houston is the ideal market to stage exports because all the different types of crude come into the Houston market. It's very short distance to deep water, and we'll have our Jones Creek terminal there to provide the tankage to stage these exports.
On my last slide, I'm going to just change gears a little bit and just talk about stakeholder and indigenous relations. We all know that you need local stakeholder support and indigenous community support to obviously permit and build a new pipeline. Without that support, you're just not going to make it happen. As Al mentioned, it's not just during construction where you need the local support. These days, you need that support through the life cycle of a pipeline. We've continued to evolve our approach on how we deal with people in local communities. We want their commitment and support over the long term, so we've made a bigger emphasis on being on the ground and being a bigger part of that local community.
We've introduced practices where we work hand in hand with communities to ensure people living there have the skills, the training, the capacity to work along our right of way, to work with us in building a pipeline, and then ultimately work with us as we operate that pipeline over its life cycle. We think by doing this, we've strengthened our support in these local communities where they want to work with us on an ongoing basis. We have a number of examples of this. Maybe I'll start with Line 3 Canada, where we engaged over 100 indigenous groups as we built the pipeline. We worked collaboratively with them on picking the micro route. We employed 1,100 First Nations people during construction, where we paid CAD 140 million of wages directly to these individuals.
While you don't hear much about this in the media, we also have applied that to the U.S. portion of the project, specifically in Minnesota. One of the things that we've done is we've been able to reach an agreement with the Fond du Lac Tribe, where we've been able to route the Line 3 replacement through their reservation and extend the easements that we have there for another 20 years. We were able to do this by working with them on the specifics of the route through their reservation, by working with them to provide employment opportunities during construction, and then during the life of the operations of the pipeline. The key takeaway here is we've obviously been working on stakeholder and indigenous relations for many years, but we continuously want to up our game here. We take this aspect of our business extremely seriously.
That really wraps up my remarks, and I'll pass it over to Guy to talk about our strategy and our growth potential.
Thank you, Vern. Good morning, everybody. It's great to be here again to talk a bit about our strategy. Vern has just spent a few minutes talking about how Liquids Pipelines fits within our overall Enbridge, a bit about the fundamentals that drive us, and what we've accomplished in 2019. Clearly, we've had a great run over the last 15 years of pretty sustained growth in Liquids Pipelines, and our goal is to continue to position ourselves to extend that track record going into the future. Our strategic priorities, like the other business units, optimizing our base business, executing our secured projects, and continuing to grow the business are unchanged, but we're really pleased with the progress that we've been making in all of these areas in 2019. Mainline optimization continues to pay dividends, not just for our shippers, but for ourselves as well.
As Vern said, it's a great source of pride in our organization to be moving record volumes on the Mainline while achieving record safety and reliability at the same time. Placing the new Line 3 Canada into service, very important milestone for us. Project came in slightly below budget, further enhances our ability to optimize Mainline throughput, provides the safety and reliability enhancements that were critical to the construction of the project in the first place. Finally, and not the least of important, starts to generate some revenue through the interim surcharges that we negotiated with our shippers. In Minnesota, Al ran through the process for Line 3, which we're happy to say is back in the hands of the PUC and progressing. The related Southern Access expansion that we've been working on for a while is in really good shape and pretty much ready to go.
Contracting of the Mainline has come a long way. We're going to hear some more about that in a minute. We continue to have strong support for that proposal. We've been advancing our U.S. Gulf Coast strategy. We have a really good line of sight now to what we want to do. We're starting to execute on that right now based on the announcement we made yesterday and some other things. Despite a challenging environment, we're really pleased with the momentum we've got going on all the elements of the strategy. The base business is underpinned by strong volumes, toll certainty, attention to costs, and a focus on highly efficient capital projects.
While looking forward at the growth picture, our efforts are focused on low capital intensity extensions and expansions of our footprint, with the ultimate goal of extending our integrated value chain all the way through to the Gulf Coast. Last year at this time, we highlighted our goal to grow our base business, and 2019 performance has only bolstered our confidence that we can continue to do that. For us, it's pretty simple. The bottom line drivers are volumes, tolls, and costs. In addition to our history of low cost Mainline throughput optimization, contract step-ups and volume growth opportunities continue to be available across our entire network of assets. Most of our tolling arrangements across the system, once again, have annual toll escalators. We're laser-focused on our costs and the efficient deployment of our capital dollars.
We're leveraging the scale of the Enbridge supply chain, targeting reductions to our power consumption and costs, and revamping our maintenance management program to reduce downtime and lower program costs. Interestingly, for many of our employees, we're targeting new technologies as well. We have an innovation lab within our company, and we're also partnering with third parties to find ways to further optimize our pipelines, to participate in new in-line inspection research that's targeted at providing better information at lower costs, and developing new approaches to optimize our API 651 tank inspection program. Not only are we confident that we can drive continued growth in the financial performance of the business, we know that doing so further enhances the competitive position of all of our assets. Mainline contracting is something we've been talking about for quite a while now.
If you think back over our history in 1995, we transitioned away from cost to service to a series of incentive tolling arrangements, which made sense to our customers for a number of reasons. They allowed us to generate additional customer service offerings, optimize throughput, all while ensuring the toll stability that our customers desired. This approach to incentive tolling evolved over time to meet the changing needs of our shippers and has worked well for us as well as we've been able to grow and extend this franchise with this strong commercial underpinning. Today's plan to contract the Mainline continues the evolution of the tolling framework to meet the needs of our customers. We heard from many of our shippers that they want access to the same features on the Mainline that are available to them on competing pipelines: capacity certainty, priority access, and toll certainty.
We negotiated extensively with our diverse shipper group for over 18 months to land on services, toll, and other terms, including in our current offer. Given the diversity of interests across that customer base and the need to land on a common contracting approach, the offering meets the overall needs of customers while ensuring that we retain a commercial structure that ensures that we are aligned with their interests. We're confident that it's a good package and the right approach that will be well-supported by our customers. As Al mentioned, an application to the CER is planned to be filed before year-end. That application is going to fully outline the offering and our planned open-season approach, provide evidence as to why it is in the public interest, and highlight the strong support we have from shippers.
Producers, integrated producers, and refiners, many of whom have been long-term shippers on the Mainline and represent a significant portion of the current throughput, support our offering. They have told us that they support Mainline contracting, that they participated in the negotiation of the offering willingly, that they are willing to contract at the tolls that we have negotiated, and that they will support our application in the CER process. In addition to the needs of those customers, we'll have plenty of room for others to participate in what we believe is an excellent offering, and we expect a successful mix of contracts to complement the spot capacity that we're offering of a minimum of 325,000 bpd. The application will clearly demonstrate that our approach is in the public interest of Canadians.
For all producers in the Western Canada Sedimentary Basin, expected long-term refinery demand that will be secured through long-term contracting provides that certainty of demand for Canadian crude that will provide transparency that our producers need to invest with certainty to grow their business. The continued competitiveness of our tolls ensures that crude oil prices will not be negatively impacted and may, in fact, be supported by our approach. For a producer community who elects to contract for Mainline capacity, our approach to the open season has ensured a fair process for everyone to participate and paid particular attention to smaller producers. The extensive market reach of our system at highly competitive tolls drives the best net backs, as illustrated by Vern's chart. We've listened carefully to the producer concerns about take-or-pay contracts and developed the producer requirements contract as an attractive alternative.
