Good morning again, and welcome to TC Energy's 2019 Investor Day. I'm David Moneta, Vice President of Relations. I'd like to start by thanking you for taking the time to join us today. We very much appreciate your ongoing interest and support of TC Energy. We intend to use this morning to provide you with an update on the many initiatives we have underway.
I also hope to provide you with some insight into the trends that are likely to help shape both the pipeline and power and storage businesses as we move forward. We'll begin today with Russ Girling, our President and Chief Executive Officer. Russ will provide you with some comments on some of the progress we've made over the last number of years, some of our key priorities and our outlook for the future. It will be followed by Tracy Robinson, Stan Chapman, Francois Poirier and Paul Miller. They'll provide you with an update on our natural gas pipelines, liquids pipelines and power and storage businesses.
And finally, Don Marchand, our Chief Financial Officer, will close out this morning with a finance update. Copies of the presentations are included in your handout. For those of you listening via webcast this morning, a copy of the presentation material is available on our website. It can be found in the Investors section under the heading Events. We will provide you an opportunity this morning to ask questions.
Just in the interest of giving everyone an opportunity, I'd ask that you limit your questions to 1 with a follow-up, if you don't mind. And before we get going, just to remind you that our comments this morning will include forward looking statements that are subject to important risks and uncertainties. For more information on those risks and uncertainties, please see reports filed with the Canadian Securities Regulators and with the U. S. Exchange Commission.
And finally, just a couple of quick comments on non GAAP measures. We will reference comparable earnings before interest, tax, depreciation and amortization or comparable EBITDA, comparable earnings and comparable funds generated from operations. These measures are used to provide you with some information or additional information on our operating performance, liquidity and our ability to fund our capital program. However, they do not have any standardized meaning under U. S.
GAAP and are therefore considered to be non GAAP measures. With that, I'll turn the podium over to Russ Girling, our President and Chief Executive Officer, for his opening comments.
Thanks, David, and good morning, everyone, both here in person and on the webcast. We certainly appreciate you all taking the time out of your busy schedules to join us both today and last night and for your ongoing interest and support of our company. It's hard to believe that we're back in this room again and a year has already passed. And I could tell you that it's been a very busy 12 months at TC Energy. But looking back over the year, and this is the time that we do that, we have made, despite all the noise, we've made a lot of progress on several fronts.
Our portfolio of high quality assets continue to perform extremely well and strong fundamentals combined with an unparalleled asset footprint and our continued financial discipline has positioned us, I believe, for growth for many years yet to come. Over the next 4 hours or so, my colleagues and I will spend that time talking about some of the significant advances that we have made over the last 12 months. And I think probably more importantly, as we look forward, the promising outlook that we see for our future. This next slide here captures the key themes of what we're going to talk about today as well as the tenants or what we call our beliefs that have guided our business for the past 2 decades. First of all, we do believe that energy demand, including the demand for oil and gas, will continue to grow, and there'll be significant opportunities in North America to build energy infrastructure that connects abundant low cost supply to premium and growing markets across North America and exporting to other continents.
Evidence of this can be seen in historically high utilization rates across our assets today as well as ongoing requests for new expansions in most areas of our footprint. Secondly, we believe that our proven low risk model will produce stable and predictable results during all phases of the economic cycle. Today, approximately 95% of our EBITDA comes from regulated assets or long term contracts, largely insulating us from both the variability associated with commodity risk and volumetric risk. Thirdly, we believe that our broad network of high quality assets provides us with a significant competitive advantage forward. Today, we are advancing $30,000,000,000 of commercially secured projects that are largely in Corridor and their expansions of existing assets, and we have another $20,000,000,000 of projects that we have currently under development.
We have the technical expertise and commercial skills to navigate the continually changing environment in front of us, whether it's our ability to successfully construct across extremely challenging terrain and severe weather conditions or to manage the technical change or distressed economic times, we have consistently adapted to the changing world around us and often have turned what were perceived threats into opportunities for our company. And finally, we believe that our financial strength and flexibility will allow us to maximize shareholder value. We have consistently allocated our internally generated cash flow in a manner that strikes, we believe, the right balance between maintaining a strong balance sheet, funding our growth and paying a sustainable and growing dividend. Our has been driven by belief that a self funded approach or model along with strong credit ratings will allow us to act at all points in the economic cycle. Overall, our strategy remains very simple.
It simply is to grow earnings, cash flow and dividends per share for our shareholders by investing in high quality, low risk infrastructure assets that deliver the energy that people need every day. With that overview, I'll delve a little bit deeper into this each of these themes, starting with our approach to capital allocation. This slide illustrates our business model, and it's straightforward. You've heard me talk about it many times actually, I believe when I was the CFO about 20 years ago, I had the same model that I showed you. Our portfolio of critical energy infrastructure assets generates strong, stable, long term cash flow streams.
What we do is we take 40% of that cash flow and return it to our shareholders in the form of a sustainable and growing dividend. The remaining 60% has been reinvested in complementary low risk assets that have driven considerable growth in both earnings and cash flow. I think while others have continually altered their approach to capital allocation, we have maintained this consistent approach, and it served us well, generating double digit annual shareholder returns since 2000. In fact, over the past 19 years, we've invested about $100,000,000,000 in pipeline and power assets. Through that investments, we have transformed our company from what was a Canadian regulated natural gas pipeline company into a leading North American infrastructure company.
That growth has come both through expansions of our legacy assets along with opportunistic acquisition. Those acquisitions include an interest in Bruce Power, which we did in 2003 GTN, which we did in 2000 and 4 ANR in 2007 various parts of the Keystone system in 2008 2010 and the Columbia acquisition in 2016. As you know, each of those acquisitions was transformational, and they expanded our North American footprint and provided us with new platforms for continued growth. As a result today, we have 5 platforms for growth compared to one that we had in 2000. They include our Canadian, U.
S. And Mexican natural gas businesses, our liquids pipeline business and our power and storage business. Investments we've made have created significant shareholder value. Evidence of this can be seen in growth in earnings and cash flow per share over that same period. As you can see on this chart, earnings have increased from approximately $1 per share in $2,000 to more than $4 per share today and while cash flow has increased from about $2.50 per share in 2,000 to approximately $7.75 today.
That equates to an average annual growth rate of approximately 7% and 6%, respectively, since the year 2000. But just as importantly, we have been able to consistently produce those results through all phases of the economic cycle, whether it's been the global financial crisis that we saw in 2008, 2009 or the various industry shocks that we've lived through, including the downfall of the IPP and MLP markets, the shale revolution or the oil price collapse, our approach has generated steady growth in earnings and cash flow through all phases of the economic cycle. Our success is largely tied to our investment in regulated or long term contracted assets that link low cost, long life natural gas and crude oil reserves to premium markets across North America as well as funding those investments through both internally generated cash flow and long term capital raised at compelling terms due to strong credit ratings and a simple corporate structure. As a result, we have largely insulated ourselves from, as I said, both commodity and volumetric risks, but as well interest rate risk, allowing us produce fairly steady and stable results in all economic climates. The steady growth in earnings and cash flow has allowed us to increase our common share dividend in each of the last 19 years from about $0.80 per share in 2000 at the current level of $3 per share.
That represents a compound average growth rate of about 7% and equates to a payment of approximately $20,000,000,000 in dividends to our shareholders over that period of time. We have also maintained strong dividend coverage ratios with our current dividend representing a payout ratio of just over 70 percent of earnings and approximately 40% of internally generated cash flow, leaving us with substantial financial flexibility to continue invest and grow our businesses. Our strong financial performance and growing dividend, in turn, has resulted in a significant increase in our share price from $10 per share in 2,000 to approximately $67 today. That growth in our share price combined with a steady and growing dividend means that we have delivered a 14% average annual total shareholder return since 2000. As we look at it, that compares very favorably to the performance of the broader markets over the last 19 years.
As highlighted on this slide, our 14% average annual return equates to a total return of more than 1100%. In comparison, TSX and S and P 500 generated returns of just over 200%. And we would say that would be a very good outcome from our perspective, particularly when you consider the low risk nature of our business. So today, we are an enterprise that's valued at about $115,000,000,000 and we own or have interest in about 91,000 kilometers or 56,000 miles of natural gas pipelines that move about 25% of all the gas demand in North America from the continent's 2 largest, most cost competitive natural gas production basins to premium markets, both here and now growing internationally. We're also North America's largest provider of natural gas storage with 6 53 Bcf of storage capacity.
In the liquids business, we deliver approximately 555,000 barrels a day or 20% of Western Canadian's crude oil exports to key refining markets in the U. S. Midwest and the Gulf Coast. In Power and Storage, we have interest in our own town power plants capable of producing about 6,000 megawatts of electricity, which is enough to power about 6,000,000 homes. Over half of that electricity is comprised of is comprised of emissionless nuclear energy.
Our strong financial performance continued into 2019 the 1st 9 months ended September 30. Comparable earnings were $3.11 or up 10% over last year. Comparable funds generated from operations above $5,300,000,000 up 14% over last year. These strong results support our Board of Directors' decision earlier this year to increase our common share dividend by 8.7 percent to $3 per share on an annualized basis. So in addition to delivering record results, we also made significant progress on many other fronts throughout the year.
We continue to advance a $30,000,000,000 portfolio of commercially secured projects. Our portfolio now includes $3,000,000,000 of new projects that have been added to our backlog since the beginning of 20 19. We also placed $8,000,000,000 of new assets into service, including Colombia's Mountaineer project, Colombia's Golf Express project as well as the Sur de Texas project in Mexico. And by the end of this year, we'll complete another $2,500,000,000 of NGTL projects, bringing the total new projects entering service in 2019 to about $10,000,000,000 We also advanced $20,000,000,000 of projects under development, including Keystone XL and the Bruce Power Life Extension Program. Turning to our funding program.
We took sheet by monetizing about $6,300,000,000 of mature assets through a series of transactions. As a result, we are on track to achieve our targeted credit metrics, and we are well positioned to return ourselves to our historic self funded model. Therefore, as we announced last quarter, we'll no longer be issuing common shares from treasury under our dividend reinvestment program commencing with the Q4 2019 dividend. So in summary, as I said earlier, it has been a very busy year for us, but I can tell you I'm extremely pleased with the progress we've made and I'm confident that we're well positioned continued success. Looking forward, our focus isn't going to change.
We remain focused on 6 key priorities. And again, these are the same priorities that have guided us for the past 2 decades. The first is to ensure that our assets continue to operate safely and reliably every day. 2nd, we continually seek to improve the profitability of existing assets by maximizing revenues and reducing our costs in each of our businesses. 3rd, we'll focus on executing our $30,000,000,000 capital program on time, on budget, on quality.
4th, we'll continue to advance the more than $20,000,000,000 of projects that we have under development in a careful cost effective existing geographies. And finally, we'll continue to allocate our internally generated cash flow in a manner that allows us to maintain a strong balance fund our growth and support a sustainable and growing dividend. Well, obviously, we're proud of the success we've had over the last number of years. We know that our long term success depends on our ability to balance that profitability with safety and social environmental responsibility. Above all else, safety is our very top priority.
It has been and will continue to be. We have 65 year track record of safe and reliable operations, but we do recognize that we need to continually improve. We've had a few incidents over the last past couple of years, including the recent one on Keystone at Edinburg in North Dakota. When incidents do occur, we are focused on ensuring that we have world class capabilities to respond, protect the public and the environment and restore those assets to service as quickly as possible. And I'm extremely proud of our organization and how it reacted to that incident and other incidents that we had.
However, for us, no safety incident is acceptable, and we're not going to be satisfied until we achieve our goal of 0 incidents, and we're spending a lot of time, energy and resources trying to get there. We also have a long history of collaborating with stakeholders and communities in which we work. We treat all land owners with fairness and respect, enabling us to create long term relationships. When we get the property, we basically marry these folks for many decades. As we look to develop new projects, our philosophy is the same, understanding stakeholder issues and engaging with local officials, landowners, indigenous communities to identify how to best address their concerns is a very critical issue to our success.
And while our customers will always look for competitively priced services, they are now focused on choosing partners whose values around safety, environmental stewardship and respect for others aligns with theirs. We believe that our world class capabilities around operations, project execution and a strong track record of collaboration stakeholders means that we're well positioned to be a partner of choice in the eyes of those customers. We also believe that maintaining the highest standards of corporate governance is critical to being successful. Our Board consists of an experienced, knowledgeable and diverse group of individuals who, with the exception of myself, are all independent of management. Ultimately, our purpose is to deliver the energy that people need safely and reliably every day.
That's why we invest more than $1,000,000,000 a year in our pipeline integrity and facility maintenance programs and continue to be industry leaders in research and development. It's why we monitor our facilities 24 hours a day, 3 65 days a year and carry out more than 100 emergency training exercises each year. It's why we interact with approximately 100,000 landowners on a daily basis and over 100 indigenous groups that we interact with on a regular basis. It's why we added sustainability to what is now known as our Health, Safety, Sustainability and Environment Committee of our Board that oversees operational issues, security, environmental and climate change related risks. It's why we created the Chief Sustainability Officer role inside of our company to provide strategic vision and leadership around sustainability issues.
And finally, it's why we published our inaugural report on sustainability and climate change, which describes the work that we are doing to ensure the resilience and long term stability of our business in an ever changing energy landscape. So with that in mind, I'd like to spend a few minutes discussing what does lie ahead for TC Energy as the world's demand for all forms of energy continues to transition and grow. This chart is probably familiar to you. You've probably seen it from me before. It's from the 2018 International Energy Agency's World Energy Outlook that depicts expected growth in worldwide demand for all sources of energy between 2017 and 2,040 under what they call their new policy scenario.
Well, the 2019 outlook just came out as well, and we've been reviewing it. Our initial review shows that it's roughly consistent with 2018
with demand for energy growing at a
faster rate in 20 demand for energy growing at a faster rate in 2018 2019 than it has over the last 10 years. As you know, the IEA is considered one of the most comprehensive and credible agencies that do this kind of work, and it's one of the many sources that we use in our planning processes. And as you can see, again, on this chart, renewables such as solar and wind power are expected to continue to grow significantly. However, in a greater scheme of things, they're expected to maintain a relatively modest overall percentage of the overall energy mix. As you can see, even with the enacted and announced targets to address climate change, the IEA anticipates the demand for oil and gas will continue to grow and that they will remain the dominant sources of energy for decades to come as billions of people in developing countries strive to achieve a higher standard of living.
More specifically and more particular to our company, here in North America, natural gas demand is expected to grow to about 130 Bcf a day. Much of that will be driven by industrial demand and natural gas fired generation on the continent, but as well growing LNG exports. In the liquids business, North American crude oil supply is also expected to grow. That includes heavy oil production in Western Canada and the need for new transportation capacity to move that growing production to market is very clear. Finally, on the power front, new generation capacity will be needed to meet both growing demand and to facilitate a shift to a greener energy mix.
Renewables will play a role, as I said. However, given the abundant supply of competitively priced natural gas, it's likely that natural gas fired generation will also play a key role in that demand. So the bottom line for all of our businesses that was we believe the growth in demand combined with the need to replace and upgrade existing infrastructure as society transitions to a lower carbon future will require 1,000,000,000 of dollars of investment in energy infrastructure. And looking forward, our growth plans are aligned with that long term energy supply demand fundamentals, and we are confident that we're well positioned to continue to capture significant share of the investment opportunities that will continue to arise in North America. In a world where it is extremely difficult to build new greenfield infrastructure, our key competitive advantage is our existing footprint, which provides us multiple platforms for in corridor growth.
The NGTL system, as I said, is a 24,000 kilometer or 15,000 mile pipeline network that moves about 12 Bcf a day or 75% of Western Canada's gas to markets through its extensive and cost competitive network. The Canadian Mainline is a 14,000 kilometer and 9,000 mile pipeline that provides a critical link between the prolific Western Sedimentary Basin and key markets in Eastern Canada and Midwestern and Northeastern United States. Columbia Gas is an 1100 mile pipeline, its best in class footprint on top of the Appalachian Basin, which is the continent's largest source of natural gas supply. Our broader U. S.
Pipeline network also includes the Columbia Gulf System, ANR, Great Lakes, Northern Border, GTN, the Portland Pipeline System and Iroquois. Deliveries on our U. Mexico, our assets are forming the backbone of the country's gas In Mexico, our assets are forming the backbone of the country's gas infrastructure. They'll play a critical role in delivering abundant low cost U. S.
