All right. Come on in, everyone. We'll get started. Well, that went quiet in a hurry. Good morning, everyone. My name is Jonathan Gould, and I'm the Director of Investor Relations here at Enbridge. It's my pleasure to welcome everyone here in New York, and for those of you listening online, to our 2018 Enbridge Day Investor Conference. A lot of great updates for you today. Before we get right into it, maybe a couple of quick housekeeping notes. As is customary at Enbridge, we'll begin our meeting with a brief safety moment. In the event of a fire, you're going to hear an alarm sound on the system. If necessary to evacuate, there will be an announcement to proceed to the emergency exits.
We've got two on this floor, one in the corner up front here, and the other one at the far end of the hallway. Front end of the room, you're going that way, back end of the room in an orderly manner down to the street level, and then we'll regroup at a muster point, say, corner of 55th and Fifth. In terms of the agenda or what we have coming down the pipe for today, as we like to say, you'll hear from several members of our executive team. Format will be a presentation followed by a Q&A. We'll have a microphone that'll be circulating for Q&A. For the benefit of those who are listening online, if you could please use that and introduce yourself prior to asking the question. Lots to get through. We're going to try to stick to schedule.
We do have a break planned for mid-morning. We'll see how we're doing for time. In any event, we'll look to wrap up the session by 12:30 P.M. Once we're done, lunch will be available for those who like to stay, and please do. Our executive team will be there and available to chat. Of course, the investor relations team will be accessible following the event and any time afterwards for any follow-ups that you might have. Finally, as you can almost read on the slide here, the legal team would like us to remind you that our comments today may refer to forward-looking information or non-GAAP measures. With that taken care of, I'll, without further ado, hand it over to our President and CEO, Al Monaco.
Thanks, John. By the way, there are other members of the management team here today. Please, at the break or during lunch, please take time to chat with them. Good morning. We're very glad to be here today to share our story. It's been a very busy and productive year at our company. Operationally, we're firing on all cylinders, as they say. Our pipes are running full. We're generating record results. We've delivered on the priorities that we laid out last year and then some. We sold assets. We'll exit the year with strong balance sheet. We're simplifying our structure. We like our position today. We're focused on extending the track record.
Today, I'm going to focus on three things: the opportunities that drive our core businesses, our growing free cash flow position and our approach to capital allocation going forward, and then how the opportunities in free cash translate to our financial outlook through 2020 and then beyond. Let me first cover the highlights of this morning's news release in case you missed that. Our 2018 outlook is the same. We expect to come in at the upper end of our guidance range in that CAD 4.15 to CAD 4.45 DCF per share. We're establishing 2019 guidance today at CAD 4.30 to CAD 4.60 a share, so the midpoint is CAD 4.45. We're confirming the 3-year guidance, that is the 2018 to 2020 period, at 10% DCF per share CAGR, which translates to CAD 5 DCF per share in 2020. As you saw, we increased our dividend by 10% to CAD 2.95 per share.
That is now fully a cash dividend. We sanctioned newly secured projects totaling CAD 1.8 billion. We'll talk about those more later. We're positioning the liquids mainline for continued success with a long-term contracting proposal that will give customers toll and market certainty. Guy will take you through that and our latest efforts on throughput optimization actions. Post-2020, we expect to achieve annual DCF per share growth of between 5%-7%. Importantly, that level of growth would be funded entirely within our expected free cash flow, that is net of dividends and maintenance capital spending. Today is about the future, but it's important to recap for a moment our significant transformation over a very short period of time. Just two years ago, back in 2016, we were a world-class, but we'd have to say Canadian-focused business on liquids pipelines.
We'd long since concluded, though, that we needed to materially expand our natural gas footprint, and we did that essentially in one fell swoop by acquiring Spectra. It's even clearer today that accelerating our gas strategy and expanding that U.S. footprint was the right thing to do at the right time. You could say we've emerged as the bellwether pipeline and utility company in North America with CAD 12.5 billion in EBITDA and CAD 15 billion in 2020. We move about a quarter of crude oil and 22% of natural gas in North America, and utility gas distribution volumes are about 2 Bcf a day. We supply about a third of all U.S. oil imports. We're not dependent on supply basins, but rather driven by the strongest demand pull markets and customers. You'll hear that term a lot today, demand pull. Our business risk is low.
There's a lot of license taken in our sector these days in using this low-risk moniker, but here's what it means to us and why we think we're unique. 98% of our EBITDA is driven by regulated constructs or long-term contracts. The sale of the G&P business earlier this year means we no longer have significant exposure to commodity prices or drilling risk. We tightly manage market price exposure like interest rates and FX, and we have BBB high credit metrics. All of this gives us steady and predictable cash flow, which is the way we like it. As you can see during the two most recent challenging times in the energy space, this is the chart on the right now, we've delivered strong, steady growth. We don't believe there's a lower risk business in our sector.
At last year's Enbridge Day, we laid out our post-Spectra priorities. Since then, I think you'd have to say we've attacked those priorities hard. We've delivered cash flow and dividend growth through strong operations and bringing CAD 7+ billion of projects into service. We received Minnesota Line 3 approval and progressed construction in Canada. We sold CAD 7.8 billion of non-core assets, more than double the target at excellent valuations. We accelerated de-leveraging to 4.7x debt to EBITDA in Q3. That's ahead of schedule and well below our year-end target, which was originally 5x. With the added flexibility, we turned off the DRIP. I have to tell you, that was a great outcome for us. We moved very quickly to streamline in three areas. We're on track to achieve the CAD 540 million synergy target from the Spectra acquisition. We struck deals to buy in our sponsored vehicles.
ENF is complete. SEP will be complete next week. The EEP EEQ votes will take place on December 17. We moved swiftly to merge our two Ontario utilities right after we received regulatory approval. We've made great headway, we believe so far, as you saw in the release, to backfill secure growth beyond 2020. Finally, we held last year's guidance at 10% cash flow and dividend growth through 2020, despite the dilutive effects of asset sales and the sponsored vehicle buy-ins. The big picture takeaway from these check marks that you see here is our shareholders get the strong financial outlook and dividend growth that we talked about last year, with even a lower risk profile, a stronger balance sheet, and a simpler structure. Here's where we sit today. The business and operations are running extremely well. Our liquids pipelines are full.
We're optimizing capacity there. In fact, we had record throughput in November of 2.8 million barrels a day. Great job by the team. Our mainline customers on that system are in very strong financial position. Many are integrated and pure-play refiners. We're also seeing great demand on the gas transmission system. In fact, the November 1 renewal rates averaged 98%, another great outcome. Gas pipeline customers are also very strong, primarily very large utilities. Some investors ask us about the longevity of our energy infrastructure in a lower carbon world. Let me spend a minute on this because I think it's a great question. However, as you'll see here, there's no disagreement that global demand for oil and gas is going to continue to increase. That's because population growth, greater urbanization, and improved living standards are a virtual certainty. Let me just give you a couple of numbers.
Population is going to grow from 7.6 billion to 9.8 billion by 2050. On urbanization, we're moving from 55%-68% of populations based in urban areas by the same timeframe. In terms of improved living standards, we'll see an increase from 3 billion to 5 billion people in the economic middle class. That means more businesses, vehicles, air conditioning, appliances, e-devices. All of that drives more energy requirements. The fact is, we're going to need all sources of energy to meet global demand. You probably saw the IEA put out its world energy outlook. Under what they call the new policy scenario, while renewables grow, global oil demand will still grow by 10% by 2040. LNG demand will double by 2030. Gas, of course, is the key ultimately to lowering overall emissions globally. The North American story is a little bit different.
Demand is flattening out while production is growing rapidly. This is a big opportunity. Abundant low-cost resources give us, on this continent, a competitive advantage in energy to capture an increased share of the global market for energy. Energy infrastructure then is not just sustainable in our view, it's going to have to grow. You can see that in the current price dislocations across the globe, and particularly here in North America. What that tells us is we're going to need a lot more infrastructure. Finally, let's not forget about something that matters to all of us. Around the world, low-cost affordable energy lifts people from poverty, makes lives better, and generates economic value. You're seeing that economic engine working here in the U.S. The fact is, what we do every day is critical to economic growth and prosperity.
Enbridge as a company is thriving today, and we will in the future because the assets that we operate are needed, and our footprint is positioned to capitalize on the fundamentals that you're seeing on this chart. Let me just outline our corporate and business unit priorities. The key priorities really haven't changed. Delivering cash flow and dividend growth, maintaining a pure pipeline utility model, a strong investment-grade balance sheet, streamlining the business, and extending growth beyond 2020. Going forward, though, we're increasing our emphasis on three areas: enhancing returns in our core business to maximize their value, expanding and extending the footprint, particularly to energy export infrastructure, and then rigorous capital allocation within a growing base of available free cash flow. We'll show you this in a few moments. Those are the priorities.
Let me summarize how they play out in each of our businesses at a high level, and then our leaders will carry on after that. Our gas network connects gas supply to North America's largest, most robust demand pull centers. Examples: Chicago, New York, Boston, Vancouver, Toronto, Seattle. Excluding new growth, we believe this business can grow at 1%-2% through system modernization and rate adjustments that reflect the current capital base and costs, since we haven't filed for rates in many years. As for other growth, we couldn't be more pleased with the opportunity set that this network here provides, and we're literally seeing expansion in all the areas of our system. We're now completing about CAD 8 billion of secured growth through the system. Bill will show how our system sits on top of where the biggest areas of growth are in gas demand going forward.
You'll see that our Texas Eastern system serves growing industrial and power generation load and the U.S. Northeast market, which is desperate for new gas supply. You just have to look at the spikes in gas prices and electricity prices in the New England area to see that, and ultimately, this will mean more pipe. Texas Eastern also feeds the U.S. Gulf Coast pet chem market, LNG, and Mexican demand. Significant export-driven growth on the system. Again, Bill will lay out how we're playing in that space. In the Southeast, we're well-positioned for continued gas-fired generation load. In Western Canada, we're expanding to meet demand. Again, Bill will talk about an interesting story developing there. Overall, post-2020, we've seen an opportunity set here that should conservatively result in CAD 2 billion-CAD 3 billion a year of organic growth.
Continuing on with the gas story, our gas distribution business, the largest in North America. I'd have to say, this is our hidden gem. We love this business because it provides low-risk growth, strong cash flows, year in and year out. We're combining Enbridge Gas with Union Gas to form the industry leader in North America. The utility sits on top of a rapidly growing population center and the Dawn-Parkway, which makes it the fastest-growing franchise in North America. Our new incentive framework means that we'll have rate clarity and no rebasing for five years. Under this model, we believe we can generate 1%-2% growth through synergy capture and embedded rate escalation. In terms of growth capital, we have roughly CAD 2 billion in projects underway right now that Cynthia and her team are completing.
Post-2020, we see about CAD 1 billion a year in new capital expenditures delivering growth. Customer additions, about 50,000 a year. Extensions of our system to new communities. Further expansion of the Dawn-Parkway corridor, as you'll hear, this is sort of the gem within the gem. Other opportunities that are being worked on now on compressed natural gas and renewable natural gas. All of that will be covered in more detail by Cynthia. Last but certainly not least, our liquids pipelines business. This business has exactly the same demand pull attributes as gas transmission, except in this case, the pull part is refinery demand, which has never been stronger. Its competitiveness, the liquids pipelines business, is unparalleled in the world because it feeds North America's two largest and most globally competitive refining centers in the Midwest and the U.S. Gulf Coast.
We've proven that we can leverage the scale and reach of this system to capture low-cost and low capital-intensive opportunities to grow the business. We're making very good progress here on our secured program. It's about CAD 11 billion now, including Line 3. The strong fundamentals here and the capacity shortages that you all know about set up liquids nicely for the next leg of growth in the business. In fact, we think a window has opened here to extend the opportunity for our customers and shareholders. Over the last four years, we've added almost 500,000 barrels a day, very quietly, of capacity through expansions and low-cost optimization initiatives. Line 3 will add 370,000 barrels per day, the additional mainline optimizations that are there total about 450,000 a day, and they are gaining momentum as we speak.
What you'll hear from Guy today are two important parts of the liquids pipeline strategy that we are excited about. First, our new long-term mainline priority access contracting proposal. Second, over the past few months, the team has been working hard to find new ideas to address capacity constraints, and we're pleased to say that we found a couple more. Over the last couple of years, we've talked about our goal to build a stronger position in the U.S. Gulf. With the Gray Oak Pipeline that we announced today, our Midcontinent systems and our Seaway assets and other assets in the region really boost our Gulf Coast strategy, and you can see how it's going to take shape. Post-2020, our liquids opportunity set should result, on average, CAD 2 billion of organic growth projects.
Remember, there's a lot of other embedded growth in this business that doesn't come with capital. To the second area of emphasis, our self-funding model and capital allocation, which is an extremely important area for us going forward. As you saw, we've got a bevy of projects just in that quick summary there in execution and in development. I can assure you, we won't be issuing equity to fund those. The suspension of our DRIP in Q3 was the last step in getting to fully self-funding mode. It's been some time since we've been able to fund our investments through internal cash flow. Let me provide some context on how we got here, which is what this chart is about. Over the last several years, external equity made sense for us. Why is that?
First, we had the largest, most attractive organic capital program in the industry. We took those opportunities off the table. We brought in over CAD 50 billion of projects into service since 2009. Those projects bolstered our strategic foothold. They're highly accretive. Because of those investments, DCF per share is going to hit a record, and it'll grow by another 10% through 2020. Second, we took bold action to capitalize on what we feel is a once-in-a-lifetime opportunity to reposition and diversify the company to natural gas by acquiring Spectra. That positioned us for the future. Third, the sponsored vehicle buy-ins eliminate complexity. They reduce regulatory risk. We retain more cash in the business, and they extend our current tax position. The buy-ins also allow us to consolidate highly strategic assets we already own the majority of.
Critical to these actions is that they've added value, as you can see by the accretion that we're showing at the right of the chart here. As shareholders ourselves, I can tell you that the management team is never keen to be issuing stock. We've just been through an extraordinary period, though, and positioned the company for long-term success and resiliency. From here, we'd expect to see the share count remain constant, or it could decrease over time, depending on future capital allocation decisions, and I'll come to that in a sec. With our secure capital program fully funded through 2020, how much free cash flow do we have available for investment? What's our approach to allocating that capital? What does it mean for post-2020 growth?
In 2020, for the first time, as I said, we'll have positive free cash, about CAD 3.5 billion after deducting dividends and maintenance capital. The CAD 3.5 billion comes with some added balance sheet capacity. That's the little sliver that you see to the right there from incremental EBITDA when we invest it. We'll be working within the 4.5 to comfortably below 5 times debt to EBITDA range, which gives us flexibility depending on the quality and magnitude of projects that we see. John will take you through more about the leverage range that we've established and how that compares to others. The way we look at this is that our free cash gives us an opportunity to invest roughly CAD 5 billion-CAD 6 billion annually within the self-funding equity model.
Having free cash flow and a strong balance sheet in today's environment gives us a lot of optionality to move quickly, with newfound flexibility, we think this provides us a competitive advantage. To the extent we're deploying that available capital to organic growth projects, we'd be focused on singles and doubles, which carry relatively lower permitting risk but still deliver really solid returns. Based on what you'll see today from the business leaders, it'll be clear we're not concerned at all about having enough projects to absorb the CAD 5 billion-CAD 6 billion of available investment capacity. In fact, given our project hopper, we'll probably have to make some tough choices on what projects to accept and not. From here, we're also going to assess organic projects against other uses of internal cash flow.
The list that you see here represent the choices at the top, which aren't going to be surprising to anybody in this room. The options we choose will depend on the circumstances, including further debt reduction as a possibility to provide more flexibility, and/or buying back shares. We'll be disciplined in our capital allocation decisions, always looking to maximize value. We'll weigh the options in the context of our financial, we'll call it financial policy filter. You can imagine what those are. Our return on new capital will have to exceed project-specific hurdle rates. The available investment capacity, I just went through of CAD 5 billion-CAD 6 billion. The debt-to-EBITDA range of 4.5 to comfortably below 5, and the dividend payout of about 65% on a cash basis.
It's really this framework that will determine the company's key value drivers at the bottom of the chart here. The expected growth rate, the return on capital, the credit metrics, and ultimately that will drive our cost of capital. We'll continue to assess and rank these options, and these are some of the factors that we're going to look at in this process. As it currently stands, the base plan, this is post-2020, assumes we invest CAD 5 billion-CAD 6 billion that I talked about in available capital in value and DCF per share accretive organic projects. That's what we do best, organic growth protects the base and extends the footprint and hopefully will add more growth in the future. Accelerating leverage reduction has been a priority recently, as you know, but we now have a good balance sheet capacity to take advantage of opportunities.