As we've evidenced by our 25-year history of successfully developing commercial frameworks that meet the needs of our customers, we believe meeting those needs once again will lead to success for us. This slide outlines at a high level the sequence of steps and timing for the CER to review our application. A robust CER review of our application and intervener perspectives has always been part of the plan. I think you're aware that the approach is not without opposition, but the process at the CER will be to balance the interests of the intervenors and those of that strong level of support that we have for our approach.
Coming back again and talking a bit about optimization of the Mainline continues to be a success story. The plans we outlined last year were to provide up to 100,000 bpd of additional throughput, and those are all now in place as of December 1st. The Line 2 enhancements in Canada are complete, which allows us to fully optimize North Dakota and Alberta barrels at the Cromer point on our Mainline. The new Line 3 in Canada is now in service, which helps us further optimize delivery windows. With these in place, and with some minor capital additions to the system early in the new year, we expect another 50,000 bpd can be achieved on the Mainline in 2020. This is great news for our customers.
Continuing on that good news for our customers, the Express Pipeline is being expanded by 50,000 bpd and will again come into service in Q1 of next year. We continue to evaluate opportunities to extend the reach of the Express system further towards the Cushing and the Gulf, and ultimately hope that that might be an opportunity to link up further with our Seaway system. Combined, by early 2020, we expect throughput from Western Canada to be 200,000 bpd higher than what we were able to do at the start of the fourth quarter of this year. Clearly, these efforts highlight the innovation and focus that results from toll stability that we have under CTS and expect to continue under Mainline contracting.
Each of these initiatives demonstrates that we can deliver on low-cost, high-impact opportunities to grow the business and, very importantly, provide additional pipeline egress for our diverse customer base. Al opened up the day talking a little bit about Line 3, and we're very pleased with the progress that we've seen with yesterday's news. Reminder, Line 3 started and continues to be a critical integrity project that's going to result in a state-of-the-art new pipeline designed to restore the capacity of the line to 760,000 bpd, which is about 370,000 bpd higher than today. The Canadian segment went into service on November 17th, and the interim surcharge with the shippers commenced on December 1st. Al has provided a good update of the regulatory status at the PUC in Minnesota, so I'm not going to repeat that.
I do want to talk about the permitting work we've got with the agencies going on. All that work has continued throughout. The cooperation with the agencies has been excellent in our view. On November 15th, we refiled our 401 water quality certification process or application to the Pollution Control Agency, which allows that process to be ready to align with the PUC's efforts that are picking back up. That new application incorporated amendments that had already been agreed to with the PCA. We will continue to work with the permitting agencies to make sure that as the PUC provides greater clarity on their timelines, that we can get the state permitting aligned with them. This is the same timeline that you would have seen if you saw the presentation with our third quarter call. To arrive at an authorization to construct, we have two concurrent tracks.
At the PUC, as Al said, the public comment period is open. At the conclusion of the comment period, we believe the PUC will determine the adequacy of the revised EIS and reinstate the certificate of need and route permit. All environmental permits, including the 401 water quality certification, will only follow final PUC decisions. That's the sequencing. It's unchanged from what we said in our third quarter call. Until we continue down that path of getting greater clarity from the PUC and the agencies on their process and timeline, we're really not in a position to start speculating about in-service dates or when we think we can be under construction. Let me shift over and talk about our strategy in growing the business. As you can see from the map, we've got a great asset position today with North American reach.
Our integrated system connects the largest supply basins to the best markets, and these assets simply cannot be replicated. They enjoy strong advantages due to their scale, operating flexibility, and market access. We continue to see further opportunity to expand and extend this system across the network. Our assets in the Oil Sands and Bakken areas are competitively positioned. Attractive tolls and market optionality are expected to afford additional optimization opportunity on the Mainline and downstream pipelines. Our joint venture pipelines, Seaway, Gray Oak, and the Bakken Pipeline System, are moving increasing volumes to the U.S. Gulf Coast with attractive expansion options. We continue that focus on extending the last mile access and terminal facilities in the Gulf Coast, which will provide further market access opportunities for our customers.
We see a range of opportunity for growth, both from highly efficient, low-cost projects and from projects representing larger system expansions. Each of these projects will have to meet the rigorous tests of our capital allocation process. Moving on and talking a bit about regional pipelines, I want to take you back to what Vern was talking about and our expectation that as oil sands producers continue to improve their environmental footprint and cost structure, additional opportunity will emerge in the oil sands. Our four major oil pipelines and the Norlite Diluent Pipeline all have upside opportunity for additional throughput. We're well-positioned to capture new investments in any project-specific facilities needed to support expansion of existing operations or the connection of new projects.
In the Bakken, we're continuing to see strong production, and we're conducting an open season to secure additional volumes for transport to the U.S. Gulf Coast on the Bakken Pipeline System. To mix baseball and boxing analogies, these projects represent singles in terms of the size of the capital investment, but are expected to swing well above their weight in terms of financial return. Our outlook for the potential further optimization of the Mainline is pretty much unchanged from last year. The prospects for up to 200,000 bpd of additional Mainline throughput are being pursued through our DRA program, pump optimization, and increased terminal efficiency. The opportunity to reverse Southern Lights and convert it to crude service remains an attractive opportunity versus building new capacity if demand warrants.
The timing of any such plan will be driven by our customers, their views on competing pipeline capacity, and the needed egress from Western Canada. We will continue assessing the opportunity with them in 2020. Either outcome, remaining in condensate service or reversing into crude service, will be a good outcome for us. Overall, our plan's going to be to execute on any of these low-cost projects when the opportunities arise, while shipper demand will drive the targeted timing of any projects that require more significant capital investment. Optimizing the Mainline doesn't really help our customers if we can't get the barrels to market. As we've said for a number of years now, we're in really good shape with the build-out of our market access pipelines.
You might recall that back a number of years ago, we sized our Southern Access pipeline as a 42-inch diameter line to ensure that going forward, we would be in a position to expand and balance the Mainline at Superior. The planned expansion of that line to 1.2 MMbpd is pretty much complete and ready to go when required. That's the starting point. There is further expansion opportunity that's available on that line. To the extent that we have additional volumes on the Mainline upstream of Superior, we can move them through Superior on an expanded Southern Access. Downstream of that again, we're into the Flanagan South and Seaway path and the Southern Access Extension. They both provide attractive expansion opportunities.
Recently, we've begun engaging on some emerging customer interest in the development of a merchant terminal at Flanagan, which would allow for barrels to be staged from the Mainline back into downstream pipelines. The ability to potentially move additional heavy barrels on Flanagan South and the Seaway system is a key link into our U.S. Gulf Coast strategy. Let me move on and talk about that for a minute. The focus of this Gulf Coast strategy is on securing the last-mile connectivity to refiners, storage terminals, and export opportunities while fully developing our heavy and light crude value chains. We've been active for many years now building out our heavy crude value chain from the oil sands through our Mainline, Flanagan South, and the Seaway system to create a path that's unparalleled in the industry.