Supply to Mexico for many decades to come. In our liquids business, as I said, Keystone moves approximately 600,000 barrels a day or 20% of Canadian oil exports to the U. S. On the southern portion of the Keystone system or the Gulf Coast segment known as Market Link, move approximately 700,000 barrels a day of both Canadian and U. S.
Production between Cushing, Oklahoma and the Gulf Coast. We and our shippers believe that the U. S. Gulf Coast is the largest and most attractive market for growing oil production, and Keystone XL is the most efficient and environmentally sound way to move that production to markets. And finally, in our Power and Storage business, Bruce Power is one of the world's largest nuclear facilities generating 6,400 megawatts of emissionless power or about 30% of Ontario's daily needs.
Looking forward, new generation capacity will be needed to meet growing demand and replace aging infrastructure to facilitate a shift to a greener energy mix. With extension for gas fired additions in our core markets, we are well positioned to capture additional contracted power opportunities along our pipeline footprint. But at the same time, we do have expertise to participate in other forms of new generation, including wind and solar as well as continued nuclear refurbishments at Bruce Power. As you can see, each of our platforms provides us with significant opportunity for in quarter growth and that is our competitive advantage. With an enviable position, it's an enviable position to have in a world where demand continues to grow but is extremely difficult to cite new greenfield infrastructure.
Today, these platforms provide us with line of sight to over $50,000,000,000 of organic growth opportunities. They include $30,000,000,000 of commercially secured projects that will expand and extend our network across North America. That program includes a series of projects and jurisdictions where we see relatively normal course permitting and construction risks. It includes $23,000,000,000 of natural gas pipeline expansions in Canada, the United States and Mexico, dollars 2,000,000,000 associated with ongoing work under the Bruce Power Life Extension Agreement in Ontario and approximately $5,000,000,000 of maintenance capital, 90% of which is related to our regulated natural gas pipelines and therefore is expected to be added to rate base and generate a return on and of capital identical to what we achieved on expansion projects in our pipeline businesses. Notably, each of the projects that I just talked about are underpinned by long term contracts or cost of service regulation, giving us good visibility to sustainable growth in earnings and cash flow as they enter service between now and 2023.
As I said, we're also advancing $20,000,000,000 of development projects, including Keystone XL and the balance of the Bruce Power Life Extension Either of those initiatives would create significant additional shareholder value and position us for continued growth. Based on the confidence we have in our business plans, today we are reaffirming that we expect to grow our common share dividend at an average annual rate of 8% 10% through 2021. As I've said many times, our dividend growth outlook is supported by growth in earnings and cash flow per share and some of the strongest coverage ratios in our industry, leaving us with financial flexibility to continue to prudently fund our capital programs going forward. Over the longer term, we expect our dividend to grow at an average annual rate of 5% to 7%, which is consistent with this historical long term average, which I showed you earlier. That growth is expected to be supported by continued growth in earnings and cash flow per share stemming from abundant organic investment opportunities across our 5 operating platforms.
At the same time, we'll adhere to a self funding model and maintain our strong credit ratings to ensure that we have financial strength and flexibility to act in all points of the economic cycle. As we've seen in the past, this will leave us well positioned to capture transformational opportunities that could supplement that organic growth, if they arise in the future. So before I conclude and pass it on to my colleagues, I'd like to make a few comments on our team. Well, obviously, I'm extremely biased. I believe that we've assembled the best talent in the industry, starting with our executive team.
Many of you are familiar with the faces on this slide. Tracy, Stan, Francois, Paul and Don are all here to provide you an update on their respective areas of responsibility. But as well with us, and some of whom you met last night, Patrick, Leslie and several of our Senior Vice Presidents. So if you didn't get the opportunity to meet with them last night, I'd very much encourage you to seek them out over the mid morning break or lunch to at least say hello so you can connect with them. They're supported by 7,000 talented employees across North America that are expert in their fields and work tirelessly to build and operate the blue chip portfolio of assets that supply the energy that people need every day.
It's their efforts and dedication that will deliver our future success. So as I said, I'm very pleased with our progress over the last 12 months, and I remain extremely confident in our ability to prudently continue to grow shareholder value for the next decade in much the same manner as we have for the past 2 decades. And in each of our businesses, our Presidents are here to provide you an update and more granularity on just exactly how they're going go about doing that. We'll start with Tracy, Stan and Francois. They'll provide you an update on our North American Gas Pipeline business.
As they make their way to the stage, we did like we want to play a brief video here that highlights our people and some of the great work that they are doing across North America to deliver that energy that people need every day. So while they're making their way up, Dave, if you can queue up the video.
Good morning. It's a pleasure to see you all here today. It was great to have a chance to chat with some of you about our business last night. Now before I get in to the Canada Gas, I'll make just a few remarks on our overall kind of gas infrastructure. TC Energy's natural gas pipeline infrastructure includes more than 92,000 kilometers of pipe to stretch across Canada, the United States and increasingly includes a meaningful presence in Mexico.
It is anchored in our position on 2 of the most prolific basins in North America, the WCSB and the Appalachian. And this infrastructure, combined with our 653,000,000,000 cubic feet of storage capacity allows us to connect that cost effective gas in these basins to the markets across the continent that need this gas every day and increasingly to global markets throughout our connection to LNG export capacity. And we leverage this network to move 25% of the gas that North America relies on every day. And we're well positioned to do this. This is a supply picture of the natural gas basins across North America.
And on this map, the smaller circles represent the resource estimates of each of these basins in 2,007 and the larger ones, the resource estimates of those same basins in 2019. And you'll note the tremendous increase in supply in all basins. And in fact, we now in North America have enough natural gas to meet our own needs for more than 100 years. The most dramatic increase, of course, is in the 2 basins in which TC Energy's assets are positioned, the WCSB in the Appalachian. Now this is largely low cost gas in the Marcellus.
It's due to the high well productivity and of course, in the WCSB to the NGL content. All this supply is competing for market. And the supply that's going to win is that, that is lowest cost production paired with effective competitive and reliable transportation to market. And of course, this is the focus of our business. Now we do expect that the market for natural gas in North America will continue to grow, although slowly, about 1% a year with the largest growth coming from an increase in the use of gas in electric generation.
The growth to feed the LNG exports will be stronger, about 11% CAGR or by 2,035, 21 Bcf a year. So in this year, 2019, North America fulfilled 10% of the world's demand for LNG. But we project that by 2,035, this continent is expected to become the world's largest LNG supplier providing 26% of global LNG. And as you will hear today, our company is positioned well to aid in this transition. Now if you look a little bit closer at Canada Gas, our Canadian system focused on moving that low cost WCSP gas to key continental demand centers.
The NGTL system attracts about 3 quarters of the 16 Bcf that the WCSB produces every day, and it offers multiple benefits. You can trade that great trading hub at Knit. You can access the intra Alberta market or access to markets across North America through our downstream pipeline network. So of the about 12 Bcf of gas moving into the NGTL system every day, about 40% of it is consumed within Alberta. So this is for power demand, petrochemical production and demand in the oil sands.
Local market is really important for the WCSB, and it's growing. In fact, last February, we hit record intra Alberta flows of about 7.5 Bcf a day. So in addition to meeting that intra Alberta demand, our systems connect the WCSB to other key markets, and these are the green bubbles that you see on this slide. We send 25% of the NGTL volume off the West Coast of the United States and the rest of it, 35% goes down the mainline and other downstream pipes to markets in East, Northeast and the Mid Continent. So despite the distance from this basin from market, this gas is competitive across North America and is attractive outside the continent as well.
We have the basin's first direct access to international markets under construction through LNG Canada's facility and Coastal GasLink, and we're working with other LNG proponents in Eastern Canada and on the West Coast to increase access to markets outside North America. Now those of you that have been covering TC Energy for some time will know that our Canadian Gas business experienced some major changes over the years. As that new technology unlocked the low cost WCSB supply in the Montney, we have worked with our customers to expand our infrastructure to get that gas competitively to market, and we've been successful. So since 2010, our investment base in Canada Gas has grown by almost 40%. And the available capacity in our system is filled to the point where our assets are now essentially fully utilized.
NGTL flows have increased to about 12 Bcf a day. Canadian Mainlines, one of the largest pipelines in North America, had seen flows diminish as Eastern markets turn to supply in the Appalachian, but we've been able to reverse that trend. We've worked producers in the WCSB and markets in the East and the Northeast to reestablish our position in those markets, and we have essentially filled the mainline. This trend in increasing supply and the scarce pipeline capacity has driven change in our customers' contracting behaviors where we used to see focus on interruptible access. We have seen that transition to a greater use of fixed contracts with lengthening term.
And on GTL, for example, the competition for access to the scarce egress has driven terms on our new export capacity to more than 24 years. And on the main line, our newer longer term contracts average in the 20 to 22 year range. So this is good for the basin and for security of access to the market. So by 2023, we'll have an incremental 5.6 DCF of new market access in place to the WCSB, and a total investment base will reach $23,400,000,000 about 50% more than it is today. These expansions are critical to the basin.
It's not getting easier. We all know to build new infrastructure, but we are successful because we leverage the strength of our existing system to drive brownfield expansion effectively. So despite all of the challenges, we have a track record of getting permits approved and projects built. And we're continuing to build on this momentum. Last year's Investors Day, we said we're going to do 3 things.
Firstly, we said we'd execute our capital program safely on time and on budget. And we are executing now a $17,000,000,000 capital program that will add 5.6 Bcf of egress from the WCSB to markets in North America and Asia. And so far, by the end of Q3, this year, we spent $2,500,000,000 to achieve these capacity expansions. Now this is a significant build for our Canadian system. And I want to emphasize that we execute these projects and we operate our system.
Safety remains our top priority. Across our network, we are fully committed to ensuring that everyone gets home safely and that we protect the lands and the environment in which we operate. Secondly, we said we'd maximize the value of our business. To us, this means doing more without spending more and by improving the utilization of our assets without major capital investment. So we continue to work to find ways to open up short term capacity on our system without additional capital.
This year, our team released 1,600,000,000 cubic feet a day of short term capacity across the network. They did this through accomplish they did 16 quick turnaround capacity projects and by actioning a number of smaller operational improvements and optimizing some of our demand parameters, and we need to continue to push these boundaries. Thirdly, we said we'd facilitate growth in the WCSB access to market, and our efforts on this continue. We recently announced a $1,200,000,000 Westpath expansion, which is a coordinated effort between our Canadian and U. S.
Gas teams, both the expansion of the NGTL systems and the Foothill system, in conjunction with what Stan will tell you, is the GTM expansion. This is underpinned by 258,000,000 cubic feet a day of new firm service contracts with terms that exceed 30 years And we'll facilitate increased flow of that WCSB volume into markets in the Pacific Northwest and California, which are key markets for our system. Last February, we announced 85,000,000 riverbend expansion, which will connect 308,000,000 cubic feet a day of supply to a new petrochemical facility in Alberta. And looking further east, this year, we signed 167 TJs and long term contracts on our Parkway expansion. So this is now a picture of the expansion program that we have underway.
NGTL's $10,000,000,000 capital growth program extends beyond 20 2 and will add 3.5 Bcf a day of delivery capacity, 1.5 Bcf a day into the intra Alberta market and 2 Bcf a day of egress out of Alberta, 700,000,000 cubic feet to the West Coast of the U. S. And an incremental 1.3 Bcf to access the mainline and the markets it reaches directly through our U. S. System.
Coastal GasLink will provide in Phase 1, 2,100,000,000 cubic feet a day of international market. And Eastern Triangle, we are investing $400,000,000 to facilitate the flow through that area and down into our U. S. Pipes in the Northeast U. S.
So to do this safely and effectively, we maintain our assets in good operating condition. And over the last 3 years, we put $1,900,000,000 in maintenance sorry, over the next 3 years, we'll put $1,900,000,000 dollars or so in maintenance capital into this system. That's about $600,000,000 a year, and that $600,000,000 is a good run rate based on expected volumes. And we do adjust maintenance capital over time to reflect the demands on our system and by our regulators. And as a reminder, financially, maintenance capital is treated the same in the Canadian pipes as expansion capital.
It receives a return of and on capital immediately. So in the NGTL system, the expansion program is an important part of our efforts to support the health and the growth of the WCSB. As supply shifts further into the Montney, we continue to work to access that supply and to reduce the bottlenecks to get it through the system. The basin's need for market growth, we are working to provide egress to a variety of markets and our expansion program will achieve this. The efforts continue on other fronts.
We're progressing our discussions now with our customers on the revenue requirement and tolls that will apply when our current arrangement expires at the end of this year. We do expect to file for interim tolls while we continue these negotiations. We hope to provide some more detail on that early in the New Year. The rate design and services application we filed earlier this year is working its way through a process that will conclude in a hearing scheduled for early December. This application proposes changes to the tolls and the services on the NGTL system to better reflect the current flows and to and to respond to our regulators' request on tolling for North Montney Mainland.
The NGTL system is underpinned by strong fundamentals customers. These contracts are held by a group of predominantly strong creditworthy customers. In fact, when you look at our 2019 revenue, our top 60 customers make up about 90% of our revenue, and most of those, well over 90% is with creditworthy counterparties. Coastal GasLink represents an important effort. For the WCSB, for indigenous and community partners, for our company and I would argue for our country, Along with the LNG Canada Liquefaction Facility, it represents the 1st direct path for Canadian gas to global markets, and we're very proud to be building it.
We're focused on executing it effectively and in a manner that delivers benefits for all of our stakeholders. When it comes into service, CGL will move 2,100,000,000 cubic feet a day of gas to Kitimat. This is Phase 1 capacity and will be built in an estimated cost of $6,600,000,000 Phase 2, should LNG Canada elect to proceed, we'll move 4,300,000,000 cubic feet a day of gas through a fully compressed pipe capable of about 5 1,000,000,000 cubic feet a day. Now we've made significant progress this year. We're well into preconstruction, clearing, roads, workforce accommodations, grading.
We remain on track to meet our committed in service date. Now make no mistake, this is a very technically challenging and environmentally sensitive project, traversing some difficult remote mountain terrain. You saw some of that in the video. We're working carefully with all of our stakeholders as we are learning more as we work across the pipeline route. The $6,600,000,000 capital estimate represents an increase of $400,000,000 That's a result of additional scope as well as new estimates for rock excavation in an area that we previously could not access and in water crossings across the route.
Now it's important to note that this increase represents an estimate based on our best and most recent information, and we'll be working to mitigate it as we proceed with construction. The terms of our agreement with LNG Canada include mechanisms to recover the differences between the estimated project cost and the final cost and through pipeline tools subject to certain conditions, and we are working with our partners on this now. Now the Coastal Gassing project special in a number of other ways and a strong environmental story. The gas that moves through this pipeline and LNG Canada's facility will increase emissions in Canada by about 3000000 or 4000000 tons a year, but it will also reduce annual emissions in Asia by 60000000 to 90000000 tonnes a year by offsetting coal. So this reduction equates to more than the total annual emissions in British Columbia, about 10% of our Canadian annual emissions.
So it's a very positive story. The project is also setting a new standard for how our company works with our indigenous Indigenous groups are also participating in another economic aspects of the project. We're committed to hiring local first and maximizing employment and contracting opportunities. By the end of this project, we aim to put $1,000,000,000 into local and indigenous businesses and create 2,500 high quality construction jobs. So far, we've awarded $720,000,000 to indigenous and local businesses, and indigenous staff have done more than onethree of the preconstruction activity.
This project in many ways is setting the standard for how we'll approach our engagement with our partners and our construction across our system. Now shifting from the West Coast to the Mainline. This is an asset that's very much in demand, important conduit to markets in the prairies and in Eastern Canada and through our U. S. Downstream pipes to the Mid Continent, Don and Northeast U.
S. Markets. And we've now essentially sold out most of the available capacity on the Mainline. The Western Mainline is contracted up for 2021 to reflect the additional flow that will result when our expansion program on NGTL delivers 1,300,000,000 cubic feet a day of incremental volume to the Mainline. On the Eastern side, the Eastern Triangle is fully contracted.