Even though further debt reduction would not be as additive to growth, it could preserve optionality and create flexibility for emerging opportunities later. Share repurchases would be on our radar post-2020, particularly if our share price continues to be undervalued. We'll assess that against the attractiveness, again, of organic investments we see at the time or creating more balance sheet flexibility. While other options aren't at the top of the list today, we'll continue to monitor our changing needs and market conditions. For example, although we've used asset sales heavily as a source of capital, and you'd always need to look at this option, they are lower priority for now. We've shown, though, we're not afraid to part with assets when we can recycle capital, whether it's into secured projects in the core businesses or creating more balance sheet flexibility.
If you look at the valuations that we received on the CAD 7.8 billion that we sold this year, it's a real good example of disciplined capital allocation at work to add value. Once we whittle down the opportunity set to a select group of highly strategic and accretive projects that we can self-fund, what does it mean in terms of our growth outlook? First of all, we continue to have great visibility to our 10% secured growth target through 2020, particularly now that we've advanced approval of Line 3 in Minnesota. Post-2020, here's how we look at it. Excluding new capital investment, we expect the base business to grow 1%-2% annually through increased system utilization, toll escalators, and ongoing efficiency measure. That's essentially what's embedded in the current business.
The three core businesses, as you'll hear, have an abundance of organic growth in front of them, and we're going to be focused on securing those opportunities. Those projects will fit squarely within our low-risk pipeline utility model. We expect to invest that CAD 5 billion-CAD 6 billion of annual available capital back into the business to drive out an additional 4%-5% growth. In combination, we're now looking at a long-term earnings and cash flow per share growth rate of 5%-7% post-2020. On dividends, we'd expect to follow cash flow per share. Before we wrap up, there are a couple of other important factors, and this connects back into the fundamentals I talked about earlier around the outlook for energy generally. It relates to the sustainability of this industry on two fronts.
Number 1, reducing energy intensity, and second, safety and reliability, which often gets overlooked in these types of meetings, but something that I think we need to focus on for a minute. First of all, the industry itself has embraced what I'd refer to as a sustainable approach, and it is making a difference. Fuel switching technology and tougher standards have really come together to ensure that the intensity of energy is lowered in the future. You can see on the chart, it's been disconnected from the rate of GDP growth. Increased use of natural gas, I referred to earlier. Since 1992, the gas additions that we've made to the base have reduced levels and emissions back to 1992 levels while the economy has grown by 80%. That's the power of using natural gas to reduce emissions intensity.
Technology has lowered oil sands energy intensity by 21%, and new production is at or below the North American average barrel. Even though we, Enbridge, are not a large emitter, we are focused on this as well. Since 1995, our demand-side management programs in the utility reduced consumption and CO2 emissions equal to taking almost 10 million cars off the road for a year. We're using less energy to power our liquids and gas systems through predictive analytics, and we're one of the first to invest in renewables. A broader element of this, I'm sure you've all focused on, is ESG performance. For us, what that means is that we look at the business through the lens of all of our stakeholders. It starts with identifying the risks around ESG, then integrating those into our priorities, the ones I talked about earlier, and the capital allocation framework.
When we make capital investments or we pursue new opportunities, we are going through ESG. That performance is managed and monitored very closely by the management team and the board. This area is not just a nice to have today. To be successful in the business, you need to have real skills and dedication to execute projects. What I mean by that is excellence in consultation with indigenous people, climate and technology solutions, and highly advanced community and public engagement. In terms of safety and reliability, this really is critical to everything that we just covered here and what you'll hear going forward today. As you've seen in the industry, catastrophic events can really derail a company's strategy. The way we look at safety and reliability and environmental protection, it's foundational to the business, and it actually drives the revenue line.
Customers today, landowners, communities, employees, regulators, and everybody in this room, of course, wants to know that we're operating the system well, and actually not just meeting, but exceeding standards. That in itself is going to drive trust that we need to engender in this business today, and it's inextricably linked to the financial bottom line. I encourage everybody to ask the companies they invest in about their ESG performance. To wrap up, let me come back to the bigger picture here and the investment value proposition. For us, the Spectra acquisition was really a game changer. We came into it with one great business, world-class business, and now we have three premium franchises. We merged with a much better balance between gas and oil, and frankly, a beautiful U.S. footprint that will spawn a lot of growth, a footprint, frankly, that cannot be replicated.
Our assets are of the highest quality and will always have inherent value, especially with the low-risk commercial structure that we think is unmatched. This allows us to generate stable, predictable, and growing cash flows. Finally, we've secured projects that'll generate 10% cash flow and dividend growth through 2020, and we believe that our organic growth opportunities can drive out 5%-7% cash flow growth beyond that. We're very confident in this business model, and how it will generate shareholder value as we continue to deliver on our strategic plan and priorities. I'm going to stop there and we'll take questions. Then after that, the business unit leaders will take you through the plans and the exciting opportunities that we have in front of us. Let's open up the questions. Yes. Go ahead, Andrew.
Sorry. Andrew Kuske, Credit Suisse. Al, if you look back in the last 5 or 10 years, you've obviously had a lot of big mega projects, which created a lot of risk in the balance sheet and the income statement. On a go-forward basis, I guess, what's your degree of confidence on the many multitude of smaller projects you've got that are more network extensions and really the focus on delivering those? What's the level of confidence you have from the past to now, and how do you think that affects the valuation?
Right. Good question. Well, as you saw earlier today, Andrew, we've locked down CAD 1.8 billion and I can't remember the exact number. It's probably seven or eight projects that comprise that CAD 1.8 billion. Those are the kind of opportunities that we're going to be focused on for sure. Obviously, because they're diversified by geography, they're smaller in scale, they do come with lower permitting risk compared to what we've seen in the larger mega-scale projects. It doesn't mean that we won't pursue large opportunities, but remember, the CAD 5 billion-CAD 6 billion that I talked about is a pretty big envelope if you look at the annual amounts. If those come up, we'll certainly consider those. But really, I look at it as sort of bread-and-butter projects, in what we call the singles and doubles range, that will be a big area of focus.
I think when you hear the business units, you'll see how that percolates through in each of them. Yes, Linda.
In the past few years, you've talked about this opportunity related to increasing exports out of North America. I'm just wondering, how's your evolved thinking on how this might manifest itself in terms of additional storage, perhaps more partnerships, or maybe even getting involved in export infrastructure, whether it be through LNG liquefaction or crude oil ports, or how you're thinking about that extension and pivoting to more of an export model in North America?
Okay, good. Well, I think first of all, we have to start with the map. The map really shows, particularly in the natural gas front in Bill's business, where the Texas Eastern system extremely well-positioned on the Gulf Coast. Frankly, I think this is what he'll tell you're not going to see many opportunities for LNG be developed out there without having access to our system. He'll talk about a project that's a very good example of that. I think it starts with the asset position. I think on the liquid side of the business, again, Guy will show you a very interesting map where now all of a sudden we've got three big conduits, including Gray Oak, coming into the Gulf Coast region, which I think sets us up extremely well.
It's one of these quiet strategic moves where we've built up a very good infrastructure position. Certainly, we're not there relative to some of the others, but we will be hopefully building on that position going forward. Those are the things that we look at first in terms of infrastructure. In terms of the other part of your question, again, Guy will go through an opportunity today that I think goes right to your point. Getting closer to export markets physically. A great example of that is the offshore port that we're now working on and is under development. It's a good opportunity. Same business model that we have, that we're developing that project. That should get us closer to the last mile, if you will, to export infrastructure capability. A couple of examples there that we'll go through.
Just as a follow-up, do you see yourself being able to substantially execute that from building versus buying or some hybrid combination?
I think to this point, we've been reasonably successful in doing it organically. Obviously, that takes a longer time to move the needle on that basis. There could be some opportunities, I would say, to do some tuck-ins that maybe would advance the strategy a little quicker. That's how we look at it at this point. Really still focused on the organic side at the moment.
Praneeth Satish, Wells Fargo. You talked about there's a renewed focus on returns. I'm just curious in terms of the returns that you're targeting on the CAD 5 billion-CAD 6 billion CapEx, what is that number and how has that changed over the years versus maybe a few years ago?
It's interesting. I think we'd all agree that returns have been compressed, certainly with a lot of new capital coming into the space, particularly from private equity. This is where the discipline comes in. This is why we put so much emphasis this time around on capital allocation. We've got to be disciplined in terms of where we put that capital and not chase opportunity. We've had the luxury, though, of having a good organic position or a natural position in our existing footprint. This actually allowed us to maintain our returns that we're investing in pretty much at the same level as before. Probably the tops have been cut off if you look at new opportunities, but we're still, as a general premise in that sort of low- to mid-teen equity return for the business in terms of new projects. Yes.
David Galison with Canaccord Genuity.
Hi, David.
You've talked about your capital allocation priorities. Can you sort of layer in how you see large-scale M&A, how that fits in, and maybe what the revised goalposts are for those? Maybe if you have a preference for geography and/or asset type?
Okay. Well, on large-scale M&A, maybe let me put it this way. We just completed a very large transaction, and as everyone knows in the M&A space, you need to digest and make sure you're chewing all that through. That's the first part. The second part is probably more important, though. The reason we moved in that direction was really to transform the business and refocus it on natural gas. With that being complete, I think we are in a good spot. We have what we want. The necessity, if you will, of having to do large-scale M&A to transform in another direction is really not needed at this point. That's what I'd say about that. Not really on our radar at this point. In terms of geography, I'd have to say that certainly, we have our assets split between Canada and the U.S.
We're a little bit agnostic in that a project is a project, and as long as it has good returns and the right commercial structure, we'll go after it in our footprint. On balance, though, you'd have to say there's probably a bit more opportunity now in the United States. This is why the U.S. footprint we acquired really sets us up quite well compared to where we were before.
Robert Catellier, CIBC.
Hi.
This may have been part of your plan when you acquired Spectra in the first place, but it seems like there's renewed emphasis today on natural gas investment opportunities in the utilities. I'm wondering, two questions here, if you can help us with what the post-2020 capital allocation might look like. Obviously, it depends on what projects are available at the time. Is it conceivable that we really see sort of a 50/50 split between liquids and all others, or how do you see the shift happening there? I'll have a follow-up question.
Okay. I think 50/50 is probably a good rule of thumb. Although, I would say we're probably more capital intensive, I would say, on the natural gas side. The projects that Guy's working on the liquids business, just in this next phase or next leg of growth that I referred to, are probably a little bit less capital intensive. Still good growth in those projects, but for a bunch of reasons around optimization of the system, it's probably less capital intensive. Probably a little bit more weighted to natural gas, I would say. If you include the distribution business, it sort of bolsters that point.
You alluded to in your comments the fact that there's external capital pressuring returns a little bit. It's also quite apparent that the permitting environment isn't a cakewalk either. There's compression, I guess, on both ends. I'm curious to know what you're doing with respect to risk transfer on the development expense that goes into developing these projects before they become commercially secured, and if there's ability or more of a movement in the industry to transfer some of that risk to the shippers.
Well, certainly, it's a great question, it's one of the biggest issues on our mind, frankly, with the mega scale projects. I think in most cases, in the smaller mid-size projects, we can manage that risk fairly well because of the, call it the less permitting risk around it. We think on that front, we're pretty good, going forward, as I said, we'll be able to focus more on those kinds of opportunities. Certainly, if mega scale projects come up, we're not excited about putting a whole bunch of capital into the regulatory process when there is not enough certainty as to whether or not the project is going to be able to complete it, even if we get regulatory approval. I guess the takeaway is we're going to be very careful in putting capital down to spend on regulatory processes in those conditions.
We've been through that once before, it wasn't fun.
One more here.
I have to go here. I think this gentleman. Yeah. He's coming.
Frank Bamberger, FBA Asset Management. I'm a stockholder with Spectra and, of course, now of Enbridge. Question is, if, God forbid, there's a recession-
Welcome.
What?
Welcome.
Thank you. If there is a recession, God forbid, in 2020, how is it likely to affect your cash flow and dividend payout?
Let me see. Recession in 2020.
I hope not.
I think as we've tried to indicate through a couple of means there, we're pretty much resilient to that outlook. Unless you believe the volumes are not going to run on the liquids and mainline system, I think we're pretty well-insulated from those kinds of events. I think this has been proven out over a number of years. I think that holds true actually for interest rate pressures as well. I think in both cases, the cash flows that we have are quite resilient because they tend to Well, they are in almost all cases fixed fee or they're long-term contracted or they have mechanisms within them to adjust rates depending on what happens. We feel pretty good about the resiliency of the business. Robert.
Robert Kwan, RBC. Al, you talked about CAD 5 billion-CAD 6 billion of available capital in the 2020 and beyond range. You mentioned specifically about potentially having to make tough choices as to what projects you actually end up pursuing. Is self-funding, at least within the equity side, and then maintaining your leverage targets, the key priority as we go forward here?
Well, it's a good question, Robert. Maybe the way I'd put it is these two forces come together. We've got all of these organic opportunities on the one side, which as you saw today, they're all very much in the middle of the fairway and offer good returns with good commercial structures. We've got a bevy of those, as I said. On the other hand, we've got, let's call it this filter or constraint that we're putting on ourselves because we're not keen on issuing any new common equity. I would say those two come together, and along with balancing other capital allocation options around debt reduction or buying back shares, we've kind of put it through that model and we rank what are going to be the best organic projects.
I would say to get to the bottom line of your question, it really is about self-funding, making sure that we're self-funding, not issuing any new common shares in this environment. I'm not sure if that answers your question.
Just within the leverage targets, that 4.5 to comfortably under our 5 times.
Yes.
Are those goalposts really what drive the 5%-7% growth on the assumption that there's no outsized returns in the project portfolio?
That's pretty much the biggest driver. Yeah.
Thank you.
Yeah.
Ben Pham.
Hi, Ben Pham, BMO.
Ben.
Just want to go back to slide 15, capital allocation post-2020. If you take your CAD 5 DCF 2020 divided by your stock price, CAD 42, suggests north of 10% DCF yield. I'm wondering then when you compare up to organic growth, low double digit, shouldn't share repurchases be much higher in terms of where you think about current rank? I mean, even equivalent to organic growth.
Yeah
post-2020.
Yeah, I think it's a good observation. I think if you just did the simple math, buying back shares would be certainly as part of the list, and it is. Obviously, as you know, it's not just about the current yield, if you will. The other things we look at when we think about buying back stock is what is the future cash flow comparison between the two alternatives, organic growth versus investing in your own stock? We'll also look at other factors, for example, on organic growth. Well, does that spawn even more growth? Whereas, in terms of buying back shares, you're not going to have that opportunity to extend the business. Of course, strategically, we've got priorities in terms of each of the businesses. Of course, organic opportunities will tend to further those strategies.
I think it's not just a one-year look at where best to put the capital and buying back shares versus organic growth.
Jeremy Tonet, J.P. Morgan.
Jim.
I was just wondering with the 450,000 of other optimization opportunities you talk about in the Mainline, getting more capacity there, just wondering if you could refresh us on what timeframe you think that could be achieved. When you talk about the CAD 2 billion of annual CapEx spend in the post-2020 era for liquids, is that tied together with that, or how should we think about that?
Yeah. The CAD 2 billion per year would loop some of those in. Most of them, as I recall, Guy will get into this, of course, it's sort of out to that 2021. I think there's probably one in 2022, which involves a longer timeframe to reverse one of the lines. It's sort of between now and 2022. There'll be more opportunities after that, of course, but that's what we're focused on.
Hey, Jeff Healy from Guardian Life. Got a question on sort of your expectation for volume growth from Canada. How much are you constrained by the current agreement that's going in? How much room for growth is there if the U.S. is going to be growing, let's say, one million barrels a year?
I'm sorry, maybe you may just repeat the question. I wasn't sure I caught the first part.
Yes, I'm just looking at the oil production volumetric growth coming out-
Yes
from Canada. How much room do you think there is, basically, in the global market if the U.S. is growing, say, by 1 million barrels a day?
Oh, okay. All right. The production profile out like that we base our assumptions on, and again, Guy will have this chart in his pocket, is about 1 million barrels a day over the next decade or so. It looks like that's pretty rock solid from the upstream work that we do in that there's a lot of projects sitting there that are sort of waiting for pipeline egress solutions. In terms of how it interacts with U.S. production growth, actually, I don't think it changes much. Obviously, most of the growth on the U.S. side comes from light oil, and that's destined for export markets.
In terms of production out of Western Canada, most of that is heavy from the oil sands, and that is actually what we call the perfect marriage in that those heavy barrels are very suited to the Midwest refining market and the U.S. Gulf Coast market. There's that natural connection between the heavy barrels and refining capability. We think that production has a lot of room to grow into the U.S. market.