The next step for us is developing a strategically located terminal position on the Gulf and participating in the development of offshore VLCC loading facilities to capitalize on the fundamentals that Vern discussed. In addition to serving growing export markets, this terminal, along with upstream expansions, will facilitate greater market access to Canadian heavy barrels by U.S. Gulf Coast refiners. For light crude, Seaway and Gray Oak provide opportunity to leverage new business between the Permian and Cushing to the Gulf. The Seaway system, its pipelines, refinery delivery capability, and existing export capability represents a strong foundation from which to leverage continued competitive offerings through capital-efficient investments. It's important both for our heavy and light strategy. What have we been up to? Al referenced it a bit in his messaging. There are a lot of assets out there.
Our team's been very active evaluating a range of opportunities and how they may or may not drive our strategy in the direction that we want to take it. The conclusion that we've landed on right now is that Seaway is the asset that provides us with the best anchor position and the most connected and capital-efficient approach to competitively extending our value chain. With that in mind, we have three things underway. First, Seaway has recently announced an open season for additional light crude service focused initially on a 200,000-barrel-a-day expansion, but if there's more demand, we will consider additional capacity. Part of our Seaway planning is to also always work closely with our partner on the potential to move incremental heavy barrels on our Mainline into the Gulf. Second, a key feature of our plan is to move ahead developing our own terminal at Jones Creek.
We have land that can support up to 15 million barrels of storage, and the exciting part of that is that we connect to the Seaway refinery delivery and distribution network, existing export docks, and future facilities. We anticipate the stage 1 of this terminal may be in service by 2022. Yesterday, we announced a plan with Enterprise Products Partners that will see us jointly develop our deep-water VLCC loading projects in a staged manner. The plan provides us with the option to purchase an ownership interest in Enterprise Products Partners' SPOT project. We will jointly market the full utilization of Enterprise Products Partners' SPOT project first, and Texas COLT will be repositioned to proceed as the export market grows. This joint venture approach makes a lot of sense for us and our partner. It's capital efficient, allows us to stage investments, and can leverage our combined assets upstream.
In combination, these initiatives advance our strategy to enhance and extend our value chain right from Western Canadian to the Gulf. Similar to Bill's story, you can see the emphasis that we're putting on export infrastructure across Enbridge in both crude oil and natural gas. To sum things up, our footprint continues to represent an unparalleled competitive and flexible set of assets that cannot be replicated. Resilient demand pull markets representing some of the world's most complex and competitive refineries support the base business and underpin our growth outlook. We're well-positioned to extend the value chain into the U.S. Gulf Coast to take advantage of growing export demand. Overall, our strategic priorities remain intact. We've demonstrated progress against them in 2019. The base business is performing very well, and we're confident that we can grow, both by improving the base business and through new capital-efficient investment.
That brings a conclusion to my remarks. I think we're going to have Vern come up and join me for the Q&A.
Hi, Rob Catellier, CIBC. With yesterday's business development announcement, it looks like there's a pretty good line of sight to have the tools in place to offer a full path toll all the way from the WCSB, all the way to the Gulf Coast and on to export markets. How do you think that will influence the Mainline recontracting application? Will there be any service offerings or any triggers in there to contemplate that? The second part of the question is, how significant do you think this is in terms of garnering support for the application?
I'll answer the last question first. I think the support for the application that we have today and that we expect that you'll see through the process is unrelated to the announcements from yesterday. Clearly, being able to offer that full value path to shippers is a great opportunity. We already, with our existing arrangements that provide service to the Gulf, have established joint tariffs and joint tolls that allow people to have toll certainty from Hardisty all the way to the Gulf. We expect we'll continue to look to market and offer those types of services. The question around further linking that then into the export terminal is still an open one. I think we still believe there's lots of room for the Canadian heavy to be consumed on the Gulf.
Whether people want to export it or not is really going to probably be targeted at ensuring that they don't create some congestion and price weakness due to the congestion of heavy barrels. We don't see it necessarily being a 365-day option for heavy producers to be exporting, but more likely that they'll participate in providing partial loads to people who might be loading a bunch of light crude.
Thank you.
Andrew Kuske, Credit Suisse. Guy, when you start to think about the market overall, obviously there's a DRU that's going ahead and another DRU that might go ahead.
Yeah.
How do you think of the interplay of DRUs in the market, just the optionality you have on the Mainline, and then what you do with Southern Lights on a longer term basis?
I think starting with the DRUs, we've been engaged in some conversations with some of our own customers about the potential to construct a DRU unit. Clearly, in the scenario that we're in right now, where rail's playing a prominent role in balancing the market, the DRUs make a lot of sense. As we think and don't know all the particulars, but I think when people look at taking term multi-year rail contracts that the province is now trying to shed, it further supports the fact of a DRU investment with some multi-year economics. Having said all of that, we still don't believe that it's a threat to pipeline utilization. One customer in particular that I know we've had discussions with around a DRU unit said, "Look, this is for this period when we need to use rail.
If we can make it work in that period, we're going to do it. Our long-term plan is always to fill every barrel on the Mainline first." In terms of Southern Lights, I think my own take on it right now is that if the producing community views that Line 3, TMX, and Keystone XL are continuing to move ahead, that I think they will probably be quite happy to continue Southern Lights and condensate service. If there's some weakness that emerges in the prospect or the timeline for that competing new pipeline capacity, then they're gonna have to do their economic balance of are we better off importing the condensate in another fashion to access that crude export.
Maybe just to follow up, does the DRU give you further optionality to optimize the system if some volumes go that way? Or is it really just there are incremental volumes in the market to help balance the market?
I think it's the latter.
Yeah. Yep. Oh, sorry.
Yeah. Hey, Guy. Just on Line 3, I know you can't pinpoint an in-service date at this point.
Yep.
Based on the regulatory timeline that you outlined, would you say there's still a chance for a late 2020 in-service date, or are we talking mid-2021 and onward at this point?
You can certainly create planning scenarios that will deliver you a range of outcomes that you're talking about. The way we're executing the balance of the project, being prepared for construction, updating capital costs, all of that, certainly is targeted and planned at being able to be in service as soon as possible. I think for planning purposes, it's hard for us to say with any conviction that we can be there by the end of the year, unless things go absolutely right. We're planning for Line 3 sometime in 2021. That's, again, not a specific date, and Colin can speak more to this when he comes up in his section. We're encouraged that the PUC is moving these three things in parallel.
Until they outline The next few steps will be really important in determining how fast it'll be until we can get under construction.
Maybe just on DAPL, maybe you can just touch on how you and your partners are managing the local opposition and challenges there just to ensure that that expansion comes in service in a timely fashion.
Yeah, I think the best way I would respond to that is to point you to the pace at which these next developments are going. I think what the pace tells you is that our partners are spending a lot more time on the stakeholder side, on the regulatory side. Much like Al said, was necessary part of our business now from an ESG perspective, because the sense we have is the demand's very strong out there. In some ways you could be saying, "Why is it taking so long?" Well, the pace that they're going at, I think is appropriate for the ESG things that they have to deal with. Oh, we're getting awfully lucky in here.
Just on the contracting side of things, you previously mentioned that there's no intention for a parallel process to negotiate with a representative shipper group on some sort of CTS-like extension. Has that changed, in terms of your thinking? On that other front, if you end up with something that's not contracting, is risk mitigation and trying to make sure that you get a much higher volume lock-in, is that a high priority?