We're spending $400,000,000 in capital to expand this part of the Mainline, including expansions at Station 130 East Hereford TQM, and that will help us in facilitating gas flow down to our Northeast U. S. Pipes, PNGTS and the Iroquois system. As volumes have increased on the Mainline, we've been able to demonstrate the strategic value to the basin and to Eastern market, And we're in discussions now with our customers on how to advance this value as part of our post-twenty 20 framework. We're making good progress on these discussions, and the details will be made available as we come to agreement.
But I will tell you this, that we are aligned around the table and the importance of the mainline connecting the basin's gas to the markets in the East. And as we look forward, we will continue to drive further growth. Here's a few of the things that we're working on now. We see the opportunity for further expansion in our intra Alberta market. We're working with customers now and solidifying their needs for growth in local gas consumption.
We're looking to leverage the benefits and the capacity of the Mainline and its connection to our downstream U. S. Pipes in Stan's area To further expand our position in markets in the East and the Mid Con, Stan will speak a little bit more about some of these opportunities. And we'll continue to work with the many efforts underway in industry in both Eastern Canada and the West Coast to increase access to the WCSB volumes into international markets through the development of new LNG capacity. So what's this all mean?
You'll see my colleagues today discuss their financial performance in terms of EBITDA. In the Canadian regulated business, the items you need to adjust in order to get to EBITDA actually are mostly flow through into tolls. So the appropriate financial metric for our business is net income. Net income is tied pretty closely to investment base into our capital program. The program is going to drive a CAGR investment base of about 9% between 2015 2022 to more than $21,000,000,000 Net income will grow by that same pace from about $500,000,000 in 2015 to more than $850,000,000 by 2022.
Also important to note that from a cash perspective, we're pulling more than $1,000,000,000 a year of depreciation out of our Canadian system. So looking forward, our priorities are clear. We will execute our $17,000,000,000 capital program safely, sustainably on time and on budget, and we'll advance the way that we work with our stakeholders, taking lessons from each experience like CGL to improve our performance across the system. We'll continue our path in optimizing our system to provide maximum capacity and service levels, and we'll continue to work with industry to drive WCSB supply further into markets, both domestic and global through competitive service offerings. We have a very strong team that has accomplished tremendous amount in 2019 and is already working on opportunities ahead of us in 2020 beyond.
They've done a great job in leverage both our Canadian and U. S. Networks to drive benefits to our customers and our bottom line. I'm very proud of the work that they've done. And with that, I'm going to turn the podium over to Stan Chapman in our U.
S. Business.
Hey, good morning, everybody, and I appreciate ongoings in our U. S. Natural gas business. Before I do, there are 3 themes that I want you to focus on during my remarks. First of all, we have a best in class position in the Appalachian Basin, but we're much more than that in that we own and operate a geographically dispersed portfolio of pipeline assets and storage assets across the United States.
Secondly, notwithstanding the headwinds that our industry faces, our pipelines are experiencing unprecedented demand, and we expect that to continue into the future. 3rd, while building new infrastructure is more and more difficult, we remain well positioned for additional growth, growth that I would describe as bite sized opportunities that are formidable, that are constructible and are largely made up of in quarter compression type expansions. So many of you are familiar with our assets, but for those of you that aren't, I thought I'd take a few seconds just to walk you through them. Have an ownership in 13 different pipelines that span 31,000 miles across 40 states of the United States. We operate 5.35 Bcf of regulated storage capacity, making us the largest such provider, and we move about 1 in 4 molecules on an average day across the United States.
When you look at things on a basin perspective, we move about 25% of all Appalachian volumes. Our U. S. Assets move about 33% of all WCSP volumes and our Northern Border system transports about 77% of our Bakken volumes. Most importantly, we connect these supply points to critical demand markets across the United States, most predominantly in the form of LNG exports where we currently connect to 5 terminals and have plans to expand to 3 others.
I thought I would take a few seconds and walk you through some supply and demand macroeconomics, focusing first on supply. Takeaway is there's a whole lot of supply in the ground right now. As a matter of fact, the potential gas committee just released its biannual report earlier this year and noted that there was 3,400,000,000,000,000 cubic feet of proved probable reserves in the United States, which was 20% higher than the 2017 report and the largest amount ever reported. On top of that, another 400,000,000,000,000 cubic feet of proved reserves and another 1,000,000,000,000,000 cubic feet of potential reserves in Canada basically says that our continent is sitting on 4,800,000,000,000,000 cubic feet of reserves. Put that in perspective for you, that is somewhere around 150 years' worth of supply at current production rates.
And know that this production the supply rather could be produced economically. About 200 Tcf is associated gas, which essentially has a zero cost. Around 900 Tcf of gas can be produced at prices less than $3 and about 1300 Tcf can be produced at prices less than $4 With respect to production, production of that supply continues to grow as shown on the graph on the right hand side, led primarily by the Appalachian Basin, which is seeing production today of about 32 Bcf a day growing to 40 Bcf or more over the next decade or so. As you see from the chart, the pace of growth is starting to moderate. In other words, when you look at the slope of the line from 2020 forward, starts to flatten out from the slope of the line from 2015 through 2020.
Put that in perspective for you, 2018 saw production growth of about 17% over 2017 out of the Appalachian Basin. 2019 is likely to see production growth of about 10% over 2018. When we look at producer forecast for production in 2020, production is likely to grow somewhere between 0% 2%. All of this supply has had an impact on prices. When you look at NYMEX prices for 2020, Henry Hub prices somewhere in the $2.50 range, prices in AECO Nit somewhere around $1.40 $1.50 and gas prices in the Permian around $0.90 or so.
On the demand side, demand continues to grow across the United States, as shown in these circle charts on the left hand side, led predominantly by natural gas. Natural gas market share increases from 30% in 2018 to about 37% by 2,040. Renewables grow even faster than natural gas, but the important takeaway is that by 2,040, renewables account for only about 12% of our overall supplies. Fastest growing demand segment continues to be LNG exports. We've seen LNG exports double 2019 over 2018 growing from 3 Bcf to 6 Bcf, likely to double again by 2023 from 6 Bcf to 12 Bcf or more going forward.
If you look at the chart on the right hand side, it will tell you that LNG demand worldwide is going to need somewhere around 19 Bcf a day of more capacity, about 10 Bcf of that, so more than half of that is forecasted to come from the United States, and we expect to compete for and win more than our fair share of that going forward. We have about 3,300 employees that are working on our U. S. Assets day in, day out, and I'd like to give them a bit of a shout out in that 2019 was a really successful year for us. We put into service about $4,500,000,000 worth of capital, which largely concluded the historical backlog of Columbia projects.
In the aggregate, we placed in almost $8,000,000,000 of capital in service, which is now generating about $8,000,000,000 or more of EBITDA per year. We closed out year 2 of our Modernization 2 program successfully on time and on budget, and we did that in an environmentally responsible manner in that the Columbia Gas Modernization Program in and of itself has reduced Columbia's overall CO2 footprint by about 7% across all of our pipelines, across the entire network of 13 pipelines since 2016. On an intensity basis, we've reduced our carbon footprint by over 20%. Think of that in the aggregate as the methane that we're taking out of the atmosphere is equivalent to removing about 240,000 cars from the road or planting 1,100,000 trees each year. Our team delivered strong results in other aspects as well.
What I'm most proud about is our safety performance year to date. We've worked over 1,600,000 hours and knock wood, we have yet to have an away from work incident so far this year. We very quietly settled 3 rate cases, including filing a settlement instead of a rate case on the Columbia Gulf proceeding. We're on track for a 3rd straight year of record earnings in the U. S, and we continue to secure more growth projects as evidenced by the fact that we have, again, very quietly originated about $1,300,000,000 in new projects, which I'll talk about in a little bit more detail in a second.
Our pipelines are experiencing record demand, the likes of which I've never seen before. 8 of our 13 pipelines are essentially 100% fully contracted for. The 9th pipeline, Columbia Gas, is roughly 93% contracted for. We set a peak day send out record of 33.1 Bcf a day back in January of this year. We've seen peak summer records set on our Columbia Gas and Columbia Gulf systems.
We've seen peak power generation send outs on our ANR system. Again, throughout all of our pipeline system, we're seeing unprecedented demand going forward. 93% of our revenues come from long term take or pay contracts. Average durations on our flagship pipelines like Columbia Gulf, Columbia Gas and ANR ranges anywhere from 7 to 8 to 9 years. With respect to counterparty risk, which several of you asked me questions about last night, I would say this, that we believe in the economics around the Appalachian production and that it is the largest and one of the lowest cost producing basins in the continent.
We do not have a problem with exploration. We know exactly where the molecules are, and there's a lot of them in the ground. We simply have a situation where we're producing more gas faster than the demand could keep up with it. We'll continue to watch for and encourage new demand growth. We'll continue to watch for reductions in the pace of growth on the supply side.
With respect to our assets, our revenues from our top 10 producers account for a majority of our overall producer exposure. Many of those producers are using their contracts at very high load factors, load factors that in some cases exceed 90%, which tells me that they're getting proper value for worth of coverage, primarily in the form of a letter of credit. So we're going to continue to monitor the health of producers overall, but we have no undue concerns at this point, nor do we expect there to be a material impact to our business going forward. With respect to our growth projects, as I stated earlier, this year, we largely closed out $8,000,000,000 worth of projects on the Columbia backlog, which generated about $1,000,000,000 worth of EBITDA for us. Going forward, we are now we're now executing on about $2,100,000,000 worth of new growth projects.
Some of these are still subject to FID and customer counterparts. But in the aggregate, you could think of us as having a build multiple on this $2,000,000,000 of projects that we're executing on somewhere around the 6x EBITDA to CapEx going forward. So very attractive build multiples. Modernization 2, 2020 will be the 3rd and final year of that program and will conclude a $1,100,000,000 investment. With respect to maintenance capital, we've included on here a 3 year look at our overall capital coming in at $2,100,000,000 which is just a tick higher than what we showed you last year due to the fact that we have some more reliability and integrity work to do on our pipes due to the high nature, high utilization load factors that we're experiencing as well as to comply with the gas transmission rule that FEMSA issued back in October.
Post-twenty 22, I would expect our maintenance capital, our 3 year average maintenance capital to moderate down to something in the $1,900,000,000 run rate going forward. I mentioned earlier that LNG demand continues to be one of the prime focal points for growth going forward. We currently access 5 LNG terminals directly or indirectly, and we have plans in place to access 3 others in the coming future. We are competing for and we are winning more than our fair share of this load. Currently, we supply about 33% of the LNG exports to Bcf out of Bcf.
Now going forward, we expect that to increase to somewhere between 40% to 45%. Key focus areas for 2020 beyond continue to be the safe, reliable operations of our pipeline. If we don't operate safely, we lose. And we're going to continue to optimize our base business with respect to both cost and capital discipline and do what I would call small scale debottlenecking to make sure that we are optimizing the flow of our assets flow of the gas across all of our assets. We're going to carefully optimize the regulatory process to take advantage of the ability to potentially file rate cases sooner to make sure that we're recovering the maintenance capital in a prudent time frame.
And we're going to continue to pursue growth opportunities going forward. As it stands right now, each of our 13 different pipelines in the U. S. Has some sort of a growth project going on either in origination or in execution, and that to me is just a testament to the strength of the footprint that we have going forward. So a lot more opportunities both with respect to being what I call a catcher's mitts and being a home to transport all the growing WCSB volumes as well as opportunities between the U.
S. And Mexico as well. If you invested $1 with us back in 2015, you did pretty darn well. We're on track to deliver a 22% compounded average growth rate between then and 2022, again, a testament to the fact that the Columbia acquisition was transformational as well as the build out of the Columbia growth projects, again, generating about $1,000,000,000 worth of EBITDA for us. So going forward, our game plan is very simple and very straightforward.
We're going to execute on our base business. We're going to continue to build out our growth projects on time and on budget. Again, these are bite sized projects that are largely in corridor expansions, compression only related that are constructible and permittable. We're going to maximize the regulatory process to take advantage of regulatory filings in a very smart way, and we're going to continue to cultivate new growth projects going forward, which again, when I look at our pipeline asset tells me that in any given year, just the breadth of our pipeline footprint says we should be originating somewhere between $500,000,000 to $1,000,000,000 of growth projects annually, and I think that we very much could do that. So with that, I will pause and turn the podium over to Francois to talk to you about the Mexico business.
Good morning, everybody. Okay. On Mexico, I think I'll start with a bit of an overview. For those of you who are less familiar with our business down there, we have 5 revenue generating pipelines today. In the Northwest, we have our Tapalabambo and Mazatlan systems.
On East Coast, offshore Mexico, we have connecting U. S. Gulf Coast gas down into Central Mexico, our Sur de Texas pipeline and bringing gas into Central Mexico through Sur de Texas where we also have our Tamazan Chale and Guadalajara pipelines in operation. These pipelines deliver reliable service to the CFE and our other customers primarily made up of small LDCs and natural gas marketers. Our plan is to put Villa de Reyes into service in 2020.
First, the North segment in the Q1 of next year, the lateral to Salamanca in Q2 and then finally, Lalira to Tula in the Q3. And once we've had that into service, we'll have over US5 $1,000,000,000 of assets in operation in the country. We've completed most of the West and East segments of the Tuxpan Tula pipeline and await completion of Cinera's indigenous consultations prior to building the middle 90 kilometer segment to complete our construction program. Our pipelines are underpinned by long term contracts with the CFE and are predominantly denominated in U. S.
Dollars. We are well positioned once this backbone infrastructure has been completed to connect U. S. Natural gas supplies to growing power generation and industrial markets in Central Mexico. We have over 600 full time employees and contractors in Mexico and are continuing our migration from a construction orientation to an operations focus with an aim to increasing capacity utilization on our systems while operating safely and efficiently.
Now I don't think we brag enough about some of the technical stuff we accomplished. So I put a couple of photos here as part of my slides. What you see here on the right is a photo of the solitaire, one of the main pipe lay vessels for the Sur de Texas pipeline. Here you can see a 42 inches line being laid through shallow waters down to the seabed of the Gulf of Mexico. And as you can see here, the concrete weightings, which ensure minimal buoyancy for the pipeline.
2019 has been a busy and an eventful year for us in Mexico with major accomplishments. Importantly, our Sur de Texas pipeline began commercial operations in September, allowing the CFE to flow up to 2,600,000,000 cubic feet per day into the east of the country and relieving strain on the Cenagas national system. This makes up approximately a 40% increase in gas flowing Mexico and improves energy security and allows for cleaner, more reliable fuel and fuel switching at existing power plants, which currently burn oil or diesel fuel oil or diesel. Now the construction of Sur de Texas included an incremental $150,000,000 investment to tunnel underneath environmentally sensitive areas near Altamira. And the construction of that tunnel ensured protection of a water crossing, a mangrove forest, a beach and a nearby reef.
And as is our practice and as is part of our core values, these activities were undertaken as part of our ongoing work to minimize environmental impact in the areas in which we operate. Now as part of this pipeline entering operations, TC Energy reached an agreement with the CFE, which includes a 10 year extension of the CFE contract and end international arbitration that the CFE had initiated. Our Villa de Reyes pipeline connecting supply and demand in the central part of the country continues to progress towards completion, as I mentioned on the prior slide, and we expect in service in 2020. And once the Villa Dores pipeline is complete, many of CFE's power plants In the central region of Mexico, we'll be using natural gas as their primary source of fuel. We also continue negotiations with the CFE on the Tula and Villa de Reyes pipelines to come to a mutually beneficial agreement and the progress is continuing.
Most importantly, in 2019, it's been an excellent year for customer gas deliveries with 100% reliability on all of our pipelines across the country. As in previous years, we continue to expect strong growth in natural gas demand within Mexico. Being connected to low cost U. S. Natural gas allows Mexico to benefit from some of the cheapest natural gas in the world, And this availability will help to support growth in the power sector within Mexico through fuel switching, as well as industrial growth across the country, including in major industrial parks in the center of the country, which will support continued growth in Mexico's burgeoning industrial sector.
We continue to expect that Mexico will rely on piped imports for a majority of its natural gas needs, even with efforts to bolster domestic gas production. With the availability of cheap gas from the U. S. Gulf Coast, we expect LNG imports to decline and potentially even reverse as LNG exports via several ports are being evaluated. In all scenarios, we see that piped imports of natural gas, including on all of our systems, will remain critical to Mexico's continued growth in the long run.