Hi, Robert Hope, Scotiabank.
Rob.
I'm sure Guy will touch on this a little bit later, but just in terms of the CTS renegotiation in a couple of years, producers do like optionality, so how can you incent them to get to the table in 2019? Then I'll have a follow-up.
Well, I think Guy is going to explain this, but essentially, we're at the table right now, the whole objective is to make sure we're moving this along so that we can replace the existing CTS agreement by 2021. In terms of optionality, we're seeing pretty good interest in this concept around priority access. When you go back to the fundamentals of why that is, it's all about optionality in that the system moves crude to various refining centers in the U.S. and in Canada. Of course, if you're a producer sitting in Western Canada, or anywhere for that matter, that's the one thing you want, is your ability to move those barrels to any refinery. That's really what they get off our system.
They're also going to get toll certainty, that's simply because we've got the scale and scope in a system that can offer very low-cost transportation. Because of that, we can provide good certainty, and if we have priority access construct, it'll also give us certainty in terms of future revenues. That's part of this discussion is that the shippers will have an interest. We also have some interest, and the trick is to line those up.
Thank you for that. Just a follow-up. In terms of your 5%-7% growth beyond 2020, would that assume some sort of cash flow step down from the CTS, or are you going to show producers tolls roughly in line with where they are right now?
Well, I'm not going to get into what the toll discussion is specifically, but what I can say is that the cash flow profile is pretty much stable or growing. I guess that is probably a little bit different than we would've seen it just a short time ago, given what's happening in the industry. Reasonable stability and some degree of growth going forward in the liquids pipeline's mainline cash flow outlook.
Any more questions?
How are we doing here?
Kind of right up on it here as well.
Time?
The team will be back at the end of the day.
Okay, thank you. We're now going to turn it over to William Yardley, who's going to talk through the gas transmission business.
Thanks, Al, and thanks to everyone for joining us today. It's great to be here in New York with all of you, and I'm pleased to have the opportunity to explain our outlook and the confidence that we've got in our gas business. It's really an interesting time to be discussing these assets. We've got a core business that's proven to be unwaveringly solid annually over the past decade. We'll continue to invest in and modernize these systems, in many instances, requiring rate cases to earn our return on those investments. This is something that we haven't seen for years, if not decades, on most of these pipeline systems.
As we wrap up a record year, placing CAD 6 billion of growth capital into service with the likes of NEXUS and Valley Crossing, our reputation remains as the company that can get it done and can get it done right. On top of the secured projects that we've got over the coming years, we've got profound optimism on where our gas business is headed. Geographically, where our footprint is where the growth opportunities in this industry are going to come from. As an orientation, let me just talk about the geographic footprint and some of the recent accomplishments that demonstrate its value. The Enbridge gas transmission assets make up one of the largest natural gas transportation networks in North America. We're connected to the most prolific and diverse supply basins, and importantly, we've linked them to the major consuming markets, both domestic and for export.
Due to this connectivity and our performance, our pipeline assets are fully contracted. They're utilized to capacity, and they're positioned to grow. They've got a very strong reservation-based business model with no direct commodity exposure, very little volume exposure, strong contract terms, and solid counterparty credit. We've been through a period of significant optimization and expansion over the last 10 years. During the same time period, around CAD 15 billion of growth projects were placed into service with another CAD 3 billion contracted for and in execution today. We're pleased with what we've accomplished in 2018. Proud of the 11 projects that were placed into service in a difficult permitting and construction environment of another strong contracting year with our customers successfully securing 98% of the contract revenue up for renewal on our major pipelines.
We're proud of filing a rate case at the Federal Energy Regulatory Commission on November 30th for changes to rates on our Texas Eastern system, and of the streamlining and the divestiture of our non-core assets in the U.S. and Canada to focus on what we're best at. We've had a great decade keeping our base strong and replumbing the North American gas grid. What makes us confident in the future? It's fundamentals, and it's our footprint. Natural gas fundamentals through the next decade confirm the continued need for our service. The industry's existing infrastructure is insufficient in most places where the need for gas continues to grow. Our assets are strategically placed to take advantage of the great opportunities presented by this growing demand throughout North America.
In the next 15-20 years, this demand-driven growth is apparent in the consuming regions of the Northeast, the Midwest, and the Southeast U.S. Economical, clean, plentiful, versatile natural gas is the fuel of choice in homes and businesses, and it's been displacing other fuels with regularity. It's been the clear choice for electric generation. Coal and oil-fired generation are waning. Hydro, wind, and behind-the-meter solar have been growing, but still account for single-digit% on most days. Nuclear is slowly being phased out, nearly impossible to build anew. Natural gas is the only viable alternative at large scale for replacement and incremental electric generation needs. Gas production in the Marcellus and Utica shales in Appalachia continues to outpace expectations, and our Texas Eastern footprint is right on top of it.
Opportunities exist for large-scale and regional projects along our entire geographic footprint. The largest of these opportunities is for LNG exports. This sector of demand will become a bigger part of our story as the use of natural gas outside North America increases.
LNG global demand is expected to grow to 65 Bcf a day through 2030, about 22 Bcf a day of new capacity is required to satisfy these incremental needs. The U.S. and Canada are poised to meet the bulk of that demand, as the number of proposed facilities in well-placed geographical areas is quite large and the economics quite strong. This has the potential to be a big prize, it'll really be interesting as it plays out, 2030 really isn't that far away. As we go through the next few slides, we'll talk more about our growth plan and how LNG factors into the possibilities for some of these regions. These next several slides address our three strategic priorities. One, optimizing our base business and the earnings associated with the existing assets. Two, executing on our secured growth projects.
Third, growing the business by capitalizing on traditional and step-out opportunities. Our base business continues to deliver predictable, stable income year after year. Protecting and optimizing the base is in some ways our blocking and tackling. It's customer service, it's cost control and efficiency, and it's regulatory strategy. Project execution is always going to be critical. Successfully delivering on our project commitments requires nearly every department within our company to be efficiently focused on meeting the needs of our customers, our regulators, communities, and other stakeholders as we bring these projects to fruition. Then, of course, growth. Taking advantage of our unparalleled footprint to compete for these high-value growth projects, both in our wheelhouse and further along the value chain. The first priority, the base. As we mentioned, this continues to be a highlight. Solid, low-risk revenues underpin the gas transmission businesses.
There are three major takeaways from this rather busy graphic. First, we enjoy a high percentage of reservation-based or take-or-pay revenue. Texas Eastern, 95%. Gulfstream in Florida, 98%. Algonquin in New England, 98%, et cetera. Second, the average contract term by asset, nine years, 12 years, eight years, and so on. These are with extremely high credit quality counterparties. Third, this capacity is also highly utilized and valued, as you can see, recent peak deliveries have been achieved on almost every one of these systems. This is what every good business wants: assets that are sold out at maximum rates for long-term with great customers and are clearly used and needed. It sure makes for a sustainable business and it breeds opportunity.
That's a pretty solid platform to build from, and over the next several years, the Texas Eastern, East Tennessee, and Algonquin pipelines will require a sizable increase in capital spend to meet evolving regulations and extend the life and capability of these valuable assets. Fortunately, these pipelines are in an excellent position to earn cost of service returns on these investments, increasing overall DCF per year. The Texas Eastern rate case is really significant for us. The filing is quite a long read, so I'd summarize our case for a rate increase with four points. First, we've seen a meaningful growth in the rate base itself, primarily from capital expenditures required on the system. Second, we've got to have a realignment of depreciation and negative salvage rates to align the return of Texas Eastern's capital invested with the estimated useful life of Texas Eastern's gas plant that's in service.
Third, there's been an increase in the overall cost of providing that FERC jurisdictional service on the Texas Eastern system. Fourth, we'll have a weighted average cost of capital when applied to Texas Eastern's rate base will provide a compensatory and a reasonable level of return. Just quite simply, the filing allows Texas Eastern to recover its cost of service through just and reasonable rates. Similar filings will follow in the coming years for some of the other U.S. pipeline systems. In Canada, earlier this year, we were able to, again, reach a multi-year toll settlement on our BC Pipeline with our shippers. Tolls were reset to recognize a higher rate base arising, in this case, primarily from our many recent expansion projects.
The base business across our system, long lauded for its consistent delivery of unchanging, if not slightly improving EBITDA, is now poised to grow as well through required rate base capital investments. This is in addition to the new pipe we're putting in the ground with our expansion projects. We continue to successfully execute on our major growth projects. This year has been one of our busiest construction years on record. In just the last two months, we've brought on more than CAD 3 billion of projects into service with two projects, NEXUS and Valley Crossing. In the current environment, this is no small feat. More than four years in the making, NEXUS is now delivering natural gas to customers in Ohio, Michigan, and Ontario.
The 256-mile, 1.5 Bcf a day pipeline supports the growing demand for natural gas in the Great Lakes region, and it enables expansions of the Dawn-Parkway system in Cynthia's gas utility business. Valley Crossing, a 168-mile, 2.6 Bcf a day intrastate natural gas pipeline beginning near Corpus Christi, Texas, and extending south through Brownsville, where it travels offshore to the U.S.-Mexico border. The pipeline provides additional market access for the Haynesville, Permian, and other supply sources through eight pipeline interconnects at Valley Crossing's 5.2 Bcf Agua Dulce header system. It's a virtual funnel of varying supplies that get into Valley Crossing, all for transport to our customer, the CFE, Mexico's state-owned utility, serving approximately 37 million customers. Projects like NEXUS and Valley Crossing are very strategic and complementary additions to our pipeline portfolio. The build-out continues.
For example, T-South, a CAD 1 billion expansion of the southern portion of the BC Pipeline in 2020. Also by 2020, Spruce Ridge, an expansion of the T-North system for half a billion CAD. In the Gulf, we just signed the Cameron Extension project. We secured an anchor shipper, Venture Global Calcasieu Pass LNG, and we are currently holding an open season to garner further interest. Stay tuned for more details on that project. Gulf Coast Express, which is a gas pipeline project from the Permian Basin to the east, invested into our 50% ownership in DCP and delivering right into the top of the Valley Crossing system. The base is strong and growing through rate proceedings. We have CAD 3 billion of growth projects under contract, and the fundamentals demonstrate both ample supply and growing domestic and export-oriented demand right on top of our footprint.
How specifically are we looking to take advantage of these opportunities in North America? These are the four regions where we see capital investment in the post-2020 timeframe. The Northeast U.S., Southeast U.S., Gulf Coast, and Western Canada. As we have examined our potential in these regions, we see about CAD 2 billion-CAD 3 billion of growth capital investment annually. Starting in the Northeast U.S., home of the World Series champion Boston Red Sox. On the supply side, the Marcellus and Utica is expected to grow, and it is going to grow from 31 Bcf today to approximately 40 Bcf per day by the middle of the next decade. Throughout the last several years of Appalachian growth, we have really taken the opportunity to expand the Texas Eastern system multiple times to the east. We have reversed the pipeline from Ohio to the Gulf Coast.
We built the OPEN project in Ohio to more fully access the Utica, and NEXUS to get that supply to the Midwest and Ontario. We move about a third of this basin, and we bring these Marcellus and Utica supplies to wherever they need to go, and we can expand accordingly. As the Appalachian supply region grows, so will we. It is fascinating to note that if Appalachia were its own country, it would be the third-largest gas-producing nation in the world. Yet, just to the east, New England relies on fuel oil and LNG imported from thousands of miles away. There is something seriously wrong with that picture. Last December and January, we saw virtually every Northeast local distribution company that we serve set new peak days or multiple peak days within that cold snap. Not surprisingly, so did we.
Our pipelines that serve that region, Texas Eastern, Algonquin, and Maritimes & Northeast, delivered more than 11 Bcf on January 6th. For scale, that is about a third of the entire Northeast peak demand. Throughout New England, natural gas is used for home heating in about 40% of homes, and it is increasing. Most of our local distribution companies are forecasting gradual increases in demand as their customer bases grow and they switch to natural gas. Again, as they grow, we grow. Enbridge has opportunities to expand our current pipelines within our right of way, limiting stakeholder and environmental impacts and allowing us to meet this growth.
Just as we delivered with New Jersey, New York, and the AIM projects, as we're doing with the construction of Atlantic Bridge, and as we're doing with the recently certificated Lambertville East Project, Enbridge will continue to develop and complete projects that meet LDC needs in the Northeast. Looking at power generation in the region, natural gas-fired plants make up nearly half of the electricity supply, and it's continuing to grow based on the planned retirements of coal, oil, and nuclear plants and based on natural gas's quick start ability to complement the renewable energy resources that are being added to the grid. In New England, our pipeline system has 25 natural gas plants attached to it. That's about 60% of the gas-fired generation for the region. Yet of those plants, only about 4% of their generation is backed by firm pipeline capacity.
We're connected to the majority of the plants already. We can expand along our right of way. When this region figures out how to contract for what they need or get fed up with burning oil or imported LNG from thousands of miles away, we'll be in position to expand for them. Moving to the Southeast markets. Electric generating capacity within Florida is expected to grow by more than 15% by 2026. The majority of this growth is projected to be natural gas-fired generation, about 9,000 megawatts through the end of that time period. We're currently executing on Sabal Trail Phases 2 and 3 to serve a good portion of this increased demand in Florida, and we're building a CAD 160 million Gulfstream expansion, Phase 6, for in-service in 2022. That's mostly for Central and South Florida.
There's also increasing need on the Panhandle as we move post-2020, and we're really well-positioned to expand either Texas Eastern or the Southeast Supply Header to serve that load. We see this as a really significant opportunity in the Panhandle to the tune of about anywhere from a half a billion CAD to a billion and a half CAD. The Gulf. Producers in many supply basins are looking for us to expand to feed the LNG and Mexico export markets that are developing along the Gulf Coast because we're really well-positioned, as you can see, to do so. As Mexico continues to build out in country, they also continue to tap into what they see as the reliable, inexpensive U.S. gas. Pipeline exports into Mexico are currently around 5 Bcf a day and forecasted to grow to 8 Bcf a day over the next five years.
Gas production in Mexico continues to decline, so over that same five-year period, marketed supply is projected to decrease from a Bcf a day today to around three-quarters of a Bcf. As for LNG exports, it's forecast that as many as seven projects will proceed in the Gulf Coast region, requiring 13 Bcf a day to feed incremental liquefaction demand. This is above the 10 Bcf a day of projects that are currently in service or under construction. Overall liquefaction capacity is forecast to be around that 23 Bcf a day level by 2030. We're doing our part. We built the Gulf Markets project to feed Cameron LNG, and we're executing on Stratton Ridge to feed Freeport LNG. Now the recently signed Cameron lateral expansion for Venture Global.
Enbridge's Texas Eastern, the Brazoria Interconnector Gas, or BIG Pipeline, and Valley Crossing assets hub the Gulf and are in perfect proximity for capital expansion and extensions to deliver to all of the Gulf Coast LNG and Mexico markets. Interestingly, with Agua Dulce as the site for its header, that funnel that I mentioned, into Valley Crossing for Permian, Eagle Ford, Haynesville, Barnett, and any other supply source, sets us up really, really well to connect any of these supply sources to the South Texas LNG facilities and future exports to Mexico. In addition to traditional growth, Mexico and LNG exports, Enbridge also continues to pursue offshore opportunities for attractive incremental investments in the Gulf of Mexico. We're leveraging our strong deepwater asset position, our relationships and technical capabilities, as demonstrated by our recently signed CAD 200 million project for Shell's Vito development. Western Canada.
In the last five years, we've more than doubled the rate base investment in our BC Pipeline system in Western Canada, including both T-North and T-South, by executing close to CAD 2 billion of supply push and demand pull expansion projects. We've built a really strong platform, setting us up for opportunities going forward. The Montney and the Duvernay basins in Western Canada are world-class, having both size and scale, and the low cost to develop and produce versus other North American basins. We also see Western Canadian sedimentary basin supplies building and needing pipeline takeaway from that region. Significant infrastructure improvements are going to be needed to get all this gas to market, creating a lot more opportunity for us. The existing assets, both the BC Pipeline and Alliance and Aux Sable, are in a really good position relative to the growing Montney and Duvernay plays.
We've put a number of bolt-on projects into service recently, such as Jackfish Lake, High Pine, Wyndwood, Ram. These are straightforward, on-system, bite-sized expansions. The Spruce Ridge and T-South expansion projects are the next in the queue and are scheduled to go into service in 2020, and there's demand for new expansions right behind these two projects. We recently completed a successful open season that'll have us expanding our T-North system by 2023 and expect to secure an additional expansion of T-South early in the next decade as demand for service from downstream markets continues. The growth outlook, certainly for BC Pipeline, remains quite strong. Then Alliance. The Alliance story is a very positive one as well. Our seasonal firm and IT contracts continue to see significant premiums to the firm tolls due to the pricing differential between AECO and the Chicago markets.