Yeah, to go to the first part of your question first, we're not pursuing anything in parallel to our Mainline contracting plan. The largest reason being is that it's in direct response to what the bulk of our largest historical shippers and many new interested shippers want us to do. We're not embarking on a parallel process. Should we come out of the other end of it with either a denial or some conditions from the CER around our proposal, that don't fit that balance equation that we struck of services and tolls and risk, we're going to have to renegotiate something else. Clearly, the volume protection would be a part of that equation, and it would be not unlike what we've done over the last 25 years. Okay, what are the key issues that the customers want?
How can we address them, and how can we give ourselves the financial underpinnings that we need?
Just in terms of some of the projects, you've outlined a number of them that are contingent on Line 3 moving forward. Are there other projects or optimizations that would be contingent on you getting the contracting strategy or some other framework, again, a renegotiation of CTS?
Yeah. Just want to clarify one thing when you use the word contingent. The real value behind Line 3 in terms of what we might be able to do in the future is the flexibility it provides us to optimize our crude slates. It's not like Line 3 itself can suddenly become much greater than the 760 we're talking about, but it gives us a lot more flexibility across the balance of the system. I wanted to make that point. Your second question, when I talked about our growth, I mentioned that the low capital stuff, once it's available and makes sense under existing tolling, we'll probably just go for that. When you get out to thinking about some of these ones that'll be longer duration, Southern Lights expansion as an example, or Southern Lights reversal, it will require regulatory work, it will require capital.
We would want to have a foundation of contractual underpinning on the Mainline before we started embarking on making that kind of investment to add capacity to it.
That's great. Thank you.
Yeah, thanks. Jeremy Rosenfield with Industrial Alliance. Just a couple of questions on SPOT. First, you may have touched on it earlier, or Al may have touched on it at the beginning, just in terms of the risk-reward profile of that investment. And the desire to sort of contract as much as possible of the volumes that would be going out for export. Just as a follow-on on SPOT also, does your involvement with EPD and that project specifically preclude you from potentially sort of securing additional business with other export terminals? Is there any type of exclusivity or?
Non-compete type of stuff?
Right. I think going to the first part of your question, obviously, our partner and ourselves, we're interested in securing as many long-term contracts as we can in support of continued development of the project. From our perspective right now, there's a base load of interest in that project that would allow it to proceed and continue to be developed and would provide returns in the lower end of our expected range that we would then firm up as additional volumes were brought to bear. In terms of the second part of the question, I think, if you think about the way we laid this out, our focus is on Seaway, the terminal, and the offshore. There's so many positive interconnections in that relationship that we have with Enterprise.
Our focus in terms of those offshore VLCCs is going to be centered with Enterprise on SPOT first, and then repositioning Texas COLT.
Jeremy Tonet, JPMorgan. Just want to follow up on the Gulf Coast there. It seems like you've got a really strong platform developing here. Wondering if you could touch on the interest, I guess, maybe to source barrels from the Permian. Any interest in developing the platform in that direction, be it on your own or joint venture or undivided joint interest in other pipes, or any thoughts you could share there?
Yeah. I think we do have interest in the Permian. We do have interest in it from a value chain perspective. I mentioned we've looked at a lot of stuff. I'm sure by now if we really wanted, we could have an interest in something at Corpus Christi. I'm sure if we wanted by now, we could have an interest in pipeline A or B. Potentially in Permian terminal B or C. Without the connections and the value chain to leverage off of, it's just hard to look at them individually and say, "How do you make this more than what you've just bought?" We do have interest, but it'll really be driven by a view as, is there enough of a value chain that we can get the last piece? Is this a value chain opportunity and then we can grow the whole thing?
That work continues.
Great, thanks. Also just wanted to touch base on Line 5, if there was any updates you could provide there as far as how that's developing.
Well, Vern has had the good fortune since he came back into Liquids Pipelines in June of being responsible for operations that included Line 5, so I'm gonna allow him to give the rundown.
Okay, thanks, Guy. On the Straits, obviously, we believe the pipeline, number one, is extremely safe. Number two, Michigan needs the crude oil that Line 5 delivers to provide the refined product for the people of the state. The state of Michigan uses 14 MMbpd of refined product. Line 5 provides 40% of the feedstock for that refined product. If that line went out of service, you'd be short 4 MMbpd of refined product in the state. Obviously, we think it's in the best interest of the state to keep that going. With the recent court decision, the court has affirmed that we do have an agreement with the state to build the tunnel. We're progressing that right now. We plan to file permits with the state agencies very soon in the new year.
Our hope is that we can have the tunnel in service for 2024. We're going to make a safe pipeline even safer, and I think we're well on that path. In the meantime, we've added incremental safety for operations in the Strait. Where we've put in 24/7 monitoring of vessels, where we have infrared capability to make sure that every anchor is up as they pass through the Straits. We have two-way communication going now with the vessels as they go through. When it's possible, we'll have patrol boats on the Straits to help ensure that if there is an incident, that we can quickly respond to these vessels.
Hi, Michael Lapides of Goldman. On some of the growth projects under point 2 and point 3, I just want to make sure I understand some of the detail behind them. The further Mainline enhancement, a large chunk of that is just adding DRA to Line 3 once it gets in service, kind of upsizing it like the law allows you to do. When we're looking at point 3, can you talk about which of those projects depend on Line 3 happening versus could happen independently, whether Line 3 moves forward or not?
I think to go to your first question, we're really looking at three things in terms of the further optimization of the Mainline. One is the continued use of our DRA program. Line 3, the new Line 3, will be part of that puzzle as we sort our way through that. We'll get into, with the new Line 3 and the configuration of this new Mainline network following Line 3. Is there a better way to optimize the pump capability that we have to eke out some additional throughput? The final thing that's very interesting, it comes back to, I mentioned the technology side of things. Through our innovation and technology lab at Enbridge, our team is working with a team of IT specialists in there in terms of mapping and following and optimizing exactly how barrels move in and out of our terminals.
We believe the way we're moving barrels in and out of our terminals is actually impacting our throughput to some negative degree, and we're trying to solve that through an IT solution that would help optimize that. Those are the three areas of it. When it comes to these market access expansions, I think if you assume for a moment that the Mainline contracting proceeds, you're going to have a range of shippers on our system. We expect there's going to be some new shippers, producers who might take capacity. While you might not be expanding the Mainline any further, they may have a desire to access some of these markets downstream of our traditional corridor. In that scenario, you could see maybe not the full-scale expansions of some of these things that you would see, but you would certainly see some of the increments.
I don't think While there's no doubt there's a significant connection, I wouldn't say that the opportunities for the market access do not exist beyond optimizing above Line 3.
One last question.
Yeah. Matt Taylor here from TPH. You mentioned that the toll escalators form a good chunk of the 2% cash flow growth in the segment. We're still about a year or so out from thinking about the five-year FERC oil pipeline index level that resets in 2021. Just curious if you've started to think about how that may incorporate the lower U.S. income tax rates and if you're accounting for that in your long-term growth projections.
I think in terms of our thinking about our own projections, just to deal with that first off. The Lakehead toll itself, when we have so much of our volume flowing on the international joint toll from Canada, is really not having a material effect on the financial outcome of our business. We have barrels coming into the Mainline right now onto the Lakehead system at Clearbrook. It's ± 100,000 bpd that attracts that local toll. On a system where we are moving 2.8, 2.9 MMbpd, only 100 of it will be exposed to that. Having said that, we manage a lot of those tolling-type things with FERC through our participation with the Association of Oil Pipe Lines.