Sorry about that. In the near term, our focus is on leveraging our existing assets. We have a dominant position in the Northwest and in the central regions of the country. We'll now be turning our focus to connecting large industrials and encouraging the conversion of diesel and fuel oil power plants to natural gas. We can quickly expand our systems by constructing additional compression and metering facilities.
These efficient expansions will support our plans to connect new customers. In the central region, certainly now that we have access to inexpensive gas from the Aqua Dulce and Waha delivery points, we believe this will stimulate tremendous economic growth in the central part of the country. We've now received our Cray permits, the regulator in Mexico, to commence marketing activities. Low risk gas marketing opportunities are available to provide potential customers with bundled commodity and transportation services. This would promote utilization of our existing assets across the region and drive original organic growth.
And over the long term, the Mexican Pacific Coast appears to be a logical location for potential LNG export terminal And our port area in Topolobambo is the shortest path to connect abundant Texas natural gas to Asian markets. And on a very preliminary basis, we're in conversations with many LNG project proponents, to that effect. So again, here pictured at left, you can see the Sur de Texas pipeline has 2 entry points to land. 1 is in Altamira and 1 is down in Tamayagua. And as I mentioned, in order to protect the environmentally sensitive mangrove areas, we decided to construct micro tunnels to connect the onshore and offshore segments of the pipeline.
And here you can see in this photo, part of the nearly 2.2 kilometer Altamira microtunnel, which is the longest of its kind in the world. So congratulations again to the team that got that done. In terms of our EBITDA going forward, we've shown impressive growth since 2015 as we've deployed capital in the country. In terms of outlook, this graph reflects the latest forecast, including adjustments based on our revised Sur de Texas contract. We include in here some interruptible volumes on the eastern segment of the Tula pipeline to supply a CFE power plant as well as of course Villa de Reyes going into service in 2020.
And through the renegotiation of our pipeline contracts with the CFE and the Mexican government, this reduced uncertainty has provided more confidence for our customers who wish to continue fuel switching and expand gas demand across the industrial sector. And this, of course, is expected to lead to additional organic growth on our pipelines that goes beyond what's portrayed on this graph. So in terms of our scorecard for ourselves in the near term, our number one priority is always to operate safely and reliably. We'll advance and finalize commercial negotiations with the CFE on the Tula and Villa de Reyes projects. From a project execution standpoint, we will complete construction of Villa de Reyes with a 3 phased 2020 in service program.
And we will cultivate organic opportunities through compression additions and laterals using our marketing arm as a lever to optimize utilization and drive those expansions. And then in the longer term, we'll assess opportunities to build new greenfield and brownfield infrastructure, such as supplying potential new LNG export capacity or other industrial load as it may present itself. So those are the end of my prepared remarks, and I think we're going to move now, David, to questions.
Thanks very much, Francois. As highlighted, we will provide the opportunity here for you to ask your questions. Got to be most efficient to cover all elements of our natural gas pipeline business together. So with that, I'd just ask that if you do have a question, just raise your hand. We'll get a mic to you so that the webcast can hear the question as well.
Jeremy Tonet, JPMorgan. Just wanted to start off with the natural gas segment here in the U. S. And just want to see, you guys have spent a lot on modernization in Colombia and across the system. And wondering just if you could talk a bit more about what it could look like going forward as far as modernization with compressors.
How much more emissions reduction could you achieve? What could that mean to capacity that you could bring online by modernizing compressors? Just wondering if you could talk a bit more about both those sides.
Yes. Sure, Jeremy. And obviously, what you're pointing out correctly so is that the environmental aspect of what we do is becoming more and more important, and we need to remember that as we build projects going forward. Maybe a good example is the project that we just did on the GTN system, which is a combination of reliability and an expansion work, a situation where we can remove an old inefficient compressor, put a new unit in and expand it at the same time, have the general system customers pay for the reliability aspect of it and then allocate the incremental cost to the expansion shippers. Those are the types of projects that we need to focus on going forward, again, that are going to reduce our footprint in terms of CO2 emissions and at the same time, provide the expandability and be that catcher's mitt for the WCS gas as it grows.
With respect to modernization programs in general, one of our goals for the next several years is to expand programs like we had on Columbia and the AR system to all of our pipelines. And again, what we're seeing is reliability is increasing. We have less restrictions. We have less outages, which means we have more throughput on a daily basis, which is a good thing for both our shareholders and our customers. And the environmental aspect is something that, quite frankly, is going to be a key focus point for us going forward.
So I mentioned the fact that on the Columbia system, we reduced our greenhouse gas footprint by about 7%. That's relatively low hanging fruit. That's taking out old inefficient compressors, putting new ones in their place. That's really replacing bare steel and cast iron pipe in some cases that tends to leak. It's really looking at things like waste heat recovery and what we could do to be more efficient going forward.
So there's lots of opportunities for us, and it's going to be a key focus going forward.
So it sounds like the kind of capacity creep with the compressor additions been pretty meaningful recently, and it seems like it's very easy low hanging fruit insofar as it's brownfield and there's not as much regulatory risk as maybe other projects. Just wondering if you might be able to quantify recently how meaningful has that been kind of that capacity creep in any of these projects?
Well, again, you look at GTN project in and itself is $250,000 a day. If you go back to my project slide, I think we're adding about 3 Bcf of projects primarily in places like Louisiana and tying into LNG exports. Much easier to build and permit a project in Louisiana than it is in New York or California for sure. So that's our strategy going forward. Our strength is our portfolio.
We have a great asset base, and we're going to leverage it by doing largely in corridor compression type expansions.
Andrew Kuske, Credit Suisse. I think both of you alluded to just the dynamics of the in quarter building. And I think, Stan, you mentioned sort of $500,000,000 to $1,000,000,000 sort of down the fairway stuff that you can do. In totality, when you look across really the 3 countries, what's the visibility on capital allocation on just down the fairway line extensions, looping, compression, how much capital per year do you think you can allocate to that? Is it sort of $2,000,000,000 $3,000,000,000 and then for how many years out?
I guess I could start just with the U. S. Business and to clarify my remarks, I think that this notion of a $500,000,000 to $1,000,000,000 a year in growth projects is, to use your analogy, the middle of the fairway or the low hanging fruit. We should do better than that as evidenced by the fact that this year we've originated about $1,300,000,000 worth of projects. Again, 1 or 2 of them is still subject to FID.
So in terms of overall capital investment, we're going to spend somewhere around $600,000,000 or more in maintenance capital. We're going to spend about $300,000,000 to $400,000,000 on modernization programs. We're going to spend about $1,000,000,000 or more on growth projects. So $2,000,000,000 to $2,500,000,000 a year is kind of what I think of a capital run rate in the U. S.
Business.
Andrea, on the Canadian side, I think we have more than $10,000,000,000 right now in capital expansion in corridor, right? Everything except the CGL program is in corridor. And as we think about taking that next tranche of egress capacity of the WCSB out to the markets, most of it or all of it will be in corridor expansion, including, of course, our maintenance program about 600,000,000 dollars a year. So it's quite a substantial program. And I think most of what we do in the future will be leveraging our existing system.
It's where the magic is for us.
And I think in terms of Mexico, as I talked about our strategy in the medium term here is going to be to fill the pipeline. We've built the backbone infrastructure. Now we need to add customers. So I think you'll see a pretty modest capital outlay from us over the next 2 or 3 years and $100,000,000 to $200,000,000 a year or that range.
Maybe the only other thing that I would augment that was with CGL will become in corridor once built. And we see ourselves going from 2 Bcf a day to 5 Bcf a day and maybe more in the future. If you think about something looks like that, I don't know, Tracy, half the cost of the build to add double the capacity of the system, so another $3,000,000,000 of in corridor expansion. So as we think about our gas business, the combination of in corridor expansion plus maintenance capital, which is recoverable and both get return on capital, I think you can easily see $3,000,000,000 or $4,000,000,000 a year of spend in our gas business for the foreseeable future.
Thanks. Chuck? Sorry, go ahead.
Hi. It's Ben Pham, BMO Capital Markets. Maybe just a question for Russ or Francois, the corporate development, have you switch it off there? Just curious what's your appetite for maybe adding a utility to your energy infrastructure platform? And I asked that because I think about your post 2021 growth is looking very similar to how utility is growing in North America.
And you can argue that you have some credit balance sheet accretion by owning a utility, maybe even some ESG accretion, you had a teaser slide on that and maybe even price earnings valuation accretion as well.
So, you look at our growth trajectory here, we have $30,000,000,000 in capital committed across our franchises. Clearly, the theme of there's policy support for electrification and that's something that we're keeping a on the storage side right now is generation. We are owners and developers and operators of long linear infrastructure, but under federal regulation with hundreds of customers, not millions of customers. So there are there is some alignment between owning regulated infrastructure on the gas and liquid side with an electric utility, but different regulatory construct, slightly different core competencies. And frankly, when you look at the financial metrics right now, perhaps there's a little bit of scarcity value on the utility side.
From a valuation standpoint and where we could allocate our capital here in the medium to long term, I think there are better opportunities inside our current portfolio. But as you can tell from my remarks, it's something we think about, we're keeping a close eye on, but it's not in our plans in the near future.
And just to augment that, I mean, always when we look at opportunities, obviously, a utility platform, what we would look for is an opportunity for growth. As we do our math, we're primarily driven by accretion in cash flow and earnings per share and the ability to continue to do that on an ongoing basis. The price of these assets are at high valuations today. So as we do our math, we don't chase multiple expansions and things like that. It has worked for us on a mathematical basis that actually we can see it adds shareholder value.
I'd argue today that the stability of our cash flow is very utility like and we haven't had to chase that kind of asset at higher prices. As Stan said, if we can do sort of in corridor rate regulated expansion at a 6x build multiple, that adds tremendous shareholder value. So as we talked about our growth rate of 5% to 7%, it's reflective of where we've been historically and where we think we can yield a company this size, a company that pays out 40% of its cash flow as a dividend, 60% reinvested. That's the kind of growth rate that you get. The growth rates that we've achieved above that 5% to 7% have been driven by some tailwinds, a large acquisition, falling interest rates, a number of those things, which you'll get to a short term But I But I would argue today that we're very utility like.
And if you look at our Canadian rate regulated business, which I think has those most of those characteristics, that's the largest growth component of our business going forward. So that's where our focus is. Not to say that we wouldn't look at acquisition opportunities, but I would say that those aren't presenting themselves today at a price that we believe can drive shareholder value.
Thank you. So we're looking at $3,000,000,000 to $4,000,000,000 a year of natural gas opportunities. Russ, can you comment on maybe where the balance of the reinvested capital will go? Will it be power, linear infrastructure transmission, maybe other value chain extensions visavis LNG export capacity or other type of hydrocarbons, maybe NGLs, refined products? How can you see the world unfolding?
Going back to our self funded model, Francois might not augment my answer here. But going back to our self funded model, we drive the greatest value by reinvesting our free cash flow and spending the debt capacity that's associated with the retained earnings that we drive on an annual basis. So take a number, the $5,000,000,000 a year. So if we're doing $3,000,000,000 to $4,000,000,000 on the gas side, in terms of our free capital that we have available, we've got $1,000,000,000 or $2,000,000 available. I think of things like Bruce Power, for example, that is our share of that build is, again, pick a number.
We don't know exactly what those are going to cost. We have 5 more reactors, a couple of 1,000,000,000 a reactor, 2,000,000,000,000 to 3,000,000,000 a reactor. Our share in real dollars could be up to another $10,000,000,000 over 10 years. So pick another number of say $1,000,000,000 a year. So now we're at $5,000,000,000 a year.
And we looked at any other sort of power opportunities that may arise, whether they be storage opportunities or new gas fired opportunities in our core regions. As I think about our liquids business, for example, is what's driving that Permian gas production growth is really crude oil that's behind it. That crude oil has got to find its way to export markets in the Gulf Coast. We think about still growing production in Alberta on the crude oil side that needs to be connected to Edmonton Hardisty. We've got expansions that have been approved on our Grand Rapids system, for example, that are approved.
Our Hardisty pipeline has been approved as well. So while we're not seeing the growth rates we saw historically in Western Canadian supply, production continues to grow and that production has got to find its way to market and we continue to sign contracts to do that. So I do expect that we'll see continued growth. Paul will talk about that in our crude oil business as well. So I think as I mentioned to a number of folks last night, as I look at our self funding model is one of the things that we're going to have to employ some discipline around capital allocation to allocate capital to those projects that give us the very best returns.
And we're probably not going to pursue be able to pursue all of the ones that are in our corridor without accessing different pools of capital going forward. But as I said, something that we hadn't included was things like the Coastal GasLink project that will emanate new opportunities. As I think about West Coast LNG, for example, there are a number of projects that are out there. Is we own a corridor that's a fully permitted pipeline through to Prince Rupert. Don't know where that will go in the coming years.
Obviously, we're getting inbound interest in the Eastern East Coast LNG project, Saguenay is they're looking at a reversal at Canaport, those kinds of things, which will drive incremental expansions of our system. So things we haven't seen yet will continue to rise going forward. So that's my long list. I don't know if anybody else wants to augment those.
Just a very quick follow-up question for Francois in Mexico. I was intrigued by a comment you made. There's a bit of white space. Everywhere else in North America, the pipes are full. Can you comment on how much white space there is and kind of what sort of opportunity there is?
Now by white space, you mean in terms of buildings or connections from the basins into our assets in market?
Yes. Well, what's the utilization, I guess, effective utilization rate versus the 93% elsewhere?
Sure. So in the Northwest where we have the systems that are predominantly being utilized, we're somewhere between the mid-50s on one system and sort of mid-70s on the other. And on our systems in Central Mexico, we're more in the 25% to 40% range depending on the system. And obviously, we'll be looking to increase that. So there's plenty of room for us to actually add connectivity.
I fly over the area. So I'm very optimistic that we're going to be able to add load here as now we finally with Sur de Texas being put in service, increased the supply of very inexpensive natural gas, but to the tune of 40%. And I think you're going to see a lot of industrial activity come to Central Mexico.
Okay. Sorry. Pat, go ahead.
Pat Kenny, National Bank. Just on NGTL, as producers continue to high grade their drilling activity and their production more towards Northwest Alberta and into BC, just wondering if there's an opportunity maybe to restructure or splice the tariffs across the system, maybe tilt the revenue requirement more towards the economic prolific plays up in the Northwest and in turn maybe reduce the tariffs for the central part of the basin and perhaps in turn also support future CapEx opportunities?
We have been doing a lot of work with our customers. So it's a collaborative effort to take a look at the rate design on the NGTL system. It's something that we're doing to kind of better reflect those flows in the system. So if you think about 10 years ago or so, about 28% of the basin's volume would flow to inter Alberta kind of markets. Now it's about 40% of the volume.
So the volumes have changed pretty significantly including where the supply is coming from. So the proposal we have in front of the CER right now reflects the outcome of that collaboration. Now it's not something that the industry is completely aligned about, but what it does is applies those principles around cost causation and where flow emanates and where the markets kind of pull it to better kind of reflect exactly what you're talking about. So that's in front of the CER right now. And as I said earlier, we'll be in a hearing, I think, in a couple of weeks to just have our final dialogue on that.
But we are constantly looking at tweaks on the system to make sure that the tolls and the services reflect the needs of the industry and the way the basin is moving.
Go ahead, Rob.
Yes.
Thank you. Rob Hope, Scotiabank. Wanted to follow-up on Linda's and Ben's questions on capital allocation. It would seem that over the next couple of years you're pretty full up on your equity self funding model as you do have a number of in quarter growth opportunities. But you also did mention M and A.
When you're looking at M and A, is this longer term in the plan to backfill some of the growth, we'll call it 2022 and beyond? Or are you looking at the market with some distress in some U. S. Opportunities and seeing a potential to add assets at good valuations?
I think as we have always done is getting ourselves back to self funding model and ensuring that we maintain our credit ratings and access to debt and equity capital markets on a cost competitive basis is very important to us. We don't know when those opportunities will arise. We don't actually put them into our plans. What our experience has been is that there is some dislocation that occurs in the marketplace and that's when very attractive assets come for sale. We don't covet buying what I would call marginal assets.