Of course, demand for service on Alliance remains strong, also due to these price differentials. For expansions on Alliance, considering both full path or Canadian-only or U.S.-only paths, we're working with our customers currently to tailor a new build to meet their needs. In addition to traditional opportunities, we're also looking at step-out projects in Western Canada. A key area of focus here is LNG exports through our Westcoast Connector Gas Transmission project. Westcoast Connector has a developed route to Prince Rupert. It's scalable. It's a cost-effective transportation option for any of the next phase LNG export projects that are being discussed. Proof of concept here for Westcoast Connector is that we've signed an exclusivity agreement with a significant LNG proponent, and they'll negotiate only with Enbridge until mid-2019 for LNG transportation to the West Coast.
We're also open to LNG terminal investment. In addition to LNG, we're exploring the development of NGL infrastructure in Western Canada so that our pipeline customers can fully monetize the liquids that are currently entrained in the gas pipeline stream. Clearly, that would be a win-win situation. Summary, we have a base business that's not only solid but provides for modest growth opportunities. We've got CAD 3 billion of growth projects that are in flight, where we are is where the growth is going to be. We know this business isn't for the faint of heart. We understand that what we do isn't easy, natural gas use is growing, despite those that don't want to believe that. It's cheap, it's abundant, it's the cleanest of the fossil fuels. It complements and enables the growth of wind and solar.
It's the fuel of choice for increasing needs in homes, businesses, and for power generation. We're in great position to make sure that those needs are met. With that, take any questions if you got them. Jonathan, right back there.
Yep.
Thanks. Jeremy Tonet, J.P. Morgan. Bill, I was wondering, with a lot of projects in Appalachia, most of the major projects have faced a lot of setbacks or issues, it seems like NEXUS, once you get the FERC quorum kind of moved pretty smoothly there. What do you think was different as far as how you guys executed versus most others, I guess?
I would say that, first of all, thank you for acknowledging that because we've put a ton of time and effort into our permitting and our stakeholder outreach strategy. What I would say is that it's difficult to compare us to anybody else in particular, we did certainly get a lot of credit for the way that we approached that project. Maybe a little bit of the extra time helped as we were going through a difficult FERC period. Jeremy, we learned an awful lot when we did New Jersey, New York. We've learned a lot through Sabal Trail, through our other Appalachian region projects as to how do you treat landowners, how do you treat other stakeholders? How do you get through the permitting process the right way? It's not to cut corners.
It's not to necessarily just say, "Well, FERC said we could do it, so we're going to do it." We've got to engage every stakeholder, whether it's a county, state, regional, government body, or permitting agency, and do it early. I think we did, and in that area, we were compared to others, and I think we came out well. Thanks for acknowledging that. I'm not sure I answered your question all that well, but I really appreciate that.
Thanks. I just wanted to follow up on Northeast growth as well. The need is quite clear in New England, New Jersey, New York. The environment seems quite difficult there. Massachusetts made the active decision to import Russian LNG instead of support infrastructure from Pennsylvania, cheap gas, very close. How do you move forward with that environment? Granted, the need is extremely clear for the infrastructure.
All we can say is that we are really well-positioned. Whether it's Access Northeast or some other derivative of that as we go on. The Algonquin pipeline and the Maritimes pipeline are right where they need to be to serve the load that needs to be served. Currently, I think it's either going to take something that is truly disruptive or some fairly significant political courage to say, "Look, we appreciate that we need a lot more renewable resources in the region." We're not fighting that. In fact, we're trying our hardest to marry what we can do on the gas side for along our system in the right of way, expansions that aren't terribly invasive with the renewables and try to partner in some way, shape, or form. That's another mechanism, frankly, that doesn't exist today. You're either renewable or you're not.
That doesn't make sense because what gas does to complement those renewable resources, it really does enable them to grow. If you're going to electrify Massachusetts and you're going to electrify the rest of New England, you're going to grow the overall need for generation. If you're going to do it with renewables, you're going to have to back it up with gas. That, I guess, states the case for why it's needed. How it's going to get done? Again, either there's going to be an event of some kind, which where gas plants won't be able to get what they need and other resources won't be available, or it's going to take one or two governors getting together and saying, "Gas really is a big part of the solution," and push it through their state Senates.
Over here, Bill.
Yep. Sorry.
Robert Catellier, CIBC. This question is relevant for your peers on the liquid side of the business, and you've indirectly answered it with the amount of investment opportunity you've detailed on the gas side. I'm very curious to know the company's opinion of Bill C-69, the Impact Assessment Act, and how that influences your appetite for growth in Canada and how it might change your approach to project development.
Well, I'll be happy to pass it off to Al or Guy for this one, but it's probably more of an overall corporate answer.
Well, as you can imagine, we spend a lot of time on Bill C-69, advising the federal government. That bill is currently in the Senate, as you know. I think generally speaking, the federal government probably has the right intention in terms of wanting to ensure predictability and certainty in the process. However, in our view, it's not quite there yet. There's some issues within Bill C-69 that cause us concern, and it goes to the previous question that we talked about, around putting capital to work in developing projects and then not having the certainty that even once approved, that we're going to be able to execute the project. There's several issues with respect to timelines, uncertainty around timelines, what's included in the project list, what projects are included and excluded from this bill and process.
Then there are several areas, let's call them, of policy generally. For example, around environmental issues that effectively get worked into project reviews. Of course, single projects cannot be responsible for addressing broader issues around environmental or emissions, for example. We have some concerns about it. We're working with the federal government to continue to provide that advice, and we'll see where it ends up. Anything to add on that, Guy?
Right here.
Yeah.
Yeah. Linda?
Oh, hi. Thanks. I wondered if you could elaborate a little bit on the NGL opportunities that you see in Western Canada in terms of scope and scale. As you can appreciate, some of the incumbents there provide kind of a full-path advantage that might have certain commercial attributes that are not typically within your kind of focus. Are you going to be leveraging some of your existing infrastructure and relationships, or how do you expect to compete, and under what timeline and how?
I'll say a little bit, and I don't want to get into it too deeply, but these would be specific to NGLs that are currently entrained in our existing BC Pipeline. That situation is getting to a point where the heat content of the gas is just getting too much as it reaches the market. Not today, but it will in the next two to three years. I think it's a unique opportunity to us to provide some sort of relief, and that could be a full complement NGL relief, or it could be for one product specifically or another. I think that's as far as I'll go on that, but I think it's an opportunity that is fairly unique to us because it's within the BC Pipeline system today.
Right here, Bill.
Yeah.
Thanks. Good morning. Tom Abrams from Morgan Stanley.
Hi, Tom.
Bill, could you give us an updated roadmap on the PennEast project? Are you hearing any rumblings in Mexico about contract changes with CFE that might impact your southern business there?
Yeah. I'll tackle the last one first. No. No issues currently, no rumblings that we're hearing. We're in contact with the CFE regularly. Any changes that we've seen in the government has not trickled down, nor would we expect them to at this point. That's good news. As far as PennEast goes, PennEast is a challenging one, right? We're dead in the middle of trying to get the project through all the way to New Jersey, and the New Jersey permitting process is a challenge for us, where, as Al alluded to, the lack of certainty within the state, partially with a change in the government there, has left us in a kind of an arduous situation or the task is arduous to try to get all of our survey permissions today.
I think the partnership generally looks at this project as a project that's probably going to be completed sometime in 2020 with the delays that we've seen. We had hoped to get that project done actually this year when we started it, and it's a long, slow slog. Luckily, I would say we do have very good partners, many of them within the state in New Jersey. We think that the gas is really very well needed in that area and would be a really nice tap into the Northeast Marcellus, which would not just benefit Jersey, but also could get into the Texas Eastern Algonquin systems and potentially provide some relief to New England. Hey, Robert.
Bill.
Robert Kwan, RBC. Just coming back to the West Coast and on the LNG pipeline side of things, the one that is going ahead has below average returns and above average leverage. Can you just talk about how Westcoast Connector might be different, particularly mapping back to Al's comments about applying a filter to high returns and then keeping in check?
There's a lot of water to go under the bridge for that. What I would say is that we have, number 1, I think overall, regardless of what the returns are on the first project going, I would say that it's generally a good sign that there's support for a project. I think it legitimizes Canada's place on the world stage with regard to LNG export. The Westcoast Connector, we did a lot of work on this at Spectra, and we think that it is scalable to what is needed for the producers that are interested that are currently left behind. In terms of the financials and leverage, there's just so much to talk about, or so much to decide between now and the time we actually sanction a project. Difficult to say.
If I can just follow up or turn to the Northeast here. You talked about having the right of way on TETCO and Algonquin. As you look at new projects, obviously there's going to be full regulatory associated with it, but how much space do you actually have in the specific right of way and the easements that you've got, or is it really just you've got general right of way-
Yeah
Permitting something along the same line is obviously going to be easier than brand new routes.
It's a great question. It's actually complicated to answer, but it varies. Algonquin is really unique, and I'll harken back to what our program has been when we started AIM and moved on to Atlantic Bridge, and we're moving on to Access Northeast or whatever comes next. Basically, Algonquin, this is the simplest one to explain. Algonquin is a two-pipeline system. It's currently got, or when it was probably before we started AIM, it had a 30-inch pipe and a 26-inch pipe in the same right of way. The 26-inch pipe was the original. What we started to do with AIM was, in addition to adding some compression, is we were replacing pieces of the 26 with a 42 in the same right of way, same path. You need a little bit more for that size pipe, but nothing that was radical.
We were able to get it through permits in New York State, of all places, right? With both Atlantic Bridge and with AIM. That, we haven't done much of that just to get AIM done and to get Atlantic Bridge to the stage that it's at. We have another, I can't remember, but I think it was 30 or 40 miles of that pickup and relay associated with Access Northeast. That's one example where having the right of way and having a pipeline that you can replace that's a 1950s vintage pipe, all good, but take out a 26, put in a brand-new 42, that's a good day. That's one way to do it. Texas Eastern, we have in between three and four pipes in the right of way, depending on which line you're looking at. I don't know specifically.
I think it varies by section, by parcel, how much extra right of way we had, but we'll do the same type of pick-up and relay if necessary, if we can't get another pipe in the right of way.
Thanks, Bill.
Yep.
Thanks. Dennis Coleman, BofA. Bill, I wonder if I might just expand on the question about returns on the Westcoast Connector to the broader set of opportunities that you talk about on LNG. The opportunity is pretty clear, but we've seen other areas where you end up with a lot of people chasing the opportunity. Others are talking about it, and you end up competing on returns. I wonder if you just might talk about that.
Yeah. I think we've been pretty disciplined to date not to get into that game. Whether it was Florida, whether it's been the Permian. Permian is actually analogous in some way. Permian, when we looked at building a Permian pipe ourselves, the returns on the pipeline, just looking at from a supply source to the demand point, and synergistic with some of our other assets like Valley Crossing, we thought, "Well, let's get in there and bid." Those returns are pretty compressed. You really need to have something on the supply end to augment those returns, and that's what DCP had. Participating and playing through DCP was actually a much better return for us overall.
I would wager that same dynamic could play out in Western Canada or frankly, in any one of our other regions where if you can leverage what you've got, you can juice the returns a little bit and earn more than just that linear piece of pipe in the ground.
Okay, thanks. Then just on the timing of how these projects might come into play, we haven't seen any FIDs on LNG. Are we talking three or four years out to-
I think we'll know a lot more after we get through the next 6 months of negotiations with this one player that we're talking to. I think if, A, if we come to some really good agreement with them, and they can drag along some of their counterparts, then we'll know more. Sorry, short stories, we'll know a heck of a lot more later this year. Where are you people on the earnings calls anyway? I don't get any calls. I don't get any questions, and now I'm getting them all.
One more over here.
Thanks. Greg Gordon from Evercore ISI. I come from the utility side. I follow DTE, so I have question on the NEXUS Pipeline. My understanding is it's about two-thirds subscribed, staging into being two-thirds subscribed. A lot of debate about the long-term merits of that pipe since the day that you guys announced it. With Dawn looking fully supplied as we go out in time, what's the competitive advantage on that pipe, and how do you get to fully subscribed? What types of returns do you expect once you're fully subscribed on that pipe?
Yeah. The pipe today at roughly two-thirds full probably just barely covers the cost of capital of the project. That's not a good place to be. That doesn't gain me any favor with my boss, that's not a good day. Frankly, the environment today, when you just build a pipe and you just build the infrastructure, it's the lowest possible time, or probably the basis is at its lowest point, going forward. Today is not a great day to judge that. I'd say two things. One is that over the course of the next several years, a few years anyway, takeaway is going to improve from Dawn, whether it's going up into TransCanada and heading East. It's just yet another way to get gas to the East Coast, or whether it is through increased power generation.
Having a partner like DTE, I think they have a pretty good insight into the coal to gas conversions that are going on in that region. There's a pretty good. At the very end of the pipe, I think we feel good about that. Along the line, we spent, I know we've talked about this a lot, we spent a lot of time hooking up gas customers in Ohio. They're not ready to sign up for firm capacity today, but they will as time goes along. That's going to be their primary choice. It's too early to judge that the project is going to be cost of capital plus 5% or whether it's going to be 3% or 8%. Too early to tell on that. For us, DTE has their own synergies with Nexus.
For Enbridge, when you think about what it does to connect the Texas Eastern system with the Dawn-Parkway storage hub, it's something that we wanted to do, frankly, since we bought Westcoast back in 2002. To have that and the ability to move gas back and forth, a couple hundred Bcf of storage in the Ontario area and all the markets and need for storage that we see on the Texas Eastern system, I think there's really good synergy back and forth. If we don't sell out for 10- and 15-year contracts early in this process, I think we have a pretty good line of sight to smaller, shorter-term contracts that will at least try to get us a little bit of revenue in the meantime. Yep.
Any more questions for Bill? Okay. We'll have Cynthia present on the utilities, and then we'll have a short break after that.
Good morning. As you heard, my name's Cynthia Hansen, and I have the privilege of leading our utilities and power operations team. It's a very exciting time for our gas utilities. On January 1, 2019, we will amalgamate Enbridge Gas Distribution and Union Gas into Enbridge Gas in Ontario. The amalgamation will allow Enbridge to grow and fully leverage our utility operations. We have high-value assets, great people, and a really strong customer base that provides a platform for continued geographic growth as well as opportunities to lever into other sectors like electric utilities. We have a five-year regulatory deal with large synergy opportunities in a low-risk business with great growth potential. This premium utility is the largest and best-situated gas utility in Canada, supporting Ontario, Quebec, and U.S. Northeast markets.
We are number one by gas send-out in North America, the third-largest based on our total number of customers. Our franchise area generates 40% of Canada's GDP. Our reach into over 12 million people and businesses with our 3.7 million meters ensures that we are very well-positioned for growth, both in our traditional and then the new lower carbon market. We have exceptional growth in customers and assets. As Al mentioned, we add over 50,000 customers each year and deploy capital in excess of CAD 1 billion annually to maintain and grow our great assets. Our franchise serves over 40% of Canada's population, and that population is expected to grow by 33% by 2040. Our Dawn storage hub and our Parkway transmission assets are tied to large demand centers that are growing.
We have a 5-year regulatory construct that provides 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 70% cheaper than heating oil. As our priorities, we will first optimize our base. Our near-term focus will be on that successful integration of our gas utilities in Ontario. With our recent Ontario Energy Board regulatory decision, the utility is positioned to generate very strong financial returns, capturing synergies, and delivering value to both our rate payers and our shareholders. We're building on a very strong foundation, applying learnings from previous Enbridge transformations. We already have two of the top quartile gas utilities in North America. With synergy capture, we will drive to the best-in-class operating cost and support structure.
We will execute on our secured projects with our near-term in-franchise growth, we will continue to capitalize on the growth opportunities that are inherent with our assets. Growing storage and transmission, expanding into new communities in Ontario, positioning gas in the transportation market for trucking, and capturing renewable natural gas within our grid. With the integration, we'll be very well-positioned to support longer-term utility step-out transactions. The new 5-year incentive structure inflates rates annually based on a factor of GDP, less 0.3%. This 0.3% stretch factor ensures that some of the benefits of amalgamation flow directly to our rate payers. We share earnings with our rate payers on a 50/50 basis after our returns exceed the allowed rate by 150 basis points so that our benefit capture starts on day one.