That group collectively has a much greater exposure to some of the issues that you're raising, and we'll be very active with them at the FERC in terms of trying to influence the FERC to make the right decision that reflects the realities of our businesses today in terms of higher costs, mostly. All right. I think we're going to now turn it over to Colin.
Great. Well, good morning, everyone. I'm excited to be here. I see a lot of familiar faces in the crowd from years gone by. Those who I haven't met, I look forward to meeting you. We've got a hardworking investor relations team, and together with them, I hope to get you everything you need to understand our story. The team's already covered a lot, the fundamentals, business strategies, and our opportunity set. I'll try to bring it all together from a financial perspective. For structural thinkers, I'll break my presentation into two parts. The first part will be how we approach financing the business and allocating capital. We'll repeat what Al said, but hopefully, some of the concepts will go a little deeper and reinforce the key points. Then secondly, I'll get into our 2020 guidance package, part of which was captured in our news release.
Before I do get into where we're at, it's instructive to consider again where we've been. We've taken a number of significant actions in the last 2.5 years since the Spectra merger closed in February 2017. We've strengthened and high-graded the portfolio and moved toward a pipeline utility business model. We've sold CAD 8 billion in non-core assets. We've simplified our structure, easier said than done. We've performed well operationally and financially, including realizing all of the synergies we announced on the Spectra transaction. As a result, we're now in a strong financial position, an equity self-funded position, and we turned the DRIP off last year, as you'll recall. In short, we were focused. We accomplished a lot in a short period of time. Where are we going?
We have very clear financial priorities that support the plan and should generate sustainable shareholder returns. Balance sheet strength, low commercial risk, and capital discipline. These are all hallmarks of Enbridge, as you know. Together, they support our unique investor proposition, we don't intend to change course. On a personal note, these priorities are all dear to me. I've been a part of forming these financial policies and executing against them for the last two decades. I'll now walk through each of these principles in a little more detail. Maintaining financial strength and flexibility is the first principle. I think you've heard that today already. In short, following a period of super normal industry growth, we accelerated our de-leveraging. We were always going to de-lever, we accelerated it. How? By selling non-core assets at very good values, secondly, by extracting more EBITDA out of the base business.
The balance sheet is now in great shape, better than ever, actually, as shown here. We're well within our target range of 4.5x to 5x debt to EBITDA. We'll look to exit 2019 in the 4.6 x area. This range is very fitting for Enbridge, given our pipeline utility business model, which I think is a differentiator from many of our peers. Keep in mind, we have an actual utility in the portfolio, and most of our pipeline assets carry utility-like commercial models, which support this capital structure. Furthermore, the range is well within the credit rating agencies' BBB+ target financial parameters. We've chosen the range to fit all of those, I think, sensible parameters. In the middle, we also prudently manage our liquidity.
We maintain approximately CAD 20 billion of committed standby facilities from over 50 global banks, providing enough room, even after draws, to cover one full year of forward capital market activity. This is our plan B, so to speak. I'd like to reinforce at this point that we value all of our capital providers and have had good access to different capital markets over time. For example, over the last four months, Max and team have raised approximately CAD 5 billion of term debt in various markets and from various issuers in our family at industry-low credit spreads, which we're grateful for, and I think reflects the conservative risk profile that we carry. A couple points of color on that CAD 5 billion. The average tenor was about 13 years, including a significant portion of 10 and 30-year maturities. The average weighted coupon was 3.1%.
That's a pre-tax cost of debt, which is attractive. Thanks to many of you in the room for supporting that. This also complements our very short-term and low-cost debt commercial paper, for example, at 2%. The point I'm making here is cost of debt is important to us. We believe a long-term differentiator in our pursuit of industry-low cost of capital. In regard to the second financial priority, there are four key aspects here supporting our low-risk or resilient business model. I'm not going to repeat these. I'm proud of all of them. I think all I would say is that we lead the industry on a number of these measures. When taken together, I think they're uniquely compelling. Further to this point, this slide outlines our financial policies aimed at managing risks and aligning with BBB+ credit profile metrics. Our target ranges are on the right.
They are unchanged from prior years. We're comfortably in range on all the measures at present. Our credit profile, debt to EBITDA and EBITDA debt, remains strong. We maintain ample liquidity. Our 2019 dividend payout is at 65% at present. This will increase to the upper end next year with this morning's dividend announcement. We'll revert back comfortably towards 65% through our plan period. The last metric on the slide there is what we call our cash flow at risk metric. It's like a VaR metric. It reduces our volatility. It currently sits at a very low level. A few comments on this. Given our recent asset sales, we have almost no direct commodity risk in the portfolio. We've hedged approximately two-thirds of our 2020 US dollar foreign exchange exposure.
Of course, 90%+ of our debt is at fixed rate, and much of our forward 2020 planned issuance is also hedged. This is the metric that captures the projected volatility over the next 12 months, and we're well-protected. Again, all these measures taken together provide us strong guardrails to sustain sustainable strength. The last two slides, I think, lead into this slide. Our commercial approach and financial approach create very predictable and reliable results. On the left, you'll see historically that during the worst commodity price downturns, our EBITDA was rock solid and actually consistently grew. In fact, our financial performance is not very commodity sensitive or oil beta sensitive. Rather, this is a picture, I think, of the resiliency we've been discussing today. I think that's borne out on the right as well.
You can see, in two dimensions, the narrowness of our guidance range, secondly, the consistent performance against those ranges. We're not perfect every quarter, but we've hit all 12 of the last year's guidance ranges as shown. Third, let me go into capital allocation in a bit more detail. There are a lot of choices out there and a number of opinions out there. Here's how we think about it and moreover, use it day to day. In the near term, priority 1, as mentioned, will be to ensure we maintain the financial strength and flexibility we've worked so hard to achieve over the last couple of years. To this end, as noted here, we'll also continue to opportunistically sell smaller non-core assets.
Historically, I think Enbridge has been an asset gatherer. Increasingly, we're looking at managing the portfolio, selling opportunistically when compelling values arise, and recycling the capital. Priority 2, we'll return capital to shareholders through the dividend. As mentioned, that is our preferred means to do so. Priority 3, we'll focus on executing, as mentioned, our secured program and improve results with embedded growth drivers that come from low capital intensity. We'll look to grow the business through singles and doubles where capital is efficiently deployed and where we have line of sight to permitting and execution capabilities. I'd like to emphasize that last point. In our longer-term mindset, post Line 3, we'll have greater flexibility, and we'll continue to use this playbook that you see here. We'll also consider other capital allocation choices.
The first question you may have is: how much growth capability or capacity do you have annually while staying in your equity self-funded model? The answer to this question is similar to last year. Over the long term, we expect to have CAD 5 billion-CAD 6 billion of capital investment room per year. Once Line 3 comes online, cash flow from operations will step up nicely, and after dividend and maintenance capital, we'll be generating free cash flow in the area of CAD 3 billion-CAD 4 billion per year. The EBITDA generated by investing this free cash flow creates additional companion capacity, if you like, of CAD 2 billion per year. Taken together, this adds up to CAD 5 billion-CAD 6 billion per year available for deployment. The next question is: where are you going to deploy it?