We like to access what we call the crown jewels in various portfolios. Those usually don't come available there is some financial dislocation that occurs in the marketplace. So that's what we position ourselves and wait for. If it was to occur tomorrow, we would act tomorrow. I'm not saying that that's available to us, but if it's 2 years from now, that's what's when we'd act is that we're not going to try to force something that doesn't add shareholder value.
So we'll bide our time and we'll wait. And if something arises that Columbia like for example, we were we'd always done our math and kept it an eye on that asset. When the MLP market started to contract, we saw an opportunity to advance the conversation. And that's what we'll continue to look for is some event that would allow us to access good assets at reasonable price. And that's why we think financial strength and flexibility in all points of the cycle is important.
And every time that one's occurred, whether that be the British Energy bankruptcy in 2,002, 2003 that allowed us to access Bruce Power, for example, That's the kind of thing that we're looking for ANR. We bought out of the El Paso. Financial difficulties that they had as they were carrying an E and P company and a midstream company. GTN, we bought out of the USGen bankruptcy. So as I think about when we've acted in the acquisition market in a large way, for the most part, it's been when the assets at a reasonable price.
We've made mistakes in the past around things like Ravenswood, for example. We saw what we thought was a good asset but acted at the wrong time in the cycle and that was very painful for us. So I think we've learned our lesson that going after assets at the wrong point in the cycle and if you overpay for them, even if you can operate them extremely well, your return on capital employed never gets you to a place where you can add shareholder value. So we'll be very careful about how we approach it. But I think our narrative around M and A is that we're not frightened of it.
We'll have the capacity to access it when we when it comes available and that's what we're trying to do is just trying to position ourselves for those times.
And then maybe just as one quick follow-up there. I'm assuming and in the past you've said that your the crown jewel assets that you cover would be large contracted low risk assets, But do you need just a discrete asset or do you need a growth profile that would be additive to TC Energy's longer term?
I think that the things that we've looked for have always been sort of growth profile. So and they don't necessarily have to be contracted upfront. Can we turn it into a contract profile. If you think of Bruce Power, it was 100% merchant when we purchased it. But we had a vision of what we could do in terms of both growth.
At the time we bought it, there was only 2 operating reactors. Now we'll have 8 operating reactors and a growth platform going forward. It's fully contracted through to 2,064. So it's a vision of what you can build. Essentially, you have to take risk to make money.
What we look at is the risks that we're good at managing, contractual risk, laying off risk, construction risk, those kinds of things that we're very good at managing. So we'll take on the risk and then we'll look to mitigate the risk. I think something like Colombia, it had a large cash flowing asset. The contracts weren't that as long term as they are today, but it had a great growth profile along with it. So we look for those attributes, something that is well positioned in the marketplace and has the ability to either is contracted or we see an opportunity to contract up and stabilize those cash flows and an opportunity to reinvest cash flow on a go forward basis.
If you look at what we've divested ourselves of, primarily what I'd say is good cash flowing assets that we didn't see an opportunity where we could see growth or where we could add more value to those assets. So we've monetized those to the parties that are looking to buy those kinds of assets. And the marketplace for that is very attractive right now with low interest rates and look to redeploy that capital into assets where we thought they were is a better long term growth profile.
Rob Catellier from CIBC Capital Markets. Thanks for your comments this morning. That last answer actually addresses some of my questions here. But knowing those strategic criteria for acquisition, I'm curious as to how important an investment in LNG terminal or something similar is to the company? And what risks would you be willing to take associated with that?
From your previous comments, not just today, but in other venues, it seems like the contracting profile is something that's very important. But in terms of LNG terminal and what risk are
you willing to assume? I'll start. And just for clarity around something like an LNG terminal, certainly a high level of contracted capacity would be a prerequisite to any kind of opportunity we pursue. It is the sheer scale of those and the there's enough other risks in those kinds of opportunities. Construction costs, for example, has been one that has been difficult for most parties to manage.
So I mean, there's only so much risk you can take on in those kind of projects. And commodity, global commodity risk is probably not one of them that we would be willing to take on unless you had some clear path to mitigating that or laying off that risk to some other party. So I would say that we are not afraid of the notion of moving downstream into the LNG market. But I think as we've said before, we'd probably have to have the same construct as we have with the rest of our portfolio. I think what we'd be looking for is if there was construction cost risk and things like that, those may be things that we might be willing to take on because we have mechanisms by which we could lay that off to construction contract and things like that.
The other thing that I think that we bring to the table is an operating capability and a capacity to grow those assets over time on an incremental basis. So I would just be clear on that, that experience with and don't have a lot of experience on how to lay off that risk. So it wouldn't be one that we would probably entertain.
Thank you.
Go ahead. Robert? Thanks. Maybe just continuing on your potential acquisition criteria. Russ, you talked about a number of assets that maybe on your radar screen is kind of biding your time.
So can you just talk about how many, roughly speaking, assets you might have on that longer term radar screen? And you can give some colors to breaking down, is it mostly gas pipelines or is there power, are there other platforms that you'd be looking at?
I think both Don and Francois and their teams, they manage the inbound. I can tell you the inbound is considerable on an ongoing basis of ideas that come past us. But I would say that the themes that we've iterated here over the last couple of days around utilities, LNG, that seems to be the space where I would call that the larger scale things are being passed in front of us at the current time. As I said earlier, we don't see anything that's transactable of what we're seeing now. But those are I guess a couple of buckets of larger themes.
Francois, you guys see the inbound every day. Is that approximately what we're looking at?
Yes. That would be accurate. And there's a lot of capital out there chasing these private capital looking to partner. We bring something to the table that they don't, which is very valuable corridors. So they're happy to deploy capital with us, and we have operating and strategic, we have construction expertise.
So that gives us a lot of flexibility to look at a range of different types of assets. One of the things that we think about is our long term resiliency and how could the energy value chain evolve over time and how do we maintain resiliency and our competitive advantage and the market position we have today in the different ways that the energy world could unfold. So longer term, we think about those issues, and those are some of the criteria that we consider. If you
think about things like as well like on the specific asset side is that we do keep an inventory of assets that are complementary to our existing business, primarily pipelines, both on the gas side, Canada and the United States and in our oil pipeline business. Again, those are assets that are in somebody else's portfolio and they're usually pretty important to their portfolio. So but we do keep an ongoing view of what those assets are doing and how they would fit with ours. If they were to if those situations were to rise where we could buy those assets or pull those assets out. So we do keep an ongoing inventory of
those as well. Okay. Maybe just finishing on the mainline and what we can expect. The previous agreement was pretty significant by decoupling the Eastern Triangle and effectively loading rate base and tolls on effectively Marcellus producers. As you look at this next framework, and I know, Tracy, you had the answer on the last conference call that maybe we won't see anything radical at least upfront.
But what are some of the different things that you are talking about with your customers that may be more of a major change in the framework to help improve the competitiveness of Western Canadian Gas?
We can't say too much right now Robert because we are in discussions. But let me just say this will this framework will continue that separation of the Eastern Triangle from the Western Mainline. So the Eastern Triangle will kind of stand on its own. The Western Main Line is interesting to us in the industry because it is that conduit from the WCSB into the Eastern markets. And it in effect if we use it well reduces the distance between that basin and the market.
Now we have seen seen there's something that happens on the regulated pipes when volume goes up, tolls go down. And if we've seen volumes go up on the Western Mainline, we've seen that asset contract up considerably. And that's, as I said earlier, when the magic happens. So as we think about what this framework should look like, there's different ways of using that asset. And we're talking with our customers in both in the West and the East around some of those different ways, including how we may create services, including what the range of tolls may look like, the stability of those tolls, the duration of the agreement, all of those types of things would be on the table and be part of this dialogue.
So we are, I would say, it's going very well. And we are both or all of us focused on how to use that asset properly for the benefit of the basin and the markets in the East.
Thank you.
Back on follow-up with U. S. Capital. Stan, you talked about going in for more frequent rate cases. Why now?
What's changed?
2022 is a big rate case year for us. I think we have 4 rate cases planned, Columbia, ANR, GTN and Great Lakes. What has changed is the amount of maintenance capital that we're spending and the time lag between when we're spending that maintenance capital and ultimately recovering it in a rate case. In many cases, we have more moratoriums in place that preclude us from making filings, but in some particular instances, we may have the ability to accelerate that filing to recover the maintenance capital in particular. So that's the main driver.
Maybe a subsequent factor would be implementing some modernization programs on some of the other pipes like we've done on Columbia and ANR, where we could spend what effectively looks or feels like maintenance capital otherwise, but create a mechanism to recover those dollars faster or in between rate cases going forward. So it's really just making sure that we're matching up to the greatest extent possible when we're spending money and when we're getting recovery on those dollars.
Thanks. And as a follow-up, I know that I appreciate your comments on the counterparty exposure. But in the event there are bankruptcies by some of these Northeast producers, they have a portfolio of Feet. Where do you think the competitiveness of Columbia Gas and Columbia Gulf fall in those portfolios?
In the aggregate, our footprint is as good as any. When you look at TECO pool pricing, you get a premium price relative to Dominion or TECO. So all things equal, a producer who has long transport capacity on Columbia is going to want to keep that capacity to get a higher netback for their gas at the end of the day. That said, it really is a producer by producer analysis that you have to go through. Most of our producers have what I would consider a core acreage, core acreage being Southwest Marcellus, which provides them with a premium over somebody who is outside that core area.
The ones that we worry about are the latter, the ones that have acreage outside the core area, but they make up a very, very, very small portion of our overall producer portfolio.
Okay. We'll take one more. Go ahead. And then we'll stop for a break. As always, as we've highlighted, to the extent you have other questions, folks will be around through the break and at lunch.
Go ahead.
Hey, guys. Michael Lapides of Goldman. Thanks for taking my question. One housekeeping item and then one kind of longer term one. The housekeeping, the 2022 guidance for the Canadian Gas Pipeline segment, how are you all treating Coastal GasLink in that?
Is that are you assuming that as kind of a full ownership or 25% ownership, especially since you get paid during construction? That's the first question. Then the second one on Mexico, just given some of the permitting challenges over the last couple of years for you and some of the other pipeline developers, How are you thinking about the appetite for growth in Mexico for new capital projects across new corridors?
I'll start on coastal. So for Coastal Gas Inc in 2022, it doesn't come into service until 2023. So it's not in rate base until 2023. And when we put up numbers for 2023, we adjusted the Coastal GasLink to
what we anticipate
will be something like a 25% ownership level.
Project was set
up where
you're earning
a cash return during construction. So, thought
the project was set up where you're earning a cash return during construction. So it would actually be contributing either on the cash flow statement or even on both the cash flow and the income statement. So you're saying you're excluding it from the EBITDA analysis, but you're getting cash?
So we don't as I said a little bit earlier, our analysis on the regulated pipes is more of a net income analysis. But we do, as you say, it comes into service, it goes into rate base in 2023. In advance of that, we do have cash AFUDC that comes into our cash flow.
It essentially is going to be a below the line item, Michael. So you're not going to see it in EBITDA.
With respect to Mexico, as I mentioned, I think it's going to be sometime as the demand grows into the backbone infrastructure before new capital outlays are required for greenfield projects in new market areas. We're always interested in building infrastructure under long term contracts with U. S. Dollar denominated contracts with creditworthy counterparties. So if those opportunities present themselves again down the road in Mexico, we'll absolutely consider them.
I think maybe just in Mexico, Mexico is not immune to permitting and siting issues that we see in the rest of North America. So we actually don't see it as different. In Mexico, one of the differences is the government's role in consultation with the communities and indigenous communities. Constitutionally, resides with the government. And you don't have the same rights of eminent domain, for example, that we see in other parts of North America.
So as Francois said, we're not shy of it. Obviously, Mexico is going to need new infrastructure, whether that be gas transmission or even electric transmission. And as we've looked at those, certainly, it has to be in partnership with the government in terms of how we're going to permit and gain access to those right of ways required to build linear infrastructure. My belief is that they're going to continue to need it and they're going to have to work through the mechanisms constitutionally and legal and otherwise defined path to make that happen. It's going to be core to their economic growth going forward.
So I actually do see them they're mindful of those issues. And as we are, as we try to manage our risk and just like we do in the rest of North America as we look at a project, will look at what those risks are and how we're going to manage them and mitigate them. And certainly, we believe that they will work through their issues. And right now as you point out there's a few bumps along the road, but there's a few bumps along the road in all places in North America and Mexico is not unique in that regard.
Thanks very much. So at this point, we're just running a couple of minutes over, but we'll stop for a break now. I could ask people to make their way back into the room at 10:15. We'll restart at that point with Paul Miller and an overview of our Liquids Pipeline business. Thanks folks for making your way back.
Hopefully, you had a chance to catch up with a few members of our senior leadership team over the break. As I've mentioned, they'll be around through lunch as well. But in the interest of time, we'll get started again here. Paul Miller, who is President of our Liquids Pipelines business, is going to kick off, if you will, the second half with an overview of everything that's going on in that business over the next 30 minutes.
Thanks, David, and good morning, everyone, and thanks again for joining us here today. So I will start off with an overview of our pipeline system, which runs from Northern Alberta, the producing areas in Northern Alberta, down through the Illinois market and down to the U. S. Gulf Coast. And our vision is simple, to provide a direct, safe, reliable, contiguous path from the supply areas down to the marketplace in the U.
S. Gulf Coast and pick up additional supply and serve additional markets along the way. Our footprint is proximate to major producing areas, and we access about 6,000,000 barrels per day of refined capacity. This pipeline network is underpinned by long term take or pay contracts with creditworthy counterparties. And the spot capacity that we are required to set aside is remains in large demand.
So we continue to continue this vision by securing additional support for planned pipelines, accessing additional supply and accessing new markets. We have 3 primary sources of EBITDA, our highly subscribed take or pay contract volume, which makes up about 80% of our total EBITDA, our spot revenue and then the revenue generated by our marketing affiliate. Our contracts are largely structured around a fixed variable tow design, where the fixed portion provides us with a return of a non capital. And then the variable portion provides for a flow through of the operating costs, the recovery of those operating costs, including maintenance capital. Our pipelines are contracted in a range of about 80% in the case of Market Link, up to 100% in the case of some of our Alberta pipelines.
And our marketing affiliate generates EBITDA around these pipelines, our pipelines as well as 3rd party
pipelines. So I'm first going to
take a look at Canadian production, Canadian producers. And this slide here represents global producer ESG scores from 3 different firms. And you can see where Canada is situated on the left there at the top end of the range with a little maple leaf on top of the column. The message is clear and consistent. Canadian oil producers rank at the high end of ESG scores.
And so Canada possesses the unique and successful combination of high ESG scores and high reserves and production of those reserves continues to grow. So the market fundamentals remain strong for TC's Liquids business. We have an increasing supply of Canadian heavy crude oil and a decreasing supply from Latin America. The U. S.
Gulf Coast refiners the most profitable in the world and they need access to heavy crude oil. So this creates opportunity for further market penetration for Canadian heavy crude, potentially serving the entire market within the next 2 decades. And this opportunity in the U. S. Gulf Coast aligns very well with the TC Liquids business.
Oil sand production is sustainable, cost effective and growing. TCE provides direct and cost competitive transportation to this market. Latin American supplies are in demand. The U. S.
Refiners will retain a high utilization rate as they meet both the domestic market as well as the global market. The U. S. Gulf Coast is the natural market for Canadian heavy crude oil, and Keystone is the most efficient form 2 years has been light tight oil production, particularly out of the Permian. U.
S. Demand for light oil is fully satisfied, so much of the incremental production is being exported. And we'll participate in that opportunity by connecting directly to these terminals, which increase the attractiveness of our system. Looking forward, the story for 2020 will be the rapid build out of pipeline capacity, again, particularly out of the Permian. This pipeline capacity will exceed the production and will exceed the demand for that capacity.
There will be about 2,000,000 barrels per day added, plus or minus chemo2000000 in this time period, and that will have an impact on differentials and that will cause differentials to tighten up a bit. So we monitor and we react to these trends and changes very closely. Back in 2017, we saw the increase in production coming. We saw that, that production and the call and transportation capacity will exceed the transportation capacity. So we very quickly started increasing the capacity of market link from about flowing 400,000 barrels per day in 2017 to an excess of 700,000 barrels per day in 2019.