Capital programs that exceed a threshold are recovered at the allowed rate of return if the projects are required, similar to the current approach to capital for Union Gas. The new deal allows Enbridge the opportunity for enhanced earnings in the utility while continuing our strong focus on safety and reliability. In this low-risk business, we have developed a 5-year business plan that will deliver on the operating cost synergy opportunities with a modest investment in capital that will drive a return of approximately 100 basis points above the allowed rate of return, which is currently 9%. While we're focused on opportunities with the amalgamation to capture synergies and our continued growth platform, we are not distracted from the day-to-day demands of our business.
We will be working to realize synergies with the combination of the two utilities in a number of areas, including operations, customer care, work management, shared services, storage, and transmission, as well as our management functions. Our people continue to safely and reliably deliver the energy that heats homes and generates economic growth. The strength of our committed and engaged team is the platform that allows us to continue to deliver those strong, stable financial results. In the next couple of slides, I'll just highlight what those growth opportunities are. As I mentioned earlier, we will add over 50,000 new customers each year.
In addition to this very steady growth, the new provincial government in Ontario recently passed Bill 32, which supports expansion of low-cost natural gas to additional communities, driving local business development. We'll have the opportunity to connect up to an additional 50-plus communities within our franchise area. We have a 10-year capital asset plan that we filed with the regulator, and we will continue to reinvest and renew our assets, ensuring safe and reliable operations. For required capital projects that exceed that threshold, the incremental capital model will provide a rate-based return. We'll continue to invest over CAD 1 billion annually in our capital programs. Our storage assets at Dawn and Tecumseh and our transmission assets, including the Dawn to Parkway system, are extremely well-placed. We are the market leader with highly reliable, competitive price storage and transmission services. Dawn is the second-most liquid hub in North America.
Last year, we completed our three-year program to build a 1.2 Bcf expansion, and we're continuing to grow that liquidity at Dawn, providing peak and seasonal services, and we're already starting to leverage the combined storage operations. We have and will continue to develop transmission capacity support, our franchise growth, as well as that U.S. Northeast demand. With the completion of NEXUS and Rover, we're very well-positioned to support that growth. We recently completed an open season, and we saw a very strong interest, which will translate into additional expansion in 2021 and 2022. Now, with the extension opportunities, there are significant opportunities for more compressed natural gas in Ontario, including busing, garbage trucks, and heavy-haul trucking. CNG is a lower-cost and lower-carbon solution. We've secured a number of projects along the Highway 401 corridor, and we're reviewing additional regional stations along the 400-series highways.
We're currently working with municipalities and commercial operations to expand generation and capture of renewable natural gas associated with landfills, biodigesters, and other opportunities. Carbon pricing, clean fuel standards, methane regulations are driving strong demand, and the regulatory construct allows for the inclusion of the RNG injection facilities into rate base. We've successfully secured projects, including the Dufferin project with the City of Toronto, and there are 15-20 potential projects that are currently under review. With our Enbridge investment in the East-West Tie facilities, we're growing further into the electricity space in Ontario. East-West Tie filed their leave to construct with the Ontario Energy Board, and the environmental assessment comment period closed on November 16th. We're excited by this potential, and we're also excited by the potential that exists for other low-risk, regulated-like business models, including alternative distribution systems and behind-the-meter solutions.
We continue to pursue opportunities to integrate gas and electric infrastructure using combined heat pumps, geothermal loops, and hydrogen storage and blending. We commissioned the first large-scale hydrogen power-to-gas fuel cell in North America this year, a 2.5-megawatt unit in Markham that provides services to the IESO. In summary, we have great assets located in major growth centers in Canada and connected to diverse gas supplies. Our assets deliver strong, predictable returns. Over the near term, we will drive tremendous value with the amalgamation of the utilities, streamlining our operations, optimizing our storage and transmission assets. We will be the best-in-class utility, leading in operating and cost management. This drives the 1%-2% annual growth of DCF per share. We have extremely strong organic growth with our ongoing 50,000-plus customer additions and the opportunity to expand into 50 or more new communities in Ontario.
Within the five-year incentive agreement, we have a defined asset plan that exceeds the CAD 5 billion and supports both the identified growth as well as the renewal of our rate base. The incremental capital model ensures that we will earn the allowed return for any required capital additions that are in excess of that threshold. We're very well-positioned to offer unique solutions to our 12 million-plus customers with complementary lower-carbon solutions, including CNG, RNG, and behind-the-meter opportunities. What we own and operate today is an extremely strong platform to support growth as we provide gas to heat homes, run businesses, and transport goods. We'll continue to build out the franchise and maximize our operational efficiencies and leverage our size, safely operate while we deliver strong, stable financial results. With that, I open it up to any questions.
Andrew Kuske, Credit Suisse. Obviously, you're in a very different position than what we've seen with Hydro One and just all the political shenanigans that have gone on there. Do you worry about any kind of movement for re-regulation and effectively taking returns downward for utility assets in the province?
I would say that, as you mentioned, within Ontario, gas and electric are in very, very different spaces. We have always developed a very strong working relationship with the existing government. We've had lots of opportunities to start to establish that relationship. I am not worried that we are going to face a re-regulation of the gas franchise within Ontario.
Hi, Michael Lapides of Goldman Sachs. Can you remind us what is the maximum earned return on equity you're allowed out of the utilities, or when does a sharing mechanism, if you hit a certain ROE, kick in that you have to give back to customers?
Right. With the new agreement that we'll have on January 1 under the amalgamation, we will be allowed to earn within the combined utilities up to 150 basis points over the allowed rate of return. The allowed rate of return for 2019 is set at 8.98%, effectively 9%. We will be able to earn up to 10.5%. After that, we can still continue to earn, but we share 50/50 with the ratepayers. You're welcome.
Hi, Ben Pham, BMO. On your rate base growth, just kind of rough numbers, looks like it's more of a 4%-5% CAGR, which isn't much different than North American growth rates. Is the difference between that, is that more a regulatory lag that you're managing this new incentive term and then in 5 years beyond, there's a big pickup in the rate base and the growth that you see longer term?
I think the way I will capture this is that the growth of 1%-2% is strong, probably on the higher side, just from the synergy capture. We'll be very well positioned to drive that growth. The rest of the growth comes from the billion-plus that we're going to add over the 5 years, and following that is going to be from our 50,000-plus customer adds that we do annually, plus the expansion in new communities, the continued build-out of Dawn-Parkway and our transmission assets. That's kind of in excess of that. It will generate overall about 4%-5% growth of EBITDA post 2020. It's a very strong growth platform compared to overall utilities.
Okay, it sounds like in terms of that 4%-5%, you've generally secured that post 2020 for a number of years beyond.
Well, for the five-year term, then we'll rebase in 2024. There will be a rebasing that happens at the end of that five-year term.
Hi, Robert Hope, Scotiabank. Just in terms of allocation of capital, we've seen you divest two of the smaller utilities. I just want to get a sense of today's focus has really been on Ontario. What about the Quebec assets? Longer term, would you look to further geographies as well?
Yeah, that's a great question. The divestiture of the two smaller utilities, St. Lawrence Gas and Enbridge Gas New Brunswick, were based on that they weren't really fitting into what our core is. Basically for those utilities, great utilities, they didn't have a lot of growth potential. Very different from the new Enbridge Gas and even Gaz Métro. Gaz Métro, we're just completing two expansion projects in that franchise. There's synergies there with Gaz Métro being close to our Ottawa operations. Like Al said earlier, though, we will continue to look at how we value our assets and how we will do our capital allocation in the future and make sure that we are getting that great return for our assets overall. At this time, as Al mentioned, we're very strong in our financial position, and we're not looking at additional divestitures.
Any more questions?
Maybe I just tag on to one point that Cynthia made in response to Andrew's question around the Ontario business environment, let's call it that, generally. One of the things that is a little bit different as well, and Cynthia alluded to this, is that the nature of natural gas and the cost structure and the efficiency of it relative to other fuels, let's just say that, in the province is extremely effective. Not only is it inherently lower cost from a heating point of view and so forth, I think the team's done a very good job at keeping costs very low, which all is to say that I think we're doing the right things for customers. I think that puts us in a bit of a different light, just in terms of the overall position in the province.
Okay. With that, let's take a 15-minute break. There's coffee and snacks in the foyer, and we'll reconvene, let's call it 10:45 A.M. sharp. Thank you. Hello. Folks, we're going to get back started again in one minute, so if you could make your way back to your chairs, appreciate it.
The other question.
Yeah. There you go.
I recommend you tell them to keep their bodies
All right. Got the signal, I'm ready to go. Good morning. Happy to be here to wrap up our business unit reviews by talking a bit, the next 30 minutes or so, about our liquids pipelines business. Like Cynthia and Bill, we're very excited about where we're at and the outlook for our business right now. We're making great progress on a secured capital plan, we're safely moving a lot of crude, we're relentlessly focused on finding ways to increase throughput. We're working hard on a range of things that give us the confidence that we're going to continue to grow this business into the future. There's going to be a number of new things that we're going to talk about today.
The first one is we've identified several options that we think are going to allow us to increase throughput out of Western Canada by the middle of next year. An opportunity has been identified to potentially expand the Express Pipeline by the end of 2019, we're continuing to pursue longer-term options to enhance throughput on the mainline system. I'm going to provide an update of our discussions with customers regarding the need to replace the current CTS agreement which expires in July of 2021. A couple of new projects have been secured, which I'll review. The acquisition of the Cheecham Area facilities that service Athabasca Oil Corp., the exercise of our option to acquire an interest in the Gray Oak Pipeline. Finally, I'll talk publicly for the first time about an offshore U.S. Gulf Coast VLCC loading facility that we're developing called Texas COLT.
There's a lot to cover. I'm going to get right to it with a quick review of what is North America's premier portfolio of liquids pipelines assets. Our mainline system, the markets it serves, the flexibility it offers, and our capabilities to optimize throughput is uniquely distinct with unparalleled competitive advantages. In November of this year, the mainline delivered a record 2.785 million barrels per day into the U.S. Following completion of the Line 3 replacement, mainline capacity will be restored to approximately 3.225 million barrels per day, 3 million of which can serve our extensive refining markets in the U.S. Regionally, we're very well-positioned in key supply areas. We serve many of the largest oil sands projects with laterals, facilities, and four pipelines capable of transporting 2 million barrels per day to the Edmonton and Hardisty market hubs.
Express Pipeline transports up to 280,000 barrels per day Canadian crude to serve markets in the Rocky Mountain region. We own and operate two pipelines serving North Dakota's Bakken production, and we're a partner in Dakota Access. We have a growing reach into the refining center and export infrastructure along the U.S. Gulf Coast through Seaway, Energy Transfer Pipeline, and now Gray Oak. These assets are commercial and operating capability, along with the many relationships that we have across this network provide a fantastic foundation to continue to grow our business. Our outlook is always underpinned by an assessment of the fundamentals. Let me start in Western Canada. Production growth from the oil sands under development are already producing continues to be strong to the point where today we estimate the basin production exceeds local refinery and export pipeline capacity by as much as 450,000 barrels a day.
Expectations are that these projects could continue to add as much as 600,000 barrels a day of incremental production through 2025. The oil sands is one of the greatest remaining crude oil reserves in the world. Producers have made huge strides in terms of how they more efficiently execute their capital projects, manage their operating costs, and utilize technologies to lower emissions. We believe in this basin over the long term and are committed to ensuring that pipeline capacity will be available to support that growth outlook. Sorry about that. It seems that I might be missing a slide.
Record throughput on the mainline in November is further proof point of our successful track record of increasing capacity and undertaking those actions to safely maximize throughput. The flexibility of the mainline, the high reliability performance it provides on the foundation of an extensive integrity program, and the innovation of our staff are driving value every day for our customers and for Enbridge. Every barrel of throughput is extremely important to our customers right now, and there's a great deal of pride throughout our organization that drives the relentless focus on things like coordinating maintenance, optimizing crude slates across our multiple lines, removing smaller bottlenecks across the system. We look forward to 2019 and beyond, we're confident that new solutions continue to be implemented. We've always liked the fundamentals for liquids-related energy infrastructure along the U.S. Coast, dating back to before the crude oil export ban was lifted.
Lifting of that ban has made the region even more significant for us, given that it is a key factor impacting pipelines and market access alternatives. The refining capability of the U.S. Gulf Coast is well understood, as is the need for additional export capability. We believe each represents a growing need for infrastructure, ranging from pipelines to storage, to blending, and ultimately, the export facility itself. Where does this lead us to with our strategic priorities? It highlights our continued focus on optimizing throughput on the mainline and ensuring complementary market access options are available. Providing support to this focus will be the finalizing of a new mainline toll framework, which we believe will continue to incentivize us to maximize available capacity and throughput. We need to execute our secured projects as planned, and we're pleased with where we are at in that regard.
We want to continue to secure opportunity to build out our U.S. Gulf Coast presence focused on market access and export opportunity. I'm going to speak to each one of these in a little bit more detail. My apologies. This is where my slides got out of order. I've already talked about this slide, and again, it comes back to talking about the proven track record that we've established in terms of optimizing throughput on the mainline system. This slide is going to look familiar to any of those who attended Enbridge Day last year or have spent any time with our investment community presentation. The reason they look familiar is that our premise remains unchanged.
Following the Line 3 replacement, our mainline system will be capable of delivering 3 million barrels per day into the U.S., and we have the on-system demand and downstream pipeline access to get these barrels to the refinery. Our system serves the highest priced markets with the lowest toll, resulting in the best net back opportunity for Western Canadian crude. Assuming pipeline tolls drive pricing differentials in a scenario with competing pipelines, the Enbridge mainline is expected to offer up to CAD 5.50 per barrel net back advantage versus spot tolls on the competitor pipelines. The chart on the right continues to assume that both Keystone XL and TMX are built. We are showing Keystone XL in service for 2021 and TMX a couple of years later. As you can see, the outlook for our mainline throughput continues to be very strong.
Barrels will dispatch out of Western Canada based on the best available net backs. Local refineries will be served first, and contracted capacity will flow next. Beyond that, we believe the Mainline will take up the remaining volumes until such time as we're full, an outlook that will only improve following the planned contracting of the Mainline system effective July 2021. Let's move on and talk a bit about that Mainline tolling. The hallmark of our success in negotiating the tolling framework for the Mainline, dating as far back as the mid-1990s, has been creating solutions that align Enbridge interests with those of our customers. Customers continue to want long-term toll predictability, flexibility to serve different refining markets across the Mainline, and incentives for Enbridge to continue to optimize throughput, all of which is available within the construct of the current competitive toll settlement.
The CTS, however, does not offer a number of new features that customers are seeking. Customers want to be able to align Mainline capacity to either of their refinery, their production, or downstream pipeline contracts on a long-term contracted basis with priority access. They're no longer subject to apportionment. Meeting these needs of customers aligns very well with our own interests. As a result, we've been in discussions with our customers on the potential to contract the capacity of the Mainline system for several months now. Negotiations with our customers are not complete. At this stage, I'm not going to be diving too deeply into any of the terms and conditions.
What I can tell you is that the framework will include priority access for up to 90% of the Mainline capacity, contract terms of up to 20 years, tailored offerings for producers, tailored offerings for refiners, and a large volume discount opportunity. We expect to conclude these negotiations on the framework and submit the required regulatory applications in 2019 to ensure we're ready to go upon the expiry of the CTS in July 2021. Talking a little bit about 2019 and the potential to increase throughput. Our team's been working hard on a couple of the longer-term options that we've identified. The option to reduce deliveries coming out of North Dakota into our system at Cromer and, of course, the planning around the expected in-service date of Line 3 at the end of next year.
That work has highlighted for us that we have a couple of options to potentially increase throughput next year. We're working very aggressively on them. Discussions are underway with our BPAP shippers to consider a temporary suspension of deliveries to Cromer that would allow the Mainline capacity to be served from Edmonton. Agreement has been reached with one of the shippers, and a small capital investment program is underway that is expected to allow us to move up to 50,000 barrels a day of incremental crude from Edmonton by the middle of next year. This plan does not increase capacity on the system, but simply replaces a North Dakota barrel with a Western Canadian barrel. The Line 3 replacement project in Canada is expected to be complete by July of next year.
As plans are developed for the required line fill and commissioning of tanks at Hardisty, it is estimated that as much as 4 million barrels will be required over a multi-month period. Again, while this does not add downstream capacity, it will move some barrels out of Alberta and position us to move more quickly into full operation of Line 3 once we're complete in the U.S. Our team is working to develop solutions to utilize up to 40,000 barrels a day downstream of Regina when deliveries are made to the refinery there and a window of downstream capacity is currently unutilized. A plan and timing has not yet been landed on, but it's another example of how we're leaving no stone unturned in our effort to increase throughput on the Mainline system. Talking a bit about Line 3 and where we're at.