I think this slide helps demonstrate our preferences in the near term. Our focus is going to be on the left-hand side of this slide, and in fact, it'll be one notch to the left of the slide where we have EBITDA growth with 0x capital intensity. Moving on to the slide, we're going to focus on capital-efficient expansions, rate-based growth, and organic extensions, and potentially, as mentioned, smaller asset purchases. I would consider these to be smaller than, I think, the CAD 3 billion or CAD 5 billion we talked about earlier. CAD 500 million, CAD 1 billion asset purchases that enhance our value chain, as mentioned, or enhance our demand pool resiliency.
To be clear, we have no plans for corporate M&A at this time, and we've talked a bunch about share buybacks already, and they would also come into the radar when we have more flexibility, but would of course, be judged against the capital opportunities at the time, including a variety of factors, including our financial flexibility and the valuation of the Enbridge shares. The last question then is: how do you evaluate and prioritize specific opportunities? There were some questions earlier to this end. I'll give you a short answer and a long answer. In short, we have a very rigorous process. I'm going to spend a couple of minutes walking through this slide to give you the longer answer, so bear with me.
From a financial perspective, which many of us, I think, come from in this room, this process focuses on all the things you would think are intuitive and disciplined. We also overlay it with a strong dose of the long-term fundamentals, which I think you've heard a lot of today, how it will or won't advance our strategy, and whether a particular investment will or won't have follow-on optional growth opportunities. These are all factors we consider. Starting on the left, our business commercial leaders cultivate and identify discrete investment opportunities, as you'd imagine. We encourage them, of course, to fill up the hopper with lots of opportunities, because in our experience, it takes a lot of opportunities to find the gems. As the industry leader, you can expect we get a phone call or see most opportunities to this end.
We have well-developed investment screens to filter opportunities. We've mentioned some here already, but there were some questions earlier around permitting and executability, ESG dimensions. We look at various parts of that and price it into our hurdle rate. To get to the next stage, as I go through the whole slide, all of these criteria need to be met. All. The next stage after this involves a detailed assessment where we identify and price each of these risk premia. It's iterative with considerable internal devil's advocacy, as you would expect. I think as mentioned, but I'll say it again, each project has its own specific hurdle rate that's built up from a base return with specific risk premia on top of it. In other words, we're not using a generic Enbridge observed or Enbridge generic return. It's risk-tailored.
For example, if a project has higher risk, like CapEx, for example, we'll add a risk premia for that. If it's got a jurisdiction that we're mindful of could be challenging, we'll add a risk premia for that, schedule, et cetera. If you end up with too many risk premia, you step back from it and go, "I don't think this makes sense." You should have very few risk premia. That's the utility pipeline model we're after. On top of that, on top of the red line here, we also target typically an additional premium to reflect the fact that we want to beat the hurdle rate and add economic value, not just meet it. The next stage, even if a project is determined to be acceptable, we aren't done yet. We then compare it to alternative uses for that capital.
Systematically, our templated outputs internally require this evaluation. It allows us to be disciplined about how and when we're investing scarce capital. All told, we've used this process over many years. I think Jonathan's had a piece in cultivating this, Vern, Al, others. I think we're all pretty proud of its maturity and track record. We've looked at hundreds of projects, and we discard more than we approve, obviously. Can be frustrating, but that's the nature of the beast. It's tried and true for us, and we don't intend to change course here as we target the lowest risk business in the sector. That's a little deeper dive on capital allocation and investment review. I'm now going to move to the second half of my presentation, which will be on the financial outlook and 2020 guidance.
High level, before I do, there are a few base assumptions that underlie the 2020 look. We assume optimization initiatives that you've heard all about today. Those are embedded in the plan. Second, from a capital standpoint, we're only including secured projects. We've excluded projects yet to be sanctioned. We may have financial capacity for more in this regard, which I'll demonstrate shortly. For 2020, there were some questions on this earlier. For 2020, we're assuming full Line 3 U.S. spend in calendar 2020 and without any EBITDA from it. We've got substantially all the capital in 2020, but no EBITDA coming from it. Although we hope to have it in service as soon as possible. From a funding perspective, all of that capital will be funded from cash from operations and new term debt issuances respecting our credit metrics.
In other words, there's no common equity requirement. We'll begin with the commercially secured growth inventory, which are at, of course, various stages of execution. There's lots been said about the midstream space having trouble getting projects built. I think we are getting projects done reasonably. In 2019, for example, we brought on seven major projects for a total of CAD 9 billion. Our three-year tally now is CAD 20 billion, 25 major projects. We are getting them done. All of these projects on this page and the ones I've just mentioned that have been completed all fit the utility pipeline model. They have strong commercial constructs, strong counterparties. There were questions on that earlier, and should contribute to EBITDA and cash flow for decades. We now have CAD 11 billion remaining of secured projects shown here. Some key observations would include the diversity across liquids, gas, utility, and power.
The most important project is Line 3 U.S. We've also included the prompt year's worth of utility customer growth capital and gas transmission modernization capital that Bill spoke of here. Of the CAD 11 billion, we've spent CAD 3 billion already, leaving CAD 8 billion to go. When they come into service, these projects should add considerable EBITDA, shown on the right-hand side, of at least CAD 2 billion per year. That's going to add the financial flexibility we've been talking about. What does this mean for 2020 CapEx and funding discretely? Our 2020 CapEx outlook, shown here in blue, is very manageable. I should clarify again, this is secured and maintenance capital only. There are no unsanctioned projects here.
The CAD 5.5 billion actually comes in lower than the last number of years and substantially lower than some of our big CapEx years that were, I remember them being as high as CAD 12 billion as shown there. Substantially all of the remaining Line 3 U.S. spend is provided for in this value. Basically, CAD 2 billion on the CAD 5.5 is Line 3 U.S. The rest of the enterprise spend relates to previously announced secured growth projects, as shown on the prior slide. We've got an arrow decline here, illustrating that 2021 and 2022 secured CapEx should be lower, but of course could be increased with further project procurements, potentially including yesterday's announcements. I think some of that will take time to get into service. Our funding plan for 2020 on the right is straightforward.
Living within our self-equity funded model, we'll fund this CapEx program from operating cash flows and new term debt as mentioned. For the debt capital market crowd, we intend to issue debt from various issuers in the family. That's now a streamlined family with basically six active debt issuers remaining, including our regulated subs. Tenors diversifying our access and optimizing our cost of debt. Back to the balance sheet. You've had a preview of this earlier. Let's zoom in quickly. Firstly, I think we've talked about this. We see 2020 levels roughly in line with 2019, up only 0.1 x to 4.7x. Again, still within our target range. Mostly as a result of the Line 3 U.S. spend.
As secured project cash flows come online the next couple of years, you can see in green the headroom that will be created. This will provide us flexibility to either add new growth projects or compare that to other capital allocation options. Either has the potential to boost the 5.7x in the near term or extend that 5.7x beyond. Okay, on to more specific guidance. We'll run through EBITDA and DCF. In our news release, this captures the EBITDA guidance for the year, which is growing 5% over 2019 to CAD 13.7 billion in 2020. This is driven in part by the annualization of contributions from assets coming into service in 2019 and some again in 2020. I think this is an important point. It's also driven by the strength in our base business in almost all of our segments.