And as we increase that capacity, we increased our contract volume. It's a good environment to attract new contracts and it's a good environment to attract spot barrels. So in 2020, when we see this additional pipeline capacity come into place and those differentials narrow, we will maintain a stable cash flow with contracts of about 80%, which partially insulates us from some of the volatility and some of the low differentials and low pipeline transportation values you're going to see here in 2020 going forward. And like in 2017, we're not going to sit back idly. We're working with various producers in various basins, Bakken, SCOOP, STACK, DJ, and then to encourage that production to come into Cushing and onward down to the U.
S. Gulf Coast. Some of our activity will include new competitive tolling to divert that volume to Cushing and then down market link. We'll continue with the Keystone capacity enhancements and continue to direct that volume to Cushing and down the path. And in 2020, we're going to increase a number of our connections, both in the Cushing market as well as the U.
S. Gulf Coast market to increase the flexibility for our shippers. We'll also continue the differentiation of Market Link from other carriers, be it through our ability to deliver to different future contract pricing points in the prompt month or continue to take advantage of our exceptional product quality. Cushing as a market hub will stay relevant and we are very well positioned in that
Cushing marketplace. And we'll apply
the same approach of active management to the entire pipeline network. We have a very good strategic quarter right down the Mid Continent. We are close to the emerging supply and we're close to the marketplace. So we'll continue to expand that footprint attaching to more supply and to attach to more market through connections and optimization of the system. Over the long term, we'll look to repurpose perhaps other assets into crude oil service.
And we're working on a number of business development initiatives and they are in various stages of development. Turning now to Alberta. Our intra Alberta market is a very important part of providing that seamless transportation from production down to the marketplace. In 2019, we successfully completed the construction of our White Spruce pipeline, which moves barrels from CNQ's Horizon facility down our Grand Rapids pipeline, moving those barrels into the Edmonton region. We did monetize a portion of our Northern Courier Pipeline for $1,150,000,000 of proceeds, retaining 15% as well as the operatorship.
And we continue to secure support necessary to move forward with other pipelines in the Alberta marketplace, including the Heartland pipeline, which will complete that contiguous path. So we have many growth projects besides Keystone XL. To be of note in Alberta, are the looping of our Grand Rapids pipeline. Grand Rapids loop, which would move volume from Northern Alberta down to the Heartland region just outside of Edmonton. It's a $700,000,000 project.
It is today fully permitted by the regulator. It is regulated by the Alberta regulator. The Heartland pipeline also regulated by the AER is a $900,000,000 investment, which would connect with the Grand Rapids pipeline in the Heartland region and move those barrels down to the Hardisty marketplace or the Hardisty hub, which is the origination point for Keystone and potentially Keystone XL. That is also fully approved by the regulator. As is Keystone Hardisty Tank Terminal, which is a $300,000,000 tank terminal in Hardisty, which will provide additional storage and batch accumulation services for Keystone and Keystone XL shippers.
Looking south, the U. S. Gulf Coast Refining Center needs more heavy crude oil, and we remain committed to provide additional transportation for that supply to Keystone XL project. But we are managing that project very carefully and very tightly as we work through the various legal and regulatory matters. On the regulatory side, we have our Canadian approvals.
We have approvals from the 3 states the pipeline travels through, that being Montana, South Dakota and Nebraska. On the federal U. S. Permitting, we have the new 2019 presidential permit. The State Department has issued the draft supplemental environmental impact statement, which refreshed some of the prior work as well as looked at the new route to Nevada, Nebraska.
And the draft SEIS concluded that the construction and operation of Keystone would not have any significant environmental impact. We anticipate that draft SEIS to be finalized here before year end. And into Q1, we would look to have the Bureau of Land Management and the Army Corps of Engineers finalize their work and issue their decisions. The key to managing last mile risk is to have an unencumbered clear line of sight to construction. You don't want to be starting construction and be delayed, idling your crews, demobilizing them, remobilize them.
So we're working towards that clear line of sight to construction. It means getting your regulatory permits. It means mitigating your legal exposure. It means getting your land, your material, your crews, your contractors, finalizing your engineering and freezing your scope. That is what we're doing now.
And at that point, when we've wrapped all these matters and have them behind us, that's when we'll be in a position to make a final investment decision. I'm often asked about the political aspect of the regulatory process. We follow the regulatory process. Regulations lay down the standards and the process to follow. We follow that process.
We meet and exceed those standards. And in doing so, if we receive our regulatory approvals to proceed, that is the basis and the authority on which we proceed to construction. Ultimately, Keystone XL is a very important project. It's a very important pipeline for Canada and U. S.
It is fully contracted with Canadian and U. S. Producers as well as U. S. Refiners in the U.
S. Gulf Coast. Our strategy is working. Our business model works. We generate stable EBITDA from highly contracted assets, again in the range of about 80% of our total EBITDA comes from those contracts.
We are well positioned with a competitive footprint to attract additional contracts and spot volume and our marketing affiliate captures value through both locational and time differentials. With the Permian build out over the next 2 years, there will be some volatility, there will be some choppiness. And our results will come from our base contracts of stable cash flow as well as what value we capture from this market volatility. And directionally, we're showing that in that light blue cap on top of the column in 2022. So going forward, we'll keep doing what we're doing.
Our focus will be the safe and reliable delivery of energy to our base business and we'll enhance that base business through capital additions by extending our reach to both supply and to the marketplace and exploiting the market volatility. Keystone XL will remain a focus as we carefully and methodically advance the project and we'll look to grow the business through BD initiatives and at the same time increasing our contracted EBITDA. Thank you. I'll be happy to take any questions you may have.
Thanks, Paul. And similarly, if you could just raise your hand, we'll get a microphone to you quickly and be happy to take your questions. That could be that may be a record. Sorry, we've got one back there.
Hey, guys. Michael Lapides of Goldman. When you think about repurposing assets, how would you think about what's on the hit list for that? Like what are the potential ones where the greatest opportunities exist? And how far along in that process are you?
Thank you for the question. Whether it's repurposing existing assets or whether greenfield development, our approach is to advance the project to the stage where it's commercially secured and all the work is done before we disclose what those projects are. What I can say is that it's going to be consistent. They will be consistent with our strategy, which is simply attach supply to market with highly contracted underpinning by creditworthy counterparties. We have an advantage in that footprint.
There's always synergies around citing new greenfields as well as repurposed assets, acquisitions for that matter within your existing footprint. And that will be where we retain our focus.
And then one quick follow-up. You've got significant intra basin pipeline capacity. You've got long haul existing with obviously Keystone and MarketLink and some development along the way. How do you think about the opportunities for either increasing presence in storage for crude as well as gaining a foothold in export?
Sure. A couple perspectives there. We have been over the last 2 or 3 years increasing our capacity on the storage side. Just last year, we added an additional 1,000,000 barrels of storage at our Cushing terminal. And we're in the process of adding about 700,000 barrels of storage at our Houston terminal.
We view storage as a means to help with the differentiation of our pipeline system. It helps with market disruptions. It helps with product quality. It helps with blending and everything else. So I think storage will continue to be very important part of our infrastructure.
Thanks, Michael.
There is a second part, Michael, and I'm sorry, I can't remember. Export. Oh, export, yes. No, we I think the more flexibility and the more optionality you create around your pipeline system, the more valuable it's going to be, both from a refiner looking for diversity of supply as well as a producer looking for markets to enhance netback. So we continue.
And in 2020, we are going to increase our connections to various terminals, including export, probably add 4 additional connections here in 2020. We've looked at the opportunity for direct investment into export terminals and that's not out of the realm of possibility, but they have to be within our risk parameters and have a high degree of long term take or pay contracts for us to invest in those types of facilities.
Great. Linda?
Thank you. I know there's a lot of moving parts with Keystone XL, but you're better equipped to think about some of the puts and takes on the cost side than we are. Can you give us your updated thoughts on some of the cost pressures upwards, maybe areas where costs are coming lower than planned? And kind of net net, how we might think of the magnitude of the cost increase? And I guess, part B of that would be how much of that could be socialized to your shippers versus potentially absorbed by TC Energy?
Sure.
So on the cost side, two aspects to cost. The first is material cost and we have much of the material on hand today, the valves, pipes, pumps, motors, etcetera. So I think we have stability from that perspective. What pipe we do need to buy going forward, be it in Canada or in the U. S, we believe that there's ample mill capacity, both from a quantity and a quality perspective to serve that requirement.
The next component of cost would be your lay contracts, your contractors. And that remains a fairly competitive market, and it's going to ebb and flow depending on what other projects are underway. And we watch that very closely. So we do see costs moving around a bit, but they're still within the fairway of
Yes. Paul, just on the Keystone spill, and I know the investigation is still ongoing, but if it is determined that an accelerated integrity program is required, can you just remind us how that incremental CapEx might be recovered from shippers within incremental or an increase in tolls?
Certainly. Our toll design separates operating costs and capital cost, if you wish. So the capital, the fixed toll provides that return of an owned capital. And our operating costs are recovered through the variable toll. And those operating costs include maintenance capital.
And so to the extent that we have to put in additional maintenance capital, additional integrity work, those form part of our variable toll, which ultimately pass through to the shipper.
Okay. Great. And then I know it's still early days. You'll be operating at reduced pressures. But any time line to get back to full operating capabilities and also be setting the stage for that 50,000 barrel a day expansion?
Yes. So it is early, Pam. There's no time line yet. How the process works is we have extracted that piece of pipe that was damaged and or that suffered the leak and we've sent it off to an independent lab. They take about 2 months to determine the root cause failure analysis.
In the meantime, we will be operating under the derate. And again, the derate is not the entire pipe. It's select sections of the pipe kind of on either side of the feature, if you wish. And so we'll get the results of that root cause failure analysis. We'll see what it means, and we'll see what it means from a modifying, if necessary, both our maintenance and our integrity program.
That will set the stage for us to resume the full pressure and ramp up the volumes at that point. So key for us though is to find out what happened and restore the pipe to full pressure, full capacity safely.
Okay. Sorry, Rob.
Sorry, just a follow-up on Patrick's question. So if we go back to 2017, the spill that occurred in the U. S. As well, you were able to mitigate much of the impact in terms of the volumes going through the pipeline despite the pressure restrictions. So can you speak to us how you think volumes will ramp up on Keystone during this 20% reduction in the pressure in the associated segments?
Yes. So it's early days. We don't have a clear timeline on when those volumes will ramp up and what those volumes will be as we ramp them up. But we will look to mitigate any impact using things like DRA. We will look to try to optimize the system around the pressure de rate, but it will mean that the volumes will be less than what we were flowing at prior to the spill, which was about 590,000 barrels per day.
It's just that we will mitigate to the extent we can, but it will take some time to determine the cause of the leak and what measures we need to take going forward.
Thanks, Rob. Okay. If that's those are all the questions for Paul. Paul, thank you for providing an overview of liquids. And Francois Poirier will make his way back to the stage now amongst his other capacities.
Francois is President of our Mexican sorry, of our Power and Storage business. Francois is going to provide an update on that now before we turn it over to Dawn.
Thank you, David. As I did with Mexico, I'd like to start with setting a bit of a baseline on what our power and storage business is today. We have ownership interest in 10 power plants, primarily based in Alberta and Ontario, but also ownership of the Becancour generating station in Quebec and the Grand View facility in New Brunswick. Our net interest is approximately 6,000 megawatts made up of low cost, low emission based low generation underpinned by long term contracts. We also own about 115 Bcf of non regulated natural gas storage in Alberta, which makes up approximately 1 third of the total storage in the province.
And I want to emphasize as we've talked about here throughout the morning that we view our power and storage business as a core aspect of TC Energy's portfolio going forward, and we intend to grow this business in a low risk fashion consistent with our risk preferences and historical practices. A bit of a breakdown here, with a bit more detail. You can see our net owned capacity by plant, by counterparty and by contract expiry. We wanted to reflect here some of the assets that are held for sale so you could get a sense of the megawatts and contract profiles post the sale of the Ontario thermals, which is scheduled to close in late in Q1 of 2020. We've had a busy year in 2019, delivering solid financial results and also, importantly, helping generate internal equity to fund our industry leading capital program.
In addition to our 2018 divestitures of our solar and wind assets on extremely attractive terms, in May of 2019, we completed the sale of our Coolidge generating station in Arizona to our offtaker Salt River project for proceeds of approximately US450 $1,000,000 And as I previously mentioned, in July of this year, we entered into an agreement to sell the interest in our 3 natural gas fired plants in Ontario for approximately $2,870,000,000 We expect the sale to close by the end of the Q1 of 2020 subject to closing conditions including regulatory approvals and Napanee reaching commercial operations as outlined in the agreement. As we mentioned previously, in March of 2019, we experienced an equipment failure while progressing commissioning activities at Napanee, and I can tell you that the replacement equipment has now been delivered to the site and commissioning activities have restarted and we expect to reach COD on Napanee late in Q1 and then closing on the transaction in fairly short order. I want to say that Ontario continues to be a core market for us and our investment in Bruce Power remains a high priority and I'll provide a little bit more detail on Bruce Power in the ensuing slides.
We also, in 2019, continued to operate and manage our assets safely and responsibly, as exemplified by our successful planned outage at our Fort Macau facility, which we completed ahead of schedule and included a gas turbine overhaul and replacement of a steam generator. Now our investment in Bruce is significant and it's long term. The Bruce Power Life Extension program is key to providing the province with emissions free, low cost, reliable electricity. The provincial government has publicly voiced support for the nuclear industry in general and Bruce Power in particular. And I think the call out box here says it all.
Bruce Power provides 30% of Ontario's electricity at 30% less than the average cost to produce residential power. The facility is operating safely and having achieved excellent safety and operating results for many, many years now. And Bruce is finding ways to improve overall site production as exemplified by Unit 1's eclipsing of the previous record of 3 61 days of continuous generation and the highest power output production over a continuous 3 year period from 2017 in its history from 2017 to 2019. Now you can see on the slide on the lower right, the major component replacement planned outage schedule. The Unit 6 MCR is scheduled to begin in January of 2020 for breaker open and both the MCR and the associated asset management programs remain on schedule and on budget.
The project scope has now been frozen, engineering is complete, all prerequisite projects are either complete or on track and the contracts have all been executed and contractors have been mobilized. So we're ready for January. As a reminder, the increased capital for the major component replacement and asset management programs are accommodated by an increase in the power price, and we received in April of 2019 an increase from $68 a megawatt hour to $78 Future MCR related price adjustments are also contemplated as we progress through the full program beyond Unit 6 from 2022 and beyond. Our share of the life extension program through 2023 is 2,200,000,000 dollars and we've got about $900,000,000 of that spent to date. And the remaining program capital cost estimate in $20.18 for the remaining 5 units is $6,000,000,000 We believe the Bruce Power MCR and Asset Management program is a sound long term investment.
It will generate robust risk adjusted returns on an $8,000,000,000 capital program underpinned by long term contracts spanning to 2,064. Throughout the first few MCRs, as we continue to invest capital, Bruce will generate steady equity income. And as generation increases beyond the 4th MCR, we will see significant increases in equity income and cash flow, which will be sustained until contract expiry due to enhanced reliability and fewer outage days. And as generation increases beyond pardon me and Bruce Power is also evaluating opportunities to increase site capacity, resulting in reduced emissions and system costs in the province. And you may see some announcements in to that effect over the coming months.
Now as you've seen the size of our power portfolio decrease as we've rotated capital into our pipeline businesses to fund growth, you may wonder if this business will continue to be a priority for TC Energy. And as I said in my opening remarks, the answer is yes. Over the course of the last 20 years, each of our three businesses has had its turn generating investment opportunities. Over the last few years, it's been our pipe business and the role of the power and storage business has been to generate internal equity to help fund that growth. Going forward, North American power markets provide strong fundamentals and many avenues of growth for TC Energy to pursue.
As coal's market share continues to fall and replaced by natural gas, wind and solar capacity, we will see opportunities to continue to develop projects. Demand growth will be driven by economic growth, demographics and policies supportive of electrification and energy efficiency. And whereas you'll see us continue to adhere to our conservative risk preferences and look to make investments underpinned by either long term contracts or regulation, you'll see us looking to diversify our investments a little bit more by
technology and fuel type.