As I just mentioned, we expect Canadian construction to be complete by July 1st. Planning is underway for line fill and commissioning. There is a lot going on and a lot of progress being made in Minnesota. The PUC has followed up their verbal approvals of the certificate of need and route permit with written orders. Petitions for reconsideration of the certificate of need were rejected by the commission, and a hearing on Thursday will deal with petitions for reconsideration of the route permit. All of our permit applications to Minnesota agencies have been submitted and accepted as complete. We are actively engaged with agency staff to work through the process and timeline to have the applications reviewed and the permits issued. Tribal cultural survey of the entire right of way in Minnesota is substantially complete. Army Corps and Bureau of Indian Affairs requirements all remain on track.
The upshot of all of this, which we still continue to believe we are going to put Line 3 in service, in Canada and the U.S., by the second half of next year. The Southern Access expansion has been overshadowed by the larger Line 3 replacement, but is an important piece of the puzzle to ensure the capacity restored on Line 3 is not bottlenecked at Superior. The project involves the expansion of Southern Access from 900,000 barrels a day to 1.2 million barrels per day at a cost of about CAD 500 million. The staged expansion of Southern Access has been underway for a number of years now. The project is permitted and the work well advanced to meet the second half 2019 targeted in-service date.
Coming back to Mainline optimizations and talking about them and their longer-term potential, it starts again with the opportunity that we are pursuing to cease the deliveries out of North Dakota into the system at Cromer. The opportunity that we have working on and can create for 2019 will continue into 2020. We continue to work with other customers to try to reach commercial solutions where they will cease their deliveries because we have the opportunity to do a bit more work on the Mainline and ultimately increase that ability to move the barrels out of Edmonton up to 100,000 barrels per day. Drag Reducing Agent is a feature we actively use to maximize throughput on the Mainline today. Our expectation is that further opportunities will be identified to ease bottlenecks and improve throughput through the further use of DRA.
Finally, a successful plan is already in place to access 50 of the 75,000 barrels a day of capacity on Line 4 that we have been looking to restore. Many of you will recall that we have talked historically about 75,000 barrels a day of incremental capacity we are trying to get back to on Line 4. We have found a solution for two-thirds of that. Are actively now working a plan to get at that last 25,000 barrels. Longer term, we have two solutions that can provide another 250,000 barrels a day of incremental throughput. First and foremost, we are going to conduct extensive analysis across the Mainline to determine the optimal mix of DRA usage and pump station design and configuration. It is expected that any changes to pump station design may require regulatory permits, which pushes the expected timeline for when this capacity may be realized out to 2022.
Commensurate with any increase to throughput on the Mainline system upstream of Superior, plans have been identified to increase capacity on Southern Access so that the barrels can get to Flanagan and ultimately the U.S. Gulf Coast. A commercial model is under development that can underpin the reversal of the Southern Lights diluent pipeline and create 150,000 barrels a day of throughput. Looking at the expected timing to execute this project and taking into consideration the diluent market in Canada, we're currently targeting 2023 for this project. Let me wrap up this fairly lengthy review of the Mainline with a few key points. There continues to be a lot of demand from our customers to optimize throughput on the Mainline system and provide the related market access.
In the face of timing uncertainty with respect to competing pipelines in Canada, we continue to execute work plans to keep all of these options alive for our customers. Of course, creating increasing throughput on the Mainline will only benefit our customers if we can provide the market access necessary to get the barrel to the refinery. Market access is already in place for the 100,000 barrels a day of Canadian crude that can replace the North Dakota barrels into Cromer, but to accommodate the remaining 350,000 barrels a day of potential, new options will be required. Fortunately, the build-out of our market access pipelines has positioned us with attractive expansion options that can accommodate the potential volume. The Flanagan South and Seaway pipelines can be expanded by up to 250,000 barrels a day to allow expanded access for Canadian barrels to the Houston Refining Center and potential export markets.
The Southern Access Extension can also be expanded by up to 100,000 barrels a day to increase deliveries into the Patoka market. Opportunity to expand the Express Pipeline has been under evaluation since it became part of our portfolio following the acquisition of Spectra Energy. The plan has now been identified to undertake a combination of pump station work and Drag Reducing Agent to add up to 60,000 barrels a day of capacity, potentially by the end of next year. A range of market access options are available off of Express, and we're seeing strong interest in the potential for this project. The technical solution and a more refined cost estimate are being developed, and we plan to secure the contractual underpinning for moving ahead with this early in the new year.
I'm happy to report that we have entered into a CAD 265 million transaction with Athabasca Oil Corp to acquire the Cheecham area lateral and facilities serving Athabasca's oil sands project in the area. Athabasca is already a long-term shipper on one of our oil sands pipelines, and as part of this transaction, they have entered into a long-term take-or-pay agreement covering the acquired facilities. As the slide indicates, this acquisition further solidifies our competitive position in the Cheecham area and offers the potential to drive additional revenue to our existing operations in the region. I've talked about our confidence in the long-term future of oil sands development, and our asset base is very well positioned to capture growth that we continue to expect.
New capital opportunities for additional laterals and related facilities are expected. Our already in service pipelines have available an expansion capacity that can be accessed at very low competitive costs. In particular, our Norlite diluent pipeline has available capacity that will be able to competitively serve new projects adjacent to its footprint. Similarly, our assets in North Dakota and the basin's ability to deliver into the Platte Pipeline system afford us a range of potential options to consider for future production growth. I've discussed our interest in the Gulf Coast for a number of years now, and we continue to see a strong set of potential investment opportunities in the region targeted at creating new market access, export opportunities, and related services for North American crude and liquids products. While we've been talking about it, we've also been doing something about it.
Today's announcement that we have exercised our option to acquire an interest in the Gray Oak Pipeline means our portfolio now includes participation in 3 pipelines serving the Gulf Coast with up to 2.3 million barrels per day of capacity. These pipelines provide access to the Gulf from key producing basins, including Canada, North Dakota, and the Permian, while also offering export opportunity through the Seaway docks. At the same time, we've been actively developing an offshore VLCC loading project that I'm going to speak to in a minute. Let me move on to talk about that and the Gray Oak Pipeline exercise of our option. We're pleased to have exercised the option to acquire a 22.8% interest in the Gray Oak Pipeline for approximately $600 million.
This asset clearly fits within our Gulf Coast strategy, given its access to multiple markets and a plan to connect to our offshore loading facility when complete. The pipeline has broad supply access, and in our view, will be connected to the highest value markets, thereby providing the Permian producer with the best net backs. The competitiveness of Gray Oak Pipeline's market access, coupled with a competitive toll and strong level of customer commitments, ensures this pipeline will remain competitive and full for a very long time. Enbridge, along with our partners Kinder Morgan and Oiltanking, have been actively developing and marketing an offshore VLCC loading project. Land has been auctioned near Freeport, Texas, for the onshore facilities, and a 40-mile offshore pipeline to loading buoys will facilitate the full loading of a VLCC every 24 hours.
Supply access will be critical to the success of this facility. We plan superior connectivity to key supply basins and storage facilities. It's clearly a competitive environment when it comes to developing export options, but we're confident with our position. We have the capabilities amongst our partners to construct and operate this facility. A plan is in place that targets an in-service date as early as late 2021 or early in 2022. I spent a lot of time talking about our secured capital program and growth opportunities across the footprint of our assets. Before I close, I want to highlight that new capital investment aside, we expect to generate 2%-3% DCF growth per year from the base business.
Considering the potential for additional revenue, toll escalations are embedded in pretty much every underlying toll framework that underpins our asset base. Our strong track record of optimizing available capacity extends beyond the Mainline to our assets in the oil sands and North Dakota as well. Our Mainline toll framework provides incentive for the company to continue to drive higher throughput. On the cost side of things, like all business, we're focused on leveraging technology to improve the productivity of our maintenance, capital, and integrity programs, lower operating costs, and manage our power consumption. To wrap things up, I want to say again, we're excited about the future and our ability to continue to grow the liquids pipelines business.
We operate the premier liquids pipelines assets in North America, we're confident in our ability to complete our secured projects as planned, extract growth from the base business, and secure attractive new capital opportunities of CAD 2 billion per year, post 2020. Thank you for your attention, I'm happy to take any questions.
Jeremy Tonet, J.P. Morgan. Guy, thanks for all the details here. Was just wondering, as you think about the product getting out of Western Canada and wanting to get down to the Gulf Coast, how you guys could participate in that and more. It seems like there's been more talk about a Capline reversal and just wondering if you had anything you could share there as far as if that's something that you could take a part in. Could this all be wrapped into some type of joint tariff in the CTS? Is there bigger plans here to really move significant barrels down there?
Yeah. There's a number of questions there. First thing, we will be looking at using joint tariffs. Joint tariffs are what underpinned our current new construction of Flanagan South and the Seaway path to the Gulf. A joint tariff would be implemented again there with our plan on Flanagan South. Really the issue, we continue to hear messaging, sometimes positive, sometimes negative, always a little bit mixed, about the status of a Capline reversal. To the extent that it does emerge as something real, it is absolutely something that we would look at doing and trying to work together with them on. I think at this stage of the game, we have to stay focused on that which we can control. That's why our focus right now is on expanding our own market access, being Flanagan South and Southern Access Extension.
I think, if in fact it is a Capline reversal that makes sense for industry down the road, it is going to require a pretty significant chunk of capacity that needs to move. We will just have to wait and see how that plays out.
Just want to follow up on Southern Access there. I was wondering, how much more could that pipe be expanded before it needs to be twinned? Is there much pumping capacity that could be left if you could just kind of
We are expanding it now to 1.2 million barrels a day. If we get into the gory details of the math of these various auctions that I talked about 175,000 barrels a day of that 450 will need to find its way down Southern Access to Flanagan. We have identified a plan that we think we can execute on the current system to optimize the operation of that to access that capacity down the road.
Tom Abrams, Morgan Stanley. Where along the Trans Mountain project would you entertain remotely getting involved with that?
Well, let me start by saying we're not involved in that, have chosen not to try to get involved in that. I think it's something we'll continue to monitor. Clearly that project is in a stage of requiring de-risking, and its current owner may be the best owner through that de-risking period. We'll just have to see how that plan pans out and whether there is a point in time when that becomes interesting to us or not. I think we're confident that we have all kinds of growth opportunities absent that within our business unit and across the rest of the organization. Should something come available there, it will be a very interesting capital allocation conversation.
Thanks, John. Pat Kenny, National Bank. Guy, just in light of Alberta's production cuts, clearly in part designed to protect the smaller producer, how confident are we that regulatory or political risk won't threaten the ability to offer up priority access for 90% of the Mainline?
Well, we're highly confident in it. First off, there is precedent already in Canada. The Trans Mountain system itself went from a common carriage to a hybrid contract, a spot shipper system like what we're proposing. Obviously, the Keystone systems are contract capacities with reservations of spot capacity, we're leveling the playing field. I think probably more importantly, maybe to the heart of your question is, we're making it very easy for producers to submit an application and participate in the open season. We've set a very low threshold for minimum volume requirements that people need to come onto the system. While I'm not really going to get into exactly how we've customized the offerings for producers versus refiners and whatnot, we think we've come up with something that makes sense for a lot of them.
We have the advantage right now where we're looking to contract a system that's already built. That gives us a lot more flexibility in how we approach it, as opposed to needing to secure the underpinning to build it new. We're taking advantage of that flexibility.
Praneeth Satish, Wells Fargo. Can you talk about the regulatory milestones that you'd have to achieve to reverse Southern Lights? If you do, would you need the consent of the existing shippers on the line? What are their alternatives if Cochin also gets reversed?
First off, yes, we need the consent of our existing shippers. We've had a lot of discussions with them already and have gone to the stage now where the discussions have gone beyond, do you think this is a good idea, and if so, when, to, okay, let's start thinking about what's the commercial structure of the deal that you have to put together to cease deliveries on that line, take it out of service for a period while you do the work, and then put it back into service. That's where we're at, is developing that commercial underpinning. In terms of the permitting requirements, there will be some.
We don't believe they're going to be extensive, primarily because we don't need to do anything with the presidential permit at the border, which is great, and we actually won't be making substantial changes to a lot of the pump stations, which will have an implication on the level of permitting that you might need in any of the states.
Thanks, guys. Just as you think about the timing on CTS and the 2019 discussions, even as we solve the nomination process, you have a pretty fractured shipping group. Given that you plan to file in 2019, is that a sign that just given the regulatory process and how contentious that might be, that you don't expect to get to something unanimous?
No. In fact, we've been talking to this group, to our customers for quite a while about a range of options as to how we would approach dealing with the tolling framework beyond 2021. I think a lot of people have in their minds that somehow priority access is a leverage point with the current situation around priority access. If you think about what's really driving the customers on our system, they've been talking priority access for a long time because they see other priority access pipelines coming into the market, and they're going to be competing to buy barrels on our system versus these other contract pipelines. If you're a shipper on Flanagan South who has a downstream contract, apportionment stuff aside, you want to link up your Mainline with your downstream. That's been their position for a long time.
If you're a refiner on our system, you want to be on a level playing field to buy barrels at Hardisty with barrels that are being sourced to go to either the Gulf on a competing pipeline or to the West Coast on a competing pipeline. A lot of these guys, we know the investment that's gone into the oil sand side of things. Sometimes we lose sight of the investment that's gone in on a refinery. If a refiner's invested CAD 5 billion, CAD 6 billion, CAD 7 billion into their refinery, they want to know that if they want a barrel of capacity off of Enbridge, that they can get it. The need and the direction has been set well in advance of the current level of increasing apportionment. That's really been the driver.
Where I'm going with all of this is the timing is not because we expect a long, drawn-out regulatory process that threatens 2021. We're doing it because people want to have that certainty.
Do you need to hold a binding open season ahead of the NEB filing, or are you going to try to get that approved and then take it to an open season?
The process will require an open season. We would probably do it before we filed at the NEB.
Okay. Thanks, guys.
Linda Ezergailis, TD Securities. You've given us an outlook for what you expect from a DCF continuity perspective in your liquids pipelines, implying not a huge reset on CTS. Can you give us an understanding of kind of the scope of what's in and out on some of your expansion initiatives and the capital required there? Would that be kind of a separate deal, or is that all rolled into the new CTS? Can you give us an understanding of what's in and out?
The way I think about it, Linda, is we're moving towards a contract framework for our mainline. One of the benefits of doing that is that same framework then provides the underpinning to continue to expand the system. We're looking at whether it's the existing system and the 3 million barrels per day, or it's those increments, particularly where we need to add new capital into the Flanagan South and Southern Access to do the expansion. We're going to want to have those underpinned by contract.
Okay. Just as a follow-up, up to 20 years is a long time.
There can be a lot of unforeseen changes on the cost side, et cetera. Would your contracts have some sort of pass-through mechanisms for unexpected environmental costs or other things, like tax changes or anything like that?
Well, I don't know that we'll go to tax changes.
Yeah
I think certainly in our environment, there will have to be some protections in there about significant regulatory change that would dramatically impact the cost structure, say, around pipeline integrity or something like that.
Okay. Thank you.
Andrew Kuske, Credit Suisse. Guy, let's just go with the scenario that we're in 2022, and a lot of the egress issues are already resolved. You've got projects like Imperial Oil with Aspen. Do you see a potential rush of other projects, given the greenhouse gas emissions cap that exists in Alberta today? That might change, but let's just assume there's something. Do you foresee a rush of projects trying to hit the window with improved technology to try to get under the gas emissions cap?
Yeah. When I think about the situation, as best as we can see it, because we're not a producer, obviously, the egress is front and center right now, and we plan to be part of being the solution to that. You've talked about some of the improvements that the oil sands producers have made. I've talked about them. We do know that there are other competitive issues that the industry is facing. For example, is Bill C-69 going to find its way into the development of any other projects or not?
I think in terms of the competitiveness angle for Western Canada, I think we've got a really good line of sight on the timing of two of them, and as long as that third leg of the stool around the overall competitiveness of the Canadian barrel is improved, I do believe we're going to see some movements very quickly. We know that larger producers are not just sitting on their hands as it relates to these other projects, that there has been a tremendous amount of work done, and they've been brought along to certain stages where when the timing gets right, that they can move more quickly. We feel pretty good about the outlook.
Hi. Robert Hope, Scotiabank. Can you update us on whether or not you've had any discussions with the incoming governor in Michigan and the potential for the Line 5 tunnel? I would guess more broadly, just how you're dealing with stakeholders on your existing rights of way to ensure that they remain valid.