The strength comes from higher tolls, higher volumes, and cost containment. Optimizations in a nutshell. Specifically, I'll walk through each of these, Liquids Pipelines, we see an uptick over 2019 of approximately CAD 200 million from EBITDA from the Line 3 Canada surcharge in effect last week. We see volume growth from creative system optimizations of the 100,000 bpd secured in 2019. The additional 50,000 bpd Guy mentioned today. The Express capacity and Gray Oak, which is all now in service. A number of positives in Liquids Pipelines. No contribution from Line 3 U.S. in 2020. In Gas Transmission, we should see uplift from our annualization of 2019 project ISDs like Stratton Ridge and Atlantic Bridge. Favorable impacts from the Texas Eastern rate case, as Bill noted. This is offset partially by the impact of asset sales, which we carried through 2019.
Gas Distribution benefits from a number of small pluses, price inflators in Cynthia's business, new customers, cost synergies, and rate-based growth through the ICM mechanism. That is being offset by a projection of normal weather, which we typically budget for. Power should benefit from the German wind farm placed into service this month, and to a lesser extent, better availability on our North American wind farms. Bridging to distributable cash flow. The first item, CAD 600 million. This is cash distributions in excess of earnings, in excess of basically our equity pickups, which are, of course, burdened by book depreciation. I think this number is being strong and growing. Some of the bigger joint venture investments we have in the portfolio contributive of this would include Gray Oak, which is new, Dakota Access, DCP, Alliance, NEXUS, Sabal Trail, and Gulfstream.
A number of investments contributing to this strength. Maintenance capital is looking to be flat to slightly down from 2019 at about CAD 1 billion, that's rounded, reflecting primarily the avoidance of maintenance capital on our G&P assets to be sold late in 2019. Current taxes are up slightly from 2019 on improved business performance, basically the higher EBITDA that you saw earlier. Financing costs are looking to be CAD 200 million higher than 2019 from a combination of two things. One, the debt-funded CapEx growth we've talked about. Secondly, we're now recording full interest expense on Line 3 Canada. Remember, that's a CAD 5 billion project, and last year we capitalized the interest. In 2019, we'll be expensing it. At the bottom are the midpoint of our guidance range is CAD 4.65 per share.
We've got a relatively narrow and symmetric 3% guidance range around it, reflecting, I think, the confidence in the business and the predictability of the business model shown. Lots of line-by-line numbers there. Don't want to get lost in them, but a step back from them. I think the strength in the base business is the main point I'd like to draw out from this. It should show through again in 2020. Beyond 2020, we see our longer-term growth rate in the 5%-7% area as mentioned. 1%-2% of this growth comes from the optimizations and embedded growth within our core businesses. We also believe we have excellent line of sight to 4%-5% growth from organic projects, including ratable rate base growth, as mentioned, I think, both in Bill's section and Cynthia's.
Longer term, we see these same individual contributors contributing to an aggregate outcome in about the same quantums. We're working on project securements today to fill that up. We will increase our annualized dividend by 9.8%, effective with our March 1, 2020 payment. This marks our 25th consecutive annual increase. We're proud of the ability to do this, and it's consistent with our investor proposition, which is to continually increase income for our shareholders. The 2020 increase reflects a number of things, most importantly, our multi-year outlook for the business and our confidence in Line 3, and as well, the base business strength, which I just emphasized. Importantly, we also view the performance as highly sustainable, and the low-risk business also gives us confidence in making this dividend increase.
We are mindful that in our industry, a significant portion of long-term shareholder return comes in the form of the dividend. We've done our own back-engineering on our TSR, two-thirds of our total shareholder return has come from our dividends over the last quarter-century. We're mindful of that. We believe a long-term payout level of cash flow in the area of 65% is appropriate, again, given our low-risk business and also the balance it affords between returning capital to shareholders and reinvesting it. Going forward, we expect dividend growth to roughly follow in pace with DCF per share growth of the 5%-7%, roughly, while also keeping an eye on our 65% long-term payout target.
In conclusion, I think the two main messages, if you step back from all of this, are that we're in great financial position today, and that we've got a self-funded plan to responsibly support the 5%-7% going forward. Happy to take any residual questions you may have, recognizing lunch is coming. Linda.
I hate to be standing in front of lunch, some quick cleanup questions. It's a very helpful update. I'm wondering if you could help us understand the long-term run rate for maintenance activity, some inflationary pressures. Your business is growing. There's probably some inefficiencies in scale economies that we can think of. If you can help us first with that long-term assumption, and then secondly, cash taxes.
I know it's hard for you guys to predict. It's even harder for us. Can you talk about how that might be trending beyond 2020?
Sure. For maintenance capital, I think all things equal, our maintenance capital budget has been growing every year. On the surface, it looks flat. We've been selling assets that carry actually quite high maintenance capital. That's what's keeping it roughly flat in that CAD 1 billion area, but it is otherwise kept naturally creeping up. I think the teams talked about technology and other efficiencies to keep that unit of work cost down when doing work. We've done a lot of work on our systems over the years, front-ending a lot of that work, especially in the Liquids Pipelines system. I think over the next few years, I'd expect something similar, maybe slowly creeping up on maintenance capital. By the way, I would venture half or slightly more than half of our maintenance capital is recoverable through various rate mechanisms. Something to keep in mind. On cash taxes.
Our cash taxes are actually relatively resilient and have been. I think we've had some benefits from the SEP buy-ins, which has helped keep that relatively low. You should probably think about the CAD 450 million per year in cash taxes as roughly sustaining through our three-year plan period. That's how far we measure it out. Is that helpful? Thanks. Andrew?
Andrew Kuske, Credit Suisse. Colin, just run with the assumption that you get the Mainline contracted. Does that allow you to take on more leverage in the future or on that specific asset base or just issue debt at tighter spreads?
I hope we can issue debt even better than we can. I think it creates a bunch of flexibility in the total which I'm excited about. I think our credit spreads are at industry lows. I think we'd like to be the best credit in the space, and I think we're well on our way.
One follow-up question. With the flexibility that you've got on the balance sheet, do you foresee the possibility of getting back to earnings guidance in the future? As we look way back, there was earnings guidance and dividend guidance in the past. Now it's all DCF guidance over the last few years.
Oh, in terms of which metrics we guide to?
Yeah, that's a good question. We used to have earnings per share. I think reflecting probably more of the midstream trend over the last four or five years, we've moved to DCF. We've kept adjusted EBITDA. It's a bit tricky to keep three or four metrics public, so we'll have to choose the most relevant ones. I think right now, and we keep an eye on earnings per share. We certainly reported earnings per share. I think from a forward planning perspective, and certainly a dividend-paying capacity perspective, we view a cash flow metric as probably the most relevant. We'll keep an eye on EPS as well.
Okay.
Hi, it's Ben Pham. BMO Capital Markets. A couple questions on opportunistic monetizations. Could you remind us non-core, what's in that bucket right now? The second question, would you ever contemplate any asset sales or maybe core assets where you just see this massive arbitrage where maybe you sell some minority interests, charge a management fee, and surface some value that way?
Thanks, Ben. On the first question, opportunistic, smaller, non-core asset sales. I think the first point is most of the portfolio is core at this point. I think the only asset that's non-core is probably DCP. We've talked lots about that. We're comfortable with its improving fee-for-service model. We do have around the edges, though, I would say, a few assets that are CAD 100 million of EV, CAD 300 million, CAD 400 million that are attractive to many. We probably have inbounds on every asset, to be honest. Some of those smaller ones that are around the edges, we'll certainly consider looking at those. In aggregate, they may total CAD 1 billion. We'll look to recycle capital there where it makes sense. On the second question around arbitraging the public-private arb. The question was asked in a similar, maybe slightly different way earlier.