In terms of increasing technological diversity, here are a few examples. Recently, TC Energy signed a power purchase agreement with Perimeter Solar for 74 Megawatts of offtake from a solar facility to be built in Southern Alberta. The facility is expected to be completed by the end of 2020. The PPA is structured such that TC Energy will take delivery of all energy from the 74 megawatts of capacity whenever it is produced, and the project's received all of its regulatory approvals and is being constructed by perimeter. That PPA transaction is obviously a very modest size, but it's complementary to our existing trading business and it was an opportunity to acquire attractively priced energy and remarket it.
It's a capital light way, if you will, for us to invest the solar resource in Alberta, and we like the Alberta power market. We were very supportive of their reaffirmation of the energy only market structure. We also believe in the fundamental merits of our cogen facilities in Alberta, and we would look for other opportunities to invest capital under a similar construct should the opportunities present themselves. As well in Alberta, in December of 2018, we were awarded a grant from the province of Alberta to help fund a supercritical CO2 waste heat recovery project at the Acme, Alberta Foothills Compressor Station. The company is working with Siemens to build a plant for this innovative technology, which will generate about 10 megawatts of emissions free electricity at the site.
Now if you think about the number of compressor stations we have across our entire system, there's definitely an opportunity, a very exciting opportunity here for us to leverage this technology once it's been proven out. The project in service date is 2021 with an estimated capital cost of $45,000,000 As renewable power continues to increase its market share, we also believe there'll be an increased demand for firming resources. And as such, in March of 2019, we were again awarded a grant by the province of Alberta to help fund a proposed 10 megawatt solar project with 5 megawatts of long duration flow battery storage technology. This plant, at our wholly owned site at Saddlebrook will demonstrate the first commercial deployment of utility scale storage combined with solar generation in Canada and with the proposed in service date of July 2022 and as well with a capital cost estimate of $45,000,000 and the application process is underway with the Alberta ISO. And then finally, in Ontario, we're proposing to develop a pump storage hydro project that would provide 1,000 megawatts of flexible clean energy to Ontario's electricity system, which would result in significant system cost reductions as well as reductions in greenhouse gas emissions.
In terms of comparable EBITDA outlook, in the near term, the dark bars below represent on the graph represent our ongoing base business EBITDA, with the light blue representing EBITDA from assets sold or in the process of being sold. The EBITDA growth from 2018 to 2022 will include growth from the Bruce price increase, which we received here in April of 2019, as well as from our unregulated gas storage as the debottlenecking on our NGTL system continues, and we'll see an increased potential activity around those assets. To sum up, our near term scorecard is firstly to execute by continuing to maximize the value of our existing assets through safe and optimized operations, by bringing Napanee into service and closing on the sale of the Ontario gas fired assets and by completing the Bruce Unit 6 major component replacement on time and on budget. Secondly, to advance our projects under development, specifically the 5 Bruce MCRs as well as the waste heat and solar and battery projects that I mentioned on a previous slide. And lastly, to cultivate additional low risk investment opportunities in North America with an emphasis on increasing technological diversity and investing on the theme of firming resources.
So that's the end of my prepared remarks, and I'd be pleased to take questions.
Thanks, Francois. Sorry, just go ahead, Anne.
Hi, there. It's Dean Highmore from Mackenzie. You just had
a question on the pump storage. Just sort of ballpark, what would a 1,000 megawatt pump storage project, what would the CapEx be on that? And what are kind of the next steps you have to overcome for this project
to actually happen? Yes. Thank you for the question.
Typically, we don't discuss projects prior to commercial sanctioning. This project has been publicly disclosed by virtue of the fact that it's cited on Department of National Defense Land, and there's a public consultation process that's underway. We are just embarking on public consultations, which will be starting in December of this year. The capital cost would be in the $3,000,000,000 to $3,500,000,000 range if and when the project was commercially sanctioned and we made a positive FID. Andrew Kuske, Credit Suisse.
Is the waste heat strategy a bit of a redo of what was done 20 years ago? I mean, it's more advanced version obviously with the latest and greatest technology, but if we went back 20 years ago, you embarked upon that strategy. What criteria do you need to really move forth in an aggressive fashion? Yes, it is. And it worked great the first time, but the technology was no longer cost competitive as things advanced.
So it needs to compete on a cost basis for us to be able to replicate this across our system. And the new so the new technology we're working with Siemens and we'll see what the initial investment sort of bears in terms of actual cost of production. And then ideally PPAs as you have in the past? That's typically our approach, yes.
Okay. Thanks, Andrew. Go ahead, Jeremy.
Jeremy Rosenfield, Industrial Alliance. Francois, you said new technologies and solar and storage are certainly interesting and emerging technologies that are becoming more popular. But in terms of capital deployment, certainly for a company the size of TC Energy, kind of a drop in
the bucket is the way
that I would put it. So there are other emerging technologies such as offshore wind, for example, where the size of the CapEx ticket is much larger and potentially more meaningful for a company of the size of TC Energy.
So is that on the radar at all?
So we've looked at offshore technologies in the past. We've watched the bidding process on the leases and then the PPAs in the U. S. Northeast and we found the returns to be quite moderate. It is an opportunity to deploy a fairly sizable amount of capital, but frankly, on a risk adjusted basis, didn't really compete well with our current opportunities and our footprint.
So it's something we're continuing to watch, but it's not been a priority for us.
Robert, sorry.
Thank you. Just wondering how when you're looking at deploying capital into power, how you're factoring in your returns around residual values, whether it's what you're doing in Ontario and say some of the history of the investments you've had and those plants being shut down or what you've had with Beck Concur and it's great to be paid for a plant not to run, but it's still not running?
So one of the things one of the lessons we've learned is that not specifically at TC Energy, but also as we've watched the marketplace, the history of re contracting projects at comparable cash flow streams as we're under the contracts is a mixed bag. And I think that to some extent has informed our decision to monetize some of our assets. Clearly, when you're from a policy standpoint, you continue to introduce very low marginal cost power into the stack, it makes it challenging for assets rolling off contracts to be accretive. And so as we look at terminal value and we're bidding into different opportunities, we're very conservative. That's part of the reason why we haven't been, for example, acquiring assets in the wind and solar space.
And frankly, after being unsuccessful enough times, we decided that we should probably be selling into it because the implied cost of capital of the bidders was below ours. And by our calculations, there are often very robust assumptions of power prices post contract expiry that we don't think are realistic. So especially with the chunkier potential investment on the
pump storage and it being in Ontario recognizing it's a different technology than you've ever constructed there. Do you want to be recovering pretty much all of your return within the contracted period? Or how much residual risk are you willing to take?
I think it depends on the commercial construct. You could go the contract route, you could go the rate base route, and we haven't actually landed on that. And based on what commercial construct provides us with a better return and risk mitigation around terminal value, that would determine whether or not we would need to recover a return on enough capital in the contract period if we go down that commercial structure.
Just another capital allocation question here, maybe Russ wants to weigh in. But now with ESG clearly having an influence on market valuations, I'm curious how ESG factors weigh into the capital allocation decision making process on an asset by asset basis. If we just had the Liquids Pipelines segment, but if you're looking at renewable power assets, let's say, that have less financial accretion but perhaps help the ESG story a bit more, does that help to offset some of the lower returns?
I would say at this point in time, the answer would be no. We think that all the assets that we invest in are sustainable for long term. We look for return of the non capital over the primary terms of the contracts, whether that be crude oil or otherwise. I don't know necessarily that painting a picture of a green portfolio and putting solar panels on our annual report actually does anything to actually move the needle on our social responsibility scores. Obviously, we think they're extremely responsible company across all forms of energy.
And so as we look at investments, it's primarily MAP driven. And to Francois's point, we saw a lot of euphoria in the renewable space. We know how to develop it. We know how to operate it, both wind and solar. But when the cost of capital that folks are willing to buy those assets is lower than our cost of capital, we looked at it as a funding source.
We looked at shareholder value first. Our strategy around ESG will be straightforward, transparent and provide all the information that we need across all of our assets. And I just think investors are smarter than us to try to look at this shiny object over here and don't look at these ones over here. Each asset has to stand alone and has to be sustainable over the long term.
Thanks, Matt. Okay. Thanks, Francois. So we'll turn the podium now over to Don Marchand, our Chief Financial Officer. Don is going to provide you with a finance update to close out the morning.
Good morning.
The coveted last speaker of the morning slots where a few people checking their watches and playing Fortnite in the back of the room and then the guy who sets my compensation, not too upset if I drag it out and have no time for Q and A. So I'm not sure where to go here. Thinking of how to trying to characterize the overall story here and is it stylish or sexy? No, rarely, rarely, if ever. Is it effective and reliable?
Yes, this thing works over time. And that reminds me, it sounds very similar to when I proposed to my wife actually. And she just passed her, you asked me to marry you or are you trying to sell me a set of snow tires? So with that, we'll tie into it. It's been a year of great accomplishment here.
We're in a very good spot. We've got assets sold. We brought significant assets in service. We're on track for credit metrics. We've turned the drip off.
Opportunity set has never been larger or more attractive. And I think we're positioned for a decade of double digit TSR ahead of us if we can execute. We are always climbing the proverbial wall of worry. There is always something on the horizon that's of concern. Just going back 20 years, I remember Y2K, everyone was worried about that about 20 years ago today.
But it's interest rates, it's regulatory actions, commodity prices, can your customers pay you?
How are you going to get all
the money? What are you going to do with all the money? Where is the growth? Is there too much growth? There's always something, but it's a very resilient business model.
And I think we've been quite effective in terms of monitoring and identifying signposts of turns in the market and as well navigating the various events that have happened over time that Russ outlined at the beginning here. So this does work over time. So spend the next 20, 25 minutes walking through how we're positioned, hopefully answering some of your questions on that wall of worry. In terms of housekeeping upfront here, I'll generally refer to Canadian dollars. We're using a $1.33 exchange rate within the presentation.
In terms of depreciation, we generally depreciate things over 40 years, about 2.5% of gross PP and E. If you're modeling income taxes, extract Canadian regulated gas pipeline income, which is flow through equity FUDC as well and apply mid to high teens effective tax rate. In terms of cash taxes, it would be in between rails of about 40% to 60% varying by year. Coastal GasLink, we'll get into a little more detail here, but fully consolidated at this point pending completion of a JV structure here. And I'll walk you through what that looks like on the various charts where it is incorporated into there.
And as for the LP, it's status quo in terms of ownership within the presentation materials. So with that, we've had a fairly straightforward doctrine of philosophy that served us well over the past several years. We'll just touch briefly on the components of that. We do take a long term view grounded in fundamentals. The macro picture right now is very supportive.
We believe we're in the right places. We've demand for our services has never been stronger. We believe our footprint is irreplaceable, and it has an innate ability to replenish itself. In terms of risk preferences, we're not trend chasers. The term it's rarely different this time when it comes to the latest funky financial or commercial structures.
The model is pretty simple, creating long term annuity streams, finance it with long term capital, capture a spread, repeat, repeat, repeat. We see value in building things. We actually have over 1100 engineers on our team, building things at a high single digit EBITDA multiples and having it valued several turns higher, if you can manage the construction risk is a very good value proposition as far as we're concerned. Our model is simple. We prefer to own and operate 100% of our assets.
We believe in financing from the center with a few modest exceptions. We do finance debt financing at the FERC asset level for rate making purposes. We do finance at Bruce given its unique nature, similarly at Coastal Gas Link. And one candidate in the future would potentially be Mexico to have a debt at the asset level. But generally, we prefer to keep it simple and financing from the center.
Thoughtful capital allocation is critical. We look for a balance between reinvestments and a valued payout to our shareholders. Everything is looked at through the lens of per share metrics. And if we can't find something sensible to do with your money, we will accelerate its return either by increasing the payout or shrinking the balance sheet proportionally to maintain our credit metrics. We believe in financial strength and flexibility at all points of the cycle.
We never want to compromise long term prospects due to short term events, and we always want preserve the ability to act when things happen, as was talked about earlier. We want to be the top credit in our sector. The biggest input cost to our business is the cost of money. So it is core to our beliefs. We also believe in candid useful disclosure, giving you relevant information instead of just data.
Looking back at the year behind us, it has been, again, a good year. Robust operating results driven by legacy pipes that are largely full. A strong tailwind from our liquids marketing and market linked business, good cost control and turning on capitalized interest in AFUDC into actual cash earnings. See $10,000,000,000 of assets come into service this year, dollars 8,000,000,000 was complete by the end of September with another $2,000,000,000 here in the 4th quarter. In terms of asset sales, we've announced $6,300,000,000 year to date.
We have closed on Coolidge, Northern Courier and Columbia Midstream for $3,400,000,000 with the Ontario thermal deal, as Francois mentioned, for $2,900,000,000 to close, we expect in the Q1 of 2020. We believe we're on track to achieve High Four's run rate in terms of debt to EBITDA as we exit this year. This is where we want to be, and we think it is appropriate given the strength of the left hand side of our balance sheet. We are also targeting 15% FFO to debt. So those are our 2 key credit metrics going forward.
We were disappointed to lose our A rating at 2 agencies here over the past couple of years. That said, we respect it as they're great in their opinion, and we accept that. Again, we reiterate we intend to be the top credit in our sector going forward. We see real value there for all of our stakeholders and consistent with that philosophy of strength at all points of the cycle. In terms of Coastal GasLink, we believe we're on track to conclude a JV agreement here between now and the end of the year.
We are very pleased with the, as mentioned, the quality and the quantity of interest there, And we would be comfortable with any number of the parties at the table being our partner for the next couple of decades going forward. The DRIP was turned off effective with the last dividend declaration. As we've mentioned previously, it's not a permanent part of our financing. It has been on twice, once from 2007 to 2011, and we turned it on again in 2016 when we acquired Columbia Pipeline Group and just turned it off now. Lastly, on the ESG front, this isn't something new for us.
We've been doing this, in our view, a very long time and doing it well. This has a fancy new moniker. It's just fallen under the realm of risk management as we look back into the rearview mirror here. We believe we have a very solid story to tell. We do have to work with some of the external raters in terms of data gaps, cleaning up data, correcting errors and that, but we are on track to do that.
We have added resources to our IR group this year throughout the company. As was mentioned earlier, we've added sustainability to our HS and E committee. We have a Chief Risk Officer and a Chief Sustainability Officer. We will be guided by TCFD and SASB going forward as we prepare our disclosures. You've seen an ESG profile included in your books today, and we've recently released a data sheet on ESG.
If you have any specific needs, please do not hesitate to contact any of us, and we will get what you need into your hands. So in terms of 2019 funding, it's about $15,200,000,000 that's represented in each of these bars. On the left hand side, we will spend $8,800,000,000 this year. It's actually about $1,000,000 an hour for context on capital programs. Coastal GasLink is about $1,100,000,000 of that, which remains fully consolidated in these numbers.
We will pay about $3,100,000,000 in dividends and distributions, and we have redeemed $3,300,000,000 of debt maturities. On the right hand side, we will report expect record cash flow of about $6,900,000,000 for the year. We have sold $3,400,000,000 of assets, as we mentioned earlier, excluding the interior thermals, which is 2020. We'll see about $925,000,000 of DRIP proceeds over the course of this year. That includes the Q4 'eighteen dividend declaration that was paid in January.
We've seen about 34%, 35% DRIP participation over the course of this year. In terms of capital markets issuance, we issued a $1,100,000,000 hybrid at a rate of $550,000,000 in September in the U. S. Market. That attracts generally about 50 percent equity credit from our agencies.
And on top of that, $2,000,000,000 of senior debt issuance here in Canada, both of them were for the NGTL rate base. Average term of those transactions was 28 years at a rate of 4.12. And to complete that is about $500,000,000 of movements in CP and cash. That has contributed to what has been a pretty exceptional 4 year funding run here of about $72,000,000,000 It's not quite up to what, say, cannabis stocks were valued at a year ago or say, the Leafs payroll, but it's still a big number. On the left hand side, about $34,000,000,000 of CapEx, $15,000,000,000 of acquisitions, which was primarily CPG and CPPL, dollars 12,000,000,000 in maturities and $11,000,000,000 of distributions.