Yeah. Okay. Well, I'm going to start with the second part first. We made a decision about three years ago, I think, within liquids pipelines to take a different approach to stakeholders across our right of way. What we've done is we have six operating regions. We've made the leadership in each one of those operating regions responsible for the stakeholder relationship plan that we have to have in their area, recognizing the uniqueness of all of them, and we're leveraging those to the greatest extent possible. I think our success in Line 3 in Minnesota to this stage is testament to exactly the strength of what those relationships and coalitions can bring to the table. Really, we're trying to get through the stakeholders at the grassroots level as to how we're going to manage going forward.
To the second point of your question on Line 3, we've not had any active engagement with the incoming governor just yet. We're really quite pleased with where we're at on Line 5. We know Line 5 is an integral piece of infrastructure for the state of Michigan. They commissioned a study of alternatives and determined there's not a lot of alternatives to Line 5. The pipeline and the products that it brings is needed. We know Line 5 is safe. I tell everybody who wants to know the answer, I would love to have the pipeline that is in the Straits of Mackinac on every inch of our system today. I would take it. It's in really great shape. It has more integrity focus probably than anywhere else in our system, probably anywhere else, possibly in North America. We've committed to do more. We are doing more.
The pipeline is very safe. Having said all of that, we do believe the potential to build a tunnel is the right thing to do for the long term, the Straits of Mackinac, and we're moving ahead with that. We've already put in place the capital for next year to do the geotechnical work and detailed engineering. That will lead then into the final design and how we move forth. We believe in this. We believe that it's the right thing for ourselves. We believe it's a great project for Michigan in terms of securing the energy needs that they require for the long term and a CAD 500 million opportunity in Northern Michigan that it'll bring jobs. We think it's a great opportunity, and we're moving forth. Okay. Down here.
Sorry. Last quick one here. We got to keep the schedule.
Frank Bamberger, FBA Asset Management. Question: Do you have any pipelines in the metropolitan area within 50 miles of New York being built or existing? Are there any environmental challenges you have?
The answer is no. We do operate adjacent to many metropolitan areas, not New York City, however. Certainly, we approach the way we operate near metropolitan areas with a much higher level of scrutiny than in other parts of our system. It's a function that we've been around for a long time as our pipelines, and communities have tended to continue to get closer to us than they used to be. It is a bit of a challenge, probably for us and probably for Bill's team as well as growth and encroachment takes away some of that buffer that you've had historically. We'll hand it over to John for the finance section.
Thanks, Guy. Good morning, everyone. It's been great to be back after what's been a very busy year. You've already heard a lot from Al and the executive team on our strategy and the great set of opportunities we have in front of us to continue to grow and deliver value. I'm going to take a little time in my segment today to drill down a little bit deeper in some areas with respect to our business risk and financial position and our go-forward financial design. I'll also touch on our guidance for 2019 and update our current outlook for 2020 before moving on to review in more detail our approach to capital allocation and why we believe we can readily deliver 10% DCF per share growth through 2020 and 5%-7% post-2020, all on a self-funded basis.
If there's an overarching message from me today, it would be that Enbridge's financial strength and flexibility is better than ever, that we're extremely well-positioned from a financial perspective as we head into 2019. That, of course, has a lot to do with the actions we've undertaken over the last year or so. This first slide provides a little bit of a recap from a finance-centric perspective. Since around this time last year, we've raised more than CAD 8 billion of long-term capital, of which close to CAD 4 billion was in the form of common equity or equivalent hybrid equity funding. With the sale of Enbridge Gas New Brunswick last week, we now have announced close to CAD 7.8 billion of non-core asset sales. About CAD 5.2 billion is already closed, and the remainder will close in 2019.
Proceeds have largely been applied to debt reduction and further strengthening of the balance sheet heading into the new year. These asset sales not only accomplished a reduction in the company's business risk profile, also enabled an acceleration of de-leveraging, allowing us to achieve our longer-term target range earlier than we'd planned. We've continued to drive out synergies and cost savings post the Spectra combination, we've also taken a number of significant steps to simplify the company's funding structure, which will enhance consolidated earnings and cash flow to equity and debt holders of the parent company and improve our consolidated credit profile. The impact of these actions to strengthen our financial position, together with strong operating and financial results, have allowed us to suspend the DRIP earlier than planned. As you've heard, no additional equity is required to fund our currently secured growth capital program.
While we've done a lot to enhance our financial position, the same priorities that drove our actions over this last year will continue to guide us in the future. This slide translates those enduring priorities into key focus areas for implementation over this next planning cycle. Preserving financial strength and flexibility to ensure that secure growth can be readily funded. Maintaining strong investment-grade credit ratings to ensure access to debt capital on the best possible terms. Hedging, where practical, any residual foreign exchange risk, interest rate, or commodity price risk that hasn't already been eliminated contractually. Maintaining a sharp focus on capital allocation as the amount of free cash flow generated by our core businesses continues to grow. Continuing to simplify the business as we look to optimize our overall cost of capital.
All of this, of course, for the goal of continuing to deliver highly reliable and predictable financial results. I think it's important to pause for a moment on the commercial foundation, which supports our low-risk business model, which we believe is a real differentiator. Post the Spectra combination, the scale and scope of our business has grown significantly. We're now really very well-diversified across energy basins, commodity types, and regulatory jurisdictions. Looking at the combined company post the asset sales, over 98% of estimated EBITDA in 2019 will be generated from long-term take-or-pay contracts, rates or tolls derived from cost of service formulas or fixed-fee arrangements that incorporate downside volumetric protection like our Liquids Mainline competitive tolling settlement. The contemplated contracting of the Canadian Mainline that Guy just talked about would serve to further strengthen that profile. The customers that pay our tolls are also highly creditworthy.
If we take a snapshot after the most recent asset sales, over 93% are now investment-grade, and the small proportion that aren't are well-diversified and very closely managed. It's also noteworthy that a large proportion of the rates and tolls that drive revenue in our business are protected by inflation escalators or other adjustment mechanisms which mitigate the impact of rising operating and/or interest rate costs. More than 70% of revenue is derived from contracts and toll frameworks that include such features. All of this adds up to one of the very strongest business risk profiles in our sector, which both Moody's and S&P continue to acknowledge in their assessment of Enbridge's overall business strength.
We think it's best in class, and it's getting even stronger. While we aren't able to contract away through tolling agreements or supply arrangements, we proactively hedge residual exposure to foreign exchange rates, interest rates, and commodity prices. As a Canadian dollar reporter, exposure to the U.S. dollar arises from both U.S. dollar-denominated tolls on our Canadian assets and through the income and cash flow generated by our U.S. subsidiaries. As of today, about 85% of earnings and 60% of distributable cash flow has been hedged for 2019 at a rate of approximately CAD 1.22 to the U.S. dollar. We're also substantially hedged against rising interest rates. The current ratio of fixed-rate debt to total debt, I should say, is over 85%, and about 70% of the underlying benchmark on term debt planned for next year has also been hedged.
I'll provide some sensitivities on that later, but as you can see from this slide, FX and interest rate exposures are closely contained. Direct exposure to commodity prices is immaterial post the sale of our G&P assets, so overall market price risk is very low and extremely well contained. Consolidated cash flow at risk, which is basically the impact of a two standard deviation movement in prices after taking into account correlation across exposure types, is not significant. Less than 2% of 12 months forward DCF. I think this slide really speaks for itself. The stability of our low-risk businesses and our ongoing focus on risk management has clearly served us well historically. We've continually driven out steady and reliable growth year after year, notwithstanding broader industry downturns and financial market volatility.
Through all of this, we've consistently achieved our annual guidance in the face of industry headwinds and tailwinds. With the risk profile of our core asset base getting even stronger, our ability to deliver the reliable results that the market has come to expect is better than ever. Even as we shift to a self-funded approach, we will look to optimize our overall cost of capital. The maintenance of financial strength and stability, as I said, and ongoing access to capital on the best possible terms will continue to be a priority. Our financing plans have been designed to steadily and deliberately bring down leverage and strengthen our balance sheet, even while funding well over CAD 40 billion of capital projects over the last five years.
The capital that we raised this year, together with proceeds from asset sales and strong financial performance from the business, has allowed us to further accelerate de-leveraging and exceed our targets for 2018. As of Q3, our consolidated debt-to-EBITDA ratio had fallen to 4.7 times on a trailing 12-month basis, and we'd expect to achieve a similar result for the full calendar year. That's a reduction of more than two multiple turns since 2014, notwithstanding the very significant growth we've funded over the same time frame. We continue to believe strong investment-grade credit ratings are central to Enbridge's value proposition, and our funding plans and risk management policies support that objective. We've been in regular contact with the agencies to review our plans and projections and the implications for our credit risk profile and credit ratings.
While I can't speak for them, you can see from their update reports that they view the recent strategic actions and the go-forward prospects for our company very favorably. S&P, Fitch, and DBRS have all reaffirmed their current ratings at BBB high or equivalent. More recently, after the release of our third quarter results, Moody's announced that it had changed its outlook on its current Baa3 rating to positive. We think the combined business and financial risk profile of Enbridge is one of the very best in our sector and warrants strong investment-grade credit ratings across the board. It's nice to see some positive feedback coming from the agencies after the actions we've taken this year, and we hope to see more positive developments in 2019. Simplification has also been a big priority since the Spectra deal, there's been a lot underway on that front.
As you know, we've a number of initiatives underway to reduce the complexity of our corporate structure, with the objective of increasing the transparency of cash flow to equity and debt holders of the parent company and improving the overall cost of capital for the Enbridge group. In June, we announced the proposed buy-ins of four publicly traded vehicles, that process is ongoing but progressing well and according to expectations. The buy-in of Enbridge Income Fund Holdings Inc., as Al mentioned, was completed in early November, and the SEP buy-in will close in late December. The buy-ins of EEP and EEQ still remain subject to the completion of a proxy solicitation process, which is underway and will culminate in a unitholder and shareholder vote, which is currently planned for next week.
In addition to reducing overall complexities, the buy-ins generate a number of very tangible benefits, including increased cash flow at the parent company, a lower consolidated payout, lower ongoing administrative and operating costs, and tax benefits which have the effect of extending the company's low taxability horizon post 2020 by at least two years. Importantly, the buy-in of these vehicles also provides an opportunity to further simplify our debt funding strategy and strengthen the credit profile of both the parent company and the consolidated group. We'd already taken some action in this regard with the repurchase and redemption of virtually all of the outstanding bonds issued by Spectra Capital and the redemption of Midcoast Energy Partners' debt, both of which eliminated a layer of structural subordination. We also announced the discontinuation of additional funding by Westcoast Energy Inc., another intermediate holding company within the broader Enbridge group.
The sponsored vehicle buy-ins will really enable us to simplify the debt structure and address structural subordination in a much bigger way. To that end, we have or will be undertaking several actions. Firstly, following the closing of the buy-in of the public interest in Enbridge Income Fund in November, we sought approval from holders of Enbridge Income Fund term debt holders to exchange their outstanding notes for notes of Enbridge Inc. with otherwise equivalent terms. I'm pleased to confirm that the required majority of bondholders voted to approve this exchange, which is now expected to close before the end of the year. With the exchange completed, we won't be issuing any external debt out of the income fund going forward.
Secondly, while existing term debt will remain outstanding at both EEP and SEP until it matures or is redeemed, we also don't plan to issue any new term debt to third parties from those entities. Finally, we're also planning to implement a cross guarantee structure, whereby any outstanding term notes of SEP and EEP would benefit from a downstream guarantee by Enbridge Inc., while EEP and SEP would, in turn, each provide an upstream guarantee on Enbridge Inc. term debt. If completed, these cross guarantees would effectively make the term debt obligations of SEP and EEP pari passu with Enbridge Inc., and eliminate another layer of structural subordination. To be clear, we don't plan to launch the process to implement the cross guarantees for either SEP or EEP until the buy-ins for each of those entities are successfully completed.
Going forward, the operating and capital requirements of our regulated subsidiaries will largely be met through intercompany funding provided by Enbridge Inc. That said, I would note that a few of our subsidiaries will continue to maintain credit facilities and raise term debt in external markets, and the key ones are listed in the footnotes to this slide, and they include Enbridge Gas Inc., that's the soon-to-be amalgamated distribution utility that Cynthia just spoke to, Enbridge Pipelines Inc., Texas Eastern Transmission, and some of our other FERC-regulated natural gas transmission pipelines. What drives the funding plan on our financial outlook going forward? Primarily, we'll look to the metrics and targets shown on this slide. Consolidated debt to EBITDA of between 4.5 and 5 times, and FFO to debt above 13%. A dividend payout ratio of about 65% of DCF.
Sufficient bank lines to ensure that we always have more than one year of liquidity for contingencies and to manage through financial market disruptions. Floating-rate debt of not greater than 30%, and a cash flow at risk metric of less than 5% of 12-month forward cash flow. Achievement of these metrics should ensure we maintain the strong investment-grade credit ratings I spoke to earlier. It is important to note the leverage targets shown on this slide are based on management's calculations of these ratios. Each agency makes different adjustments to our reported numbers in their determination of these metrics. In developing these planning parameters, we've looked to ensure that we'll ultimately exceed or meet the specific metrics that each agency has established to achieve our target ratings.
Leverage has no doubt received a tremendous amount of focus of late, it may be worth elaborating a little on how we plan to manage it going forward. In developing our capital spending and funding plans, we'll always look to keep debt to EBITDA comfortably below 5 times post-2019. Consolidated leverage will likely average closer to 4.5 times or possibly below that level, depending on the size of the capital program at the time. The ability to flex closer to 5 times will allow us to accommodate any funding drag associated with greenfield projects that have longer lead times, where interest costs on the debt we incur to fund construction are not immediately offset by incremental EBITDA. Before getting to guidance, let's have a quick look at the currently secured capital growth program.
We've included projects completed in 2018, because a large number of these were brought into service in the latter part of last year and will be significant contributors to year-over-year EBITDA and DCF growth next year, in addition to the new projects that we expect to bring online in 2019. While volume ramp-ups and toll inflators will also contribute, it's this diversified suite of low-risk projects that is expected to drive highly transparent growth through 2020. Turning now to our financial guidance for 2019 and focusing here on adjusted EBITDA for each of our business segments. At Liquids Pipelines, EBITDA is expected to grow due to higher anticipated volumes in the Bakken system and the scheduled completion of the Line 3 Replacement Project, where for forecasting purposes, our models still assume a November 1st in-service date.
Gas Transmission will deliver a higher EBITDA, primarily on the strength of the larger transmission projects that were recently completed that Bill mentioned and will make a full year's earnings contribution and DCF contribution in 2019. As noted, the incremental contributions from these newly built assets are partially offset by the loss of EBITDA from the U.S. and Canadian G&P assets that we sold earlier this year. Gas Distribution EBITDA will also grow, driven largely by the synergies that are anticipated from the amalgamation of the Ontario utilities. EBITDA from Green Power will grow on the strength of new projects placed into service, notably the first phase of our German offshore wind power project, which is expected to commence operations in Q3 of next year. Energy services is also expected to make a solid EBITDA contribution, given actions already taken to lock in attractive location differentials on a forward basis.
Finally, elimination and other should come in better than 2019, largely due to a stronger average FX hedge rate and ongoing cost management initiatives. I would note that our estimates of EBITDA contributions from each segment clearly do have the potential to vary from the point estimates provided here, but in most cases, the variability is not expected to be large given the stability of the underlying businesses. That CAD 13 billion of EBITDA in 2019 is expected to translate to bottom-line DCF of about CAD 8.9 billion after estimated maintenance capital, financing costs, cash distributions in excess of equity earnings, and payments to any remaining non-controlling interests. You can think of the estimates provided here as the midpoint of a potential range of outcomes for each of these line items, which, when taken together, translates to bottom-line DCF, a DCF range of approximately CAD 4.30 to CAD 4.60 per share.
I'd point out that our 2019 per share guidance range is right in line with what we provided last year, and that's despite the impact of selling significantly more assets than we originally contemplated and the near-term dilutive impact of the shares issued in connection with the buying of our sponsored vehicles that were not accounted for in last year's guidance. We managed to mitigate these impacts through improved performance in our core businesses and significant effort by our teams to generate cost savings and efficiencies post-Spectra. As I noted earlier, we've substantially hedged FX and interest rates. However, we do remain exposed on unhedged amounts, and you can see the sensitivities on this slide.
A sustained one-cent move in the Canada-U.S. exchange rate would result in a little over a CAD 0.01 move in the projected 2019 DCF per share, while a sustained 25-basis-point move across the yield curve would have an impact on DCF of less than a half a CAD 0.01 per share. So again, pretty close contained there, and we'll continue to be proactive in trying to manage these residual risks throughout the year. Today's spot FX rates and interest rates are a little better than what we'd embedded in our projections, which provides a little bit of additional positive momentum for the outlook heading into the new year. We've also shown our current outlook for 2020 on this slide, and at CAD 4.85 to CAD 5.15 DCF per share, our guidance range is unchanged from last year.