I share the view that there is some opportunity there. There's a number of factors to consider around complexity, structural subordination, ongoing governance of the asset. We have looked at those historically, and we continue to do so periodically. I think the key there will be how attractive the arbitrage could be. How attractive could the valuation be?
Hey, Colin. Just to follow on that topic. You did mention historically, the company's been a little bit more of an asset gatherer and that you're increasingly looking at optimizing capital. But given the recent actions were distinctly tied to funding and reducing leverage, is this really, as we go forward, just cleaning up the portfolio, those kind of small things up to CAD 1 billion? Or would you be looking at something much more meaningful given the opportunities absolutely seem to be there to monetize at much higher values than where you're trading?
You didn't like the answer I gave to Ben's question? Well, I think it can be attractive. It can be attractive. Certainly, our assets could fetch excellent value. Once again, it's all those factors together and the view needs to be worth the climb, I think is the bottom line. The valuation needs to be compelling. We are open-minded to it. I think it's fair to say we're not scared of complexity, but we're not going to go looking for it, if you know what I mean.
Would you undertake a significant monetization in the absence of a need for that capital?
The use of proceeds is important, I think. If the price was ridiculous, I think that would be very tempting.
Do you want to say what ridiculous might mean to you?
You can use your own imagination. I think you've seen a lot of comps out there.
Thanks, Colin.
Okay. Dean?
Hi, Colin. It's Dean Highmoor from Mackenzie. I just have a question on your payout ratio. You said that cash flow is a more relevant metric for you than earnings. How did you come to the 65% level on payout, and why is it not 55% or 75%?
Yeah, good question, Dean. I think we've carried a relatively healthy payout ratio for some time. I think we've had 65% for a number of years here. There's a variety of factors. We'll start with what everybody else is doing, midstream peers, even utility peers. If you look at utilities, I think on a cash flow basis, they're probably in the 60%-70% range as well. We think we're utility-like. Certainly, the predictability of our cash flows give us a lot of confidence in sustaining the dividend. Could it be higher? I don't know. We still have lots of reinvestment opportunities to put it into. From your question, I'm not sure which direction you're leaning to, I think it strikes the right balance for us.
Okay, we wouldn't see any movement of that payout target one way or the other then, based on that comment.
Agreed. Yeah. We think 65% is about right. When Line 3 comes in, I think that'll allow us some cash flow payout headroom to potentially inch it back to 65% or towards 65%. I don't see a step change either direction in the near term.
Okay. Thank you.
We have time for one last question.
Hey, Robert Hope, Scotiabank.
Rob.
Assuming Line 3 enters service and you dip below that 4.5 x debt to EBITDA, how do you weigh remaining below 4.5 x debt to EBITDA versus keeping your powder to dry versus buying back shares at where your valuation is?
Yeah, that's going to be an it depends answer right? On all the factors, right? What opportunities do we have in front of us? Where the share price is at, what other strategic ambitions we have. Certainly, we want to maintain some financial flexibility, always. That's just a tenet of our mindset. I'm hesitant to say, if we have a little bit of financial capacity, we're going to go and do a CAD 1 billion buyback just to make it perfect from an equity shareholder perspective. It's got to be sustainable, I'd always like to keep some buffer on the balance sheet. Now, below 4.5x , we've got all kinds of options at that point, right?
I guess as a follow-up, when you're looking at that 4.5x-5x range, it would seem that the target's more towards that 4.5x.
No, it's a range for a reason. It'll ebb and flow within it. Hopefully, you're picking up a vibe of conservatism generally, but will there be opportunities to secure that will take us towards the top? I used to say comfortably below five, probably too many words, but I would say for practical planning purposes in our own minds, 4.8 is probably the warning track, personally. Yeah. All right. I think that's it. Off to Al.
Okay.
Thanks, Colin. Well, if you're ever wondering if we had a gatekeeper in the company around the investment review process, I think you just heard from him. Cynthia, Bill, and Guy and Matthew on the power side will certainly vouch for that. There's a process, and as you can see, it's fairly lengthy and disciplined. I'll just say a few things before we wrap up here. Hopefully, as I said at the very beginning, you come away with these three messages: resilience, discipline, and growth. We could say it at the corporate level, and I could talk about it, but I think that you got that feeling with all of the three big core businesses. One theme I hope you took away as well was we've adapted to this environment. On the growth side, it's not just about growth.
We're focused on expansion, extension, and optimizing of the existing base. That'll be very capital efficient. On capital allocation. Number one, preserve financial flexibility. I think you got that message again from the CFO. Return capital in a ratable way, in a sustainable way, and then organic growth to extend that growth rate well into the future. We had a lot of discussion today, and I'm glad we got a number of questions on ESG. We do really feel this is a differentiator in our businesses. Now, we've had a lot of challenges and a lot of headlines in the industry and ourselves as well, but we are getting things done. It's because of one reason. We need the skill set that really is able to manage in this kind of environment that we're in.
Yes, there's been some headlines this year and last year, but indigenous successes have been prominent too, which you don't hear as much about. You heard around Line 3, around that opportunity. That was a fantastic outcome. Emissions reductions and setting targets, which we're doing. You heard Bill's comments that the FERC made about construction on NEXUS. These people don't give away those comments gratuitously. Then he added, of course, his butterflies, which I thought was the highlight of his presentation. Of course, renewable natural gas and renewables generally. We think are at the forefront on ESG. On the U.S. Gulf Coast strategy, I think this really exemplified a lot of what we said today about capital efficiency. It provides a growth opportunity, it's doing so in a very capital efficient way.
It's using a great partner with us, where we both bring something to the table. It's really establishing a value chain. If you look at that liquids map and what it was five, six, seven years ago, there was nothing on the Gulf Coast. Now I think we've got a very credible strategy to really capitalize on exports. Exports was a theme, and not just on the liquids side, but Bill talked about it a lot on his business, and lots of good things going on on LNG exports on the pipe side for us. I should just mention, back on the liquids export strategy, one of the architects of that is Phil Anderson. Phil, just stand up for a moment, please. Phil is one of our imports.
He saw the light and came to Enbridge, I don't know, about a couple or one year ago, I guess, somewhere like that. He's running the Gulf Coast strategy out of Houston. Line 3, I think we've talked about that enough, but I think the EIS work now being concluded and reestablished and reaffirmed, that's positive. The fact that the PUC will handle the comment process related to the EIS, the certificate of need, and the routing permit, I think is a good sign. In terms of growth, there's really two things, two periods of time. In the next three years, we've got very visible growth, visibility to the 5%- 7% on growth from optimizing the base and the secured capital projects. Beyond that, it becomes optimizing the base and then newly secured projects.
You saw a pretty darn good inventory of all of those that we're working on. That was it for today. As you saw, hopefully we conveyed the strength of this team. I'm very proud of the group. They're doing a fantastic job getting through a very challenging environment. Lastly, we want to give thanks to John Gould, who's not here today. He's back in Calgary holding down the fort. John looked after investor relations for a number of years, as you know, and we want to recognize him for his good work. IR jobs can be challenging when prices are going the wrong way, and you don't get much credit when they're going up. Great job by Jonathan Gould and providing transparency, further transparency to our opportunity set to all of you. Thank you for joining us, and we look forward to seeing you over lunch.
Thank you.