The big driver here, of course, is the 14% year-over-year EBITDA growth, primarily driven by the impact of a full year's contribution from the Line 3 Replacement Project, other projects going into service, and ongoing strong performance from the base business. I'm not going to dwell for very long on this slide. It's really here as a reminder that our earnings and cash flow are not generated evenly over the year and will have a distinct quarterly profile due to a few factors. The seasonality of our utility and interruptible gas transmission businesses, which typically generate much higher earnings and cash flow in the first and fourth quarters and undertake a higher proportion of their maintenance capital in the second and third quarters.
The seasonality of revenue generated by our renewable power generations, and of course, the timing of in-service dates for capital projects, which will also impact the profile of quarterly financial performance in any given year. As Al and the executive team have laid out today, we see plenty of opportunity to generate very solid, low-risk growth beyond 2020. We believe we can readily grow the business without compromising our risk profile through greenfield and brownfield extensions and expansions of existing systems, as well as selective asset acquisitions where it's more practical and/or more cost-effective to buy than to build. As Al said, we'll be applying a very disciplined screening process, and you can see that illustrated here on this slide.
We're going to look to pare down a big bucket of opportunities to a much smaller, high-graded list of investments that are aligned with our strategy, can be readily self-funded, and will generate the biggest bang for our buck from both a near-term accretion and a long-term value perspective. The slide, again, is illustrative, but it should give you a feel for the process. Importantly, before capital is committed to any project or group of projects, we'll always take stock of our broader outlook and compare and contrast the anticipated value created by the investment opportunity with other capital allocation choices, whether that be debt repayment, a change in the dividend payment, a payout rather, or share repurchase. Currently, our focus and preference is to pursue organic growth where it aligns with strategy and fits our risk profile, as long as it very clearly adds value.
Given the magnitude of the larger opportunity set within our core businesses, we think this will generate something in the range of CAD 5 billion-CAD 6 billion of high-graded investment opportunities per year on average post-2020. That's not really hard to imagine on a consolidated asset base of close to CAD 165 billion. The next question might be, can you really self-fund that CAD 5 billion-CAD 6 billion of assets every year? What would that translate to in terms of a longer growth rate? The rough math on this slide is intended to answer that using our public guidance and assuming the planning parameters that I talked to earlier. Let's start with what we already know. By 2020, we will be generating about CAD 10 billion in free cash flow after maintenance capital and before dividends.
That's CAD 5 per share times roughly 2 billion shares issued and outstanding. We expect our dividend to grow again by 10% next year, so the total annual dividend paid in 2020 will grow to approximately CAD 6.5 billion. That leaves about CAD 3.5 billion of free cash flow to reinvest in the business. Importantly, the investments made with this free cash flow will themselves generate incremental EBITDA, which in turn will create additional debt capacity on the balance sheet. In this example, I've assumed we can lever that newly created EBITDA at 4.5 times, the bottom of our go-forward target range. The reality is not all of that EBITDA will be generated immediately upon investment, particularly if it's a greenfield project that we're talking about. In that case, we might expect debt-to-EBITDA ratio to creep up towards the higher end of our target range.
On the other hand, if it was an immediately accretive asset acquisition, that wouldn't be the case. For the sake of this example, we've assumed a 4.5 times would create incremental debt capacity of about CAD 2 billion, depending on the investment multiple assumed, bringing the total amount of capital to invest to somewhere around CAD 5.5 billion. For the sake of this simple example, and to be conservative, we've shown a case where investments on the available capital are made at an EV to EBITDA multiple of 9 times and 8 times.
We've left out a couple of steps here, if you take the EBITDA generated by this available capital, then subtract off maintenance capital, interest expense, and current taxes, which are expected to be low over our planning horizon, you should get to incremental DCF in the range of CAD 445 million-CAD 510 million, or about CAD 0.22-CAD 0.25 per share. Keeping in mind our estimate of CAD 5 per share in 2020, that translates to 4%-5% incremental growth generated through new investment. Our revised long-term forecast indicate that our base business should grow on average between 1%-2% organically through a combination of toll inflators, throughput optimization, and ongoing cost efficiency initiatives.
If you put this together with the growth generated from incremental investment, you come up with a range of 5%-7% growth, that is without any incremental equity and without eroding our credit metrics over the longer term. Essentially, sustainable, self-funded growth. Bringing it all together. Hopefully, my remarks have provided a little more color on how our strategy and plans will drive the financial outlook over the next few years. In summary, we see highly transparent compound annual average DCF per share and dividend per share growth of 10% through 2020, driven by the execution of a very well-advanced, commercially secured capital program. Readily achievable, self-funded DCF per share growth in the range of 5%-7% post-2020, generated from a very attractive suite of low-risk investment opportunities and solid underlying growth from the base business.
I'm going to wrap up here where I started off by pointing out that from a financial perspective, we really are extremely well-positioned. Looking forward, we won't be as focused on capital raising as we have been in recent years. We think we have plenty of capacity to grow at an attractive rate without raising any new equity, an increasing proportion of our debt issuance will be for refinancing. We will continue to be driven and guided by those enduring financial priorities that I went through at the beginning of my presentation. Preserving financial strength and flexibility to ensure we can execute the strategy and continue to add value through all market cycles. Maintaining access to low-cost capital as we look to refinance maturing debt. Managing controllable risk and proactively hedging exposures we can't otherwise contract away.
Simplifying and optimizing existing financing to ensure the best possible cost of capital. Continuing as always to drive out the attractive, reliable, and predictable results that our investors have come to expect. With that, I'd be happy to stop and take any questions on the finance side that you might have. Andrew.
Andrew Kuske, Credit Suisse. Probably an easy one to start off with, just on the streamlining. You've had a few slides on streamlining.
Yeah.
You mentioned a DCP. How do you think about the longer-term outlook for DCP from an Enbridge perspective?
Yeah.
In particular, with the crystallization of the tax consequences coming off the roll-up of the U.S. MLPs.
For the moment, and Al may want to speak to this one as well, I think DCP we wouldn't put right in the middle of our core business. On the other hand, I think we've been quite happy with the way it's been performing with their approach to risk management in particular, which has taken a significant amount of the variability out of that business, and so we're reasonably comfortable with it at this particular point in time. Our plans don't assume anything, and the plans I presented don't assume anything with respect to DCP other than that we continue to hold it.
Over here, John, Tom. Oh, Greg.
Hey. Dan Longo, Bank of America. Just one thing that's noticeably absent from your financing strategy this year is hybrid capital. Could you just talk to how you guys are thinking about hybrid capital going forward?
Yeah. I think with respect to hybrid capital, we viewed it always as an efficient form of equity capital, a lower cost form of equity capital when compared to a combination of senior debt and common equity. In our current plan, where we've raised so much through asset acquisitions and so on and so forth, it doesn't call for a lot of incremental capital right now. Our financing plans are primarily focused on the issuance of senior debt and a good chunk of that really just to refinance maturities as they come due.
Hi.
Hi.
Dennis Coleman with BofA. Hi. One thing we didn't cover today, John, is the renewables piece. As recently as in November, you're talking about a CAD 5 billion-CAD 10 billion opportunity there. I wonder if you could just layer that on to the rest of what we talked about today.
I think renewables, it's one of those businesses where the business model fits very well with what we do, the way we're approaching renewables, which is long-term, highly contracted assets at the end of the day. That probably applies more to offshore in terms of the risk-return profile than it does to the onshore business, where we've seen a tremendous amount of competition. In fact, we thought we got very good value for monetizing a portion of our onshore earlier this year. We'll continue to explore that business, I think try to build it if there is opportunities to invest with a value proposition that we like. From a finance perspective, it's got to meet all of those hurdles that we talked about in terms of risks, contractual profile and so on and so forth.
Hi, Robert Hope, Scotiabank. If we go back a year ago, it seemed like the focus was delevering, and now today the focus is on growth. Taking a look at the project execution funnel that you have there, would it be fair to say that you have a lot of projects in the hopper that you're de-risking relatively quickly, so we could see 2019 to be more of a heavy project announcement year?
I think if you looked at the plan, I think you could see announcements. The spend and the build-out of a lot of these projects, I think really shows up in 2020 and beyond in our plan. You don't see a big impact financially in 2019, Robert.
Just a more theoretical question. Taking a look at the 5%-7% growth, that includes 1%-2% on the base business. If projects don't show up and you are shrinking your balance sheet, is that a 3%-5% growth rate?
If projects don't show up and we're shrinking our balance sheet?
Yeah, by a fair share.
I think if projects really aren't showing up, we may be looking at some of those other capital allocation alternatives that you talked about, in which case, I don't think our growth profile on a DCF per share basis would necessarily change.
Thank you.
Got one in front of you, John.
Oh. Sorry.
No worries. Thanks, John. Linda Ezergailis, TD Securities. Can you give us a sense over the long term, maybe post CTS renewal, 2022 plus, what your FX composition would be, either on a sensitivity basis or what % EBITDA would be U.S. dollars, and how you think about what the tipping point would be when you would become a U.S. dollar reporter, and when that might make sense versus hedging?
Yeah, that's a great question. I think at this particular stage, we are a Canadian dollar reporter. We have no plans to change from that at this point in time. I think you'd have to see something more profoundly directional show up in our plan before we would look to shift that. I think the sensitivities, Linda, would not be we'd continue on with a similar type of hedging structure, if we were aligned roughly the way we were in terms of the split of our business between Canada and the U.S. Obviously, it's something that we would continue to evaluate over time, and it'll be informed by the direction ultimately that our plans take us.
Thanks. John, I apologize if it's been slipped in somewhere, there's a lot of talk of 5%-7% post-2020 on DCF. Can you just talk about what you see that meaning for the dividend?
Well, that's a great question. I think Al talked about it right up front in his opening remarks. As a general principle, we probably see the dividend roughly growing at the same rate that we'd see the DCF per share growing at, watching earnings per share as well while we do that. On the other hand, if it's clear that we're not deriving value from the rate of growth that we're applying to dividends, we'll look at some of those other capital allocation opportunities or consider whether the growth rate's appropriate relative to other uses of our capital going forward. We'll keep that in mind as we go through that. As a general principle, though, we'd be looking to grow it in line with DCF growth.
Just turning to hedging, I think there's a disclosure that the FX for 2019 is hedged at 122. Can you just talk about when you get in a lot closer to where spot is?
Yeah, sure.
The second part is just on the interest rate hedges. Have you hedged the underlying base rate only, or have you also managed to hedge the spread into total issuance?
Good questions. It'll take a while to see our effective hedge rate, to answer the first part of your question, creep up towards spot. You will have noticed it over the last couple of years creeping up fairly significantly towards spot, and it will continue to do that. Over this next couple of years, that average rate that I gave you is probably pretty indicative of where it will be. On the interest rate side, we've only hedged the underlyings and not the spread. It's pretty hard to effectively spread the hedge. Try that again. Spread the hedge. Hedge the spread in most markets. Good news is our spreads have come down quite significantly.
John, even though the era of financial engineering has come to an end, I'm just wondering if you see any other opportunities on the fringe
To perhaps augment that 5%-7% DCF per share growth rate beyond 2020?
Yeah. We're always going to look at ways to optimize our cost of capital. We're very convinced that undue complexity is not a value driver. There has to be some very compelling reason. Frankly, we're not looking at anything in our plans that you saw don't include any of that sort of thing. We do have arrangements with funding partners. Those are well-established in their typical joint ventures. That's about all you're going to see.
Hi.
Hey, John, Jeff Hewitt at Guardian. Our question is looking at the DCF per unit versus just looking at DCF directly. Is this sort of more in line with equity messaging throughout the industry, or are you looking ahead at potentially reducing the unit count?
Well, I think if you're talking about would we look to buy back shares at some particular point or an action like that, I think it gets back to some of those opening remarks that Al had. First and foremost, we would look to grow through our traditional source of businesses and primarily through organic growth. If we're not seeing the value-add opportunity there, I don't think we'd hesitate to look at it, but it's got to add value, not just in the immediate term, but perceived to be adding value for the long term by doing that. It's got to be sustainably accretive, if you like, if we look at an action like that.
If it could be for a follow-up, do you think right now, the industry is rewarding dividend growth, or are they really looking for starting to see buybacks?
I think you're seeing a push. It's not rewarding dividend growth, clearly, at least we would certainly argue that at the particular point in time in the current market anyway, and we've seen markets ebb and flow over the years, definitely. I think for buybacks, there may be a pocket of the investor community looking for that, although I think what they're really looking for is a catalyst, something to get the stocks in the sector back on track more than anything. From our perspective, we want to make sure that it's sustainable over time, that we're actually doing something that's going to add value for the long run if we take that approach.
Hey, John. Michael Lapides of Goldman Sachs. Just looking at the 2020 EBITDA projection, you put out the CAD 14.8 billion. Can you walk us through what's the bridge from 2019 to 2020? Meaning, that's a pretty big year-over-year step-up. Is that almost all Line 3? If there are other really big components of it, can you just walk us through high level what those are?
Yeah. Biggest chunks, quite frankly, are Line 3. You're absolutely right, Michael. The other projects that you see that will be placed into service, together with some continuing cost efficiencies that we see driving out in the business. Those are the biggest pieces of the year-over-year EBITDA growth.
Just on that question, too, on the bridge, 2020 versus 2019. You're adding CAD 1.8 billion of EBITDA and free cash flow. It's like it's going up a much smaller amount. I would think your maintenance CapEx would've been rising over time. It's not. You have this empty box here purposely, I'm guessing. It doesn't look like your debt's going to go up dramatically, probably CAD 1 billion or so, just looking at debt-to-EBITDA. What am I missing here?
Well-
Is there a bias to the CAD 10 billion, is that part?
I mean, interest expense will go up.
Okay.
Naturally, we're funding a lot of.
Yeah
assets between 2019 and 2020. Capitalized interest, of course, will cease, you'll see a fairly big difference between those two years. Cash taxes, I think I'd have to go back and look at the slide, they're going to go up a snick as well. It'll be factors primarily like that that'll drive it.
Okay. I think that's it, John. Thanks.
Great.
We'll ask Al to come back up to wrap.
Well, we've covered a lot of ground. Thank you for your attention today. Maybe just a couple of closing comments here. If you really boil this down, the value proposition here is really composed of three things. Number 1, we think we have extremely high-quality infrastructure franchises. All three, frankly, we wouldn't trade any of them for any other assets in the space. I would say that secondly, and this goes a little bit to Rob's question over there about the emphasis on growth. Let me just put that one in context. I think when you go through all of the opportunities that you hear today, there's no doubt that our focus is on extending and expanding the existing franchise because we have a lot of opportunity there in front of us.
At the same time, though, we're equally focused on making sure on the risk side of the equation, managing the balance sheet very closely. You saw, I think, equal emphasis through the last year, but also going forward, around that discipline and making sure we're living within our free cash flow to invest in the business. I think that's a key to all of this. On the growth side, certainly we're landing where we were last year as far as growth through 2020 at 10% CAGR through 2018 through 2020. Of course, we've been talking about 5%-7% growth beyond 2020. All within, again, to emphasize our existing cash flow availability, and making sure we're allocating and being flexible about where we put capital to ensure that we're maximizing value along the way.
We will test each of our opportunities within the business units with each other, but also against these other options that we're talking about. Maybe I'll just end with a comment on something that we haven't really touched on here, but it's the management team. From my point of view, we have a very strong and capable team. I think you saw that with the presentations. They're all very passionate about what they do. There's a bunch of people that are here today and back at home office and throughout the organization that you don't see, and you haven't heard from today, but we have a very strong bench and we're very pleased with that capability. We often say we could each replace each other in our roles, and I'm not sure how that goes over necessarily too well, but it is true.
We have a lot of capability within the bench along the organization. A final comment on this notion about what it takes to build infrastructure today in a very tough environment. It comes to the people who actually engage communities, indigenous groups, community leaders, and political leaders around what we do in this business and how we do it. The very important message that we have to get across is the passion and the commitment that we have to do things safely and reliably. That is the key driver of getting people to ensure that they're supporting the infrastructure, the critical infrastructure that we run, but also build for the future growth of our business going forward. Finally, all of these people I'm talking about, we're all owners.
We're all stock owners in the business, and we take this growth and balance sheet and healthy infrastructure very seriously because it is our own money, and that is very important at the end of the day. We thank you very much for attending. I know it's been a long morning, but hopefully, you can join us for lunch shortly in the other room. Thank you.