Consistent with our theme of community service, making sure no banker goes without a hot meal or a hot car. We've got $24,000,000,000 of cash flow with $17,000,000,000 of debt issuance, dollars 8,000,000,000 of hybrids and preferreds over that time frame, again with 50 percent equity credit, $12,000,000,000 of equity issuance, 8 of which was discrete issues, 3 on DRIP and 1 on ATM and about $11,000,000,000 from portfolio management. Included in that amount is about $1,000,000,000 of project recoveries that we received on PRGT and CGL in this time frame. In terms of deleveraging and EPS growth, I think I showed you this chart last year. Now I'm pleased to say it's more historical than aspirational here.
On the left hand side is debt to EBITDA, which has gravitated down from the high 6s to the targeted high 4s here from 2016 post CPG to now. So very pleased about that. On the right hand side, EPS moving from $2.78 in 2016 up to, call it, the low 4s this year. And again, a notable increase in quality as we've exited merchant businesses and invested more heavily into regulated contracted assets. String your eyes here in the next couple of slides.
What this is meant to depict is the diversity and quality of our revenue streams well as some of the variability inherent in that. Turning your attention to the outer ring on the circle here. This indicates our EBITDA from our 5 distinct businesses. So again, very diverse. It would also highlight our ability to rotate capital amongst our businesses.
The ability to invest in 3 different businesses in 3 different countries allows us to pursue opportunities as they cycle from one to the other. We're not really beholden and or tempted by having to force capital into one specific business or one geography. And the inner ring here is the commercial breakdown of our EBITDA. About 62% is regulated, 31% is contracted, 6% is associated with volumetric, where we have volumetric risk. This is principally the market linked asset south of Cushing and about 1% is exposed to commodity prices, which is mainly our Alberta cogen plants and gas storage.
Long history of, in our view, adeptly managing commercial and financial risks here. On the right hand side, just walk you through a few of them here. In terms of FX, about 60% of our EBITDA comes in the form of U. S. Dollars, and that includes our Mexican business where our revenue streams are paid in USD.
That's as a natural hedge, we have US25 $1,000,000,000 of debt, including hybrids and the associated interest expense that comes with that. That leaves us long, thumb in the air, approximately US2 $1,000,000,000 each year on an after tax basis. We actively hedge that on a 1 year forward basis. So our sensitivities would be to take about a $0.10 move in the currency to impact EPS by a $0.01 in the prompt year. And then beyond that, it is fairly sensitive where a $0.10 move in the currency would probably have a $0.20 impact in EPS going forward.
In terms of interest rates, our operating cash flow is fairly immune to short termmedium term movements in the general economy or interest rates. Our debt portfolio is predominantly long dated and fixed. Over 90% of our debt is fixed rate. Average term is 22 years. To final call, 14 years to first call of our hybrid portfolio.
We also have regulatory and commercial structures in place where a sizable amount of our interest costs and movements are passed through to our customer base. In terms of counterparty, this was touched on several times earlier today, but being quite topical right now. Our counterparty portfolio is diverse. It is heavily investment grade, and I would highlight again the high asset utilization that we have right now. We recognize the financial strains hitting some of our producer shippers in the WCSB and Appalachia, But it's our expectation that there will be no material loss impact suffered as a result of any counterparty failures given our market position, the fundamentals as well as collateral financial insurances held.
Looking forward now, turning to the capital program. Again, continuing with the strained eyes. We're about just over $30,000,000,000 of secured projects through 2023. Included in here is 3 years of maintenance capital with $5,400,000,000 of maintenance capital over that time frame, 90% of which is recoverable through our regulated businesses. The portfolio here is diverse.
It's mainly small to midsize projects with CGL probably being the outlier there. And it's heavily regulated, contracted, about 61% regulated, 37% contracts, 25 years or longer and 2%, which is really maintenance capital that's nonrecoverable aside from that. And again, a proven ability to replenish this list year after year. So $30,300,000,000 on this table. We've spent about $9,000,000 to date.
So it'll be the $20,000,000 $20,500,000 left to spend, About $17,500,000,000 of that will be in the 'twenty to 'twenty two period, about $4,000,000,000 thereafter. And CGL is still fully 100% consolidated in this number in these numbers right now, pending completion of the JV. What this is meant
to do is
to pick the quality of the commercial underpinning of the program in the prior slide here. Common attributes are length and again quality of the contracts. I think the way we define contracts in term probably differentiates us from many of our peers in our sector. And just walking through this here, about $23,000,000,000 of the $30,000,000,000 is depicted here. What's excluded is maintenance capital and the Modernization II program for $7,000,000,000 from this chart.
And I'd just note that $6,000,000,000 of the $7,000,000,000 that's excluded here is actually rate base investments just without contracts behind it. So moving left to right, NGTL and Mainline is about $10,500,000,000 of investment there. And U. S. PL has about $1,500,000,000 of investment.
All that investment is included in rate basis where we do recover return on and off capital. But in terms of belt and suspenders, we actually do have contractual backing beyond that. In the case of the Canadian Gas business, the average is about 12.5 years. It's about 10 years for receipt capacity and about 16 for delivery capacity. And in the U.
S. Side, it's about 19 years in terms of the contracts backstopping the growth that's on here. Moving further to the right with Coastal GasLink. We have a 25 year contract with a consortium of shippers there. It's extendable at their option.
Depreciation length will match contract lengths. There is no recovered unrecovered capital at the end of that contract. Should they extend it, the depreciation life will shift to reflect that. In terms of the Mexican gas pipelines, this is Tula and Villa de Reyes. Both are under 25 year contracts with CFE, full recovery of capital well within the length of those contracts.
And again, our Mexican business payment streams are in U. S. Dollars. And on the far right hand side is Bruce Unit 6, major component replacement and the asset management program, and that's fully captured within the contract with for Bruce that goes out to 2,064. So again, very long life, very high quality backstopping for the capital program.
Getting a little more granular here. It's about $18,000,000,000 as I mentioned, of CapEx over the next 3 years, dollars 7,200,000,000 next year, dollars 6,200,000,000 in 2021 and dollars 4,600,000,000 in 2022. Dollars 12,200,000,000 of this is growth capital, dollars 5,400,000,000 is maintenance capital. And there's about $400,000,000 in here for capitalized interest and debt AFUDC, and we're using a rate of approximately 5% to record that. In here, Coastal GasLink is represented at a 25% ownership level.
We are also expecting to have project financing in place for that asset by the end of the year, around the end of the year. And what so what's depicted on here is actually a fairly minimal cash contribution to Coastal GasLink over this time frame when you factor those 2 financing mechanisms in there. So again, fairly minimal cash contribution to CGL over the next 3 years. Maintenance capital, as I mentioned, is $5,400,000,000 It's again, to get put it in context, about $200,000 an hour we spend on maintaining our assets. The vast majority of that is passed through.
We have absolutely zero financial incentive to not spend the money and do what we need to do on the maintenance capital front. Maintenance capital remains elevated because of high asset utilization. We've had class changes in some of our assets, particularly in the United States. We've had new regulations come into force, as Stan mentioned, and a condensed time frame to complete maintenance capital as dictated here in Canada. So we expect that number to normalize probably around $1,500,000,000 once we get beyond this horizon.
But again, right now, elevated in about the $1,800,000,000 average range over this time frame. Again, I highlight 90% of this is recoverable. In Canada, it goes immediately into rate base. As Stan mentioned, there is a timing difference potentially in the U. S.
Between rate cases and settlements and in our liquids business, it's immediately passed through to our customers. In terms of funding program for the next 3 years, nothing too sexy or stylish here for the bankers. But on the left hand side, dollars 18,000,000,000 of capital, about $11,000,000,000 of dividends, and that is at an 8% to 10% growth rate through 2021 and then in the 5% to 7% range for 2022 incorporated into that number. Cash from operations, about $21,500,000,000 over that time frame, and we do expect the sale of the Ontario thermals to close in early 2020 for $2,900,000,000 That leaves funding need in the capital markets of about $4,500,000,000 over this time frame. That excludes debt maturities, which I'll touch on in the next slide.
And that is maintaining our credit metrics within the metrics outlined earlier of high forwards debt to EBITDA and in the 15 percent FFO to debt area. We do not see any need for common equity to complete the secured capital program that we have underway right now. In terms of levers available, we look at everything on a per share basis. We generally run our hybrid preferreds to about 15% of capital structure. We're right there right now.
So in the absence of any substantial balance sheet growth, not a lot of hybrid capacity at the moment. In terms of future portfolio management, we don't see LP dropdowns as something financially attractive at this point in time. We do have some residual assets from the $500,000,000 of contracted EBITDA that was mentioned last year as salable assets, but it's a much smaller subset of assets there and nothing that we're actively working right now. One thing we will look at is joint venturing if necessary in the future, but we will weigh that against the tenet of trying to keep things simple, understandable and maintain 100% of everything. So there's a few trade offs in here, but we do have plenty of levers available should more growth show up.
In terms of the debt maturity profile, it is about $5,400,000,000 over the next 3 years. That's on top of the previous slides financing need. It's about $3,500,000,000 That's depicted in the dark blue on here. The currency exchange at 133 is in the light blue. And then we have about $800,000,000 of Canadian maturities in green.
Average term of the debt maturing is 4.2%. So when you take it all together, the $4,500,000,000 of senior debt on the prior slide and the $5,400,000,000 here, We see about $10,000,000,000 of senior debt issuance over this time frame into the markets on Canada, the United States and potentially other markets should conditions or economics warrant. In terms of liquidity, cash flow is robust and growing. We have over $10,000,000,000 of committed bank lines with our core relationship banks. And as I mentioned earlier, we will be putting in place additional committed facilities for CGL through construction to further bolster that.
Full access to capital markets, including well supported CP programs, and we always have shelves in place so that we can expedite asset access if necessary. Turning to comparable EBITDA over the next several years. We expect it to go from it was $5,900,000,000 in 2015, consensus of $9,300,000,000 this year and then growing to $10,000,000,000 plus in 2022, representing about an 8% CAGR over that time frame. Just some observations over that, navigated a few things over this time, including the KXL denial, the commodity price collapse and MLP meltdown, the Columbia integration, acquisition integration, U. S.
Tax reform and the FERC actions in 2018. So a bit of drama in there, but again, a fairly healthy growth rate over that time frame. I'd also highlight the quality of the EBITDA has grown as we have exited merchant businesses and added in particular the Columbia platform and all the regulation and contracts that comes with that. We expect to again debt credit metrics to be achieved and the DRIP is turned off over this time frame. And I just note that about 70% to 75% of our EBITDA does convert to cash, and we expect that to continue going forward over this time frame.
There are a number of normalizing items I just want to point out for you on here. In the 2019 number, there are some there is EBITDA from assets that have been sold. It's about $250,000,000 related to the assets that were included in the $6,300,000,000 of asset sales that will disappear from here. Bruce is a sizable nonlinear asset. We do see Unit 6 coming off in early 2020, and you can see on the far right hand side back on in 2023.
So if you're looking at a point in time on 2022, that should be factored into your thinking. Current strength in the liquids business is expected to normalize. So we're not expecting the current stellar level of results to being to achieve the 8% growth rate out to 2022. And I just highlight that 95 plus percent of the EBITDA in 2022 is contracted or regulated. One last one is Canadian regulated EBITDA, and this is a bit of a Kumon moment here.
It is Canadian regulated gas pipes is a flow through business. So one thing I would highlight here is we have seen new regulation, new tax rules come down in Canada where we have accelerated tax on that on that business that is passed through to our customers. So if you're simply taking a multiple of EBITDA, we've actually we'll actually probably see EBITDA decline by $100,000,000 because we pay less tax, which we passed on to our customers, no impact on net income. But it's difficult to argue that the value of the enterprise has dropped $1,000,000,000 because of that if you are just simply applying an EBITDA multiple to the business. So Canadian regulated pipes are an anomaly if you are strictly looking at EBITDA numbers.
On the far right hand side here post 2020 2, in 2023, we see about $10,000,000,000 of assets coming into service. That includes Coastal GasLink, the NGTL 2023 expansion and Bruce Unit 6 coming back. So this slide is we've taken it out to 2,030. We've shown this for the past couple of years, but it's meant to show just the stability and longevity of the revenue streams coming off our base businesses here. So what's reflected in here aside from the purple arrow swooping upward is if we spend $30,000,000,000 if we complete our $30,000,000,000 secured capital program, spend maintenance capital over this time frame, normalized recontracting of our U.
S. Business, particularly and a modest contribution from volumetric and market exposed businesses. We have about a $10,000,000,000 EBITDA base that goes out a decade with a pretty high degree of visibility. So when you take all of our assets together, this portrays, we describe as a pseudo utility revenue stream. Reflected in there is everything spent in Canada goes right into rate base.
Our Coastal GasLink, our 25 year contracts, as noted previously, everything in Mexico was under a 25 or higher year contract base. This reflects our liquids business, the contracts that are in place right now. So this is a pretty nice base to start from as we're looking to grow the company going forward and looking at dividend policy. Any surplus capacity would be represented in the in that purple arrow upward. Again, the 5 core businesses, strong fundamentals and a new replaceable set of corridors gives us comfort that we can certainly grow this business going forward off this base.
Just want to touch on Bruce for a second here. It is truly a unique asset and investment opportunity. Bruce Unit 6 is reflected in the $10,000,000,000 but nothing beyond that. But there is a decade plus investment opportunity here. This is a missionless, economic, well supported in its jurisdiction power that represents in the 30%, 30%, low 30% of Ontario's power needs here, contract out to 2,064 and returns that are probably at the upper end of our return spectrum of our portfolio.
So Bruce, should it go ahead as we work through these various quite accretive as you get towards the end of this time frame and well into the next decade. So it's something to bear in mind here as we look at potentially a $10,000,000,000 investment over in real dollars, Bruce, over the coming years. In terms of dividend policy, the only negative on this slide is it's bearing in an unusually high correlation to my body mass index over this time frame. So 2 or 3 more years of this, we'll have to reinforce the stage when I come up here. Principles on our dividend, again, we're always seeking balance that balance between what's valued by shareholders, what's sustainable versus what's left for reinvestment in a fairly attractive suite of opportunities.
Earnings matter. We're old school on this one, but it still does factor into our decisions. And a little change to our historical payout ratios, strong coverages and everything on here is backed by growth in earnings and cash flow. By our standards, hyper growth, 8% to 10 percent through 2015. That's really driven by the shale build out and the acquisition of CPG.
We do reaffirm the 8% to 10% growth rate through 2021 that we've previously mentioned in the past several years here. And again, no fundamental change to payouts. Post-twenty 21, we see organic growth in the 5% to 7 further in corridor expansions that has been outlined Further in corridor expansions that has been outlined over the course of the morning here, it's a pretty vast opportunity set. We get about 3 to 4 years visibility on that. So by the time you permit, spend the money, get stuff in service, That's generally the time frame that we do have where we put something on the secured project list.
And then we do have $20,000,000,000 of projects in development right now, including KXL, an entourage of Alberta Liquids projects, the various Bruce restarts and beyond Unit 6 and the Merrick pipeline. Where we end up in this range will depend on the mix of projects, where they are in the spectrum of return where Canadian regulated pipes are probably at the lower end, Bruce and the Mexican pipes probably at the higher end, the cadence in which they come in and how we execute them. So but again, we see 5% to 7% organically over this time frame. Inorganic is not included in here. There's been a fair bit of discussion today about M and A.
We never budget for it, but it's why we keep our financial house in order so we can act on opportunities as they arise. And somewhere over this time frame, if something does appear that allows us to bolster this rate, we will pursue that. So to wrap up here. The model, simple, understandable, proven. Dollars 10,000,000,000 of EBITDA with high visibility through the end of the decade.
That's a pretty nice base to build off of. Financial House is an order from a credit metric standpoint. The macro environment, we view as highly constructive. Demand for services has never been stronger. We are seeking and achieving multi decade contracts where we do want to expand our assets.
It is tough to build things out there, but that is our competitive advantage with these corridors. We do believe we can capture disproportionate share of growth given our footprint. And if we stick to our risk preferences, we should be able to achieve returns appropriate for the risk that we're taking on here. And we will be cautious in developing new projects and how we parcel out risk and how much money we spend upfront on that. So again, to finish off here, we believe we're poised for another decade of double digit TSR if we can execute on a proven business model here.
So with that, happy to take your questions.
Durgesh Chopra with Evercore ISI. Just can you touch on 2021 versus last year Investor Day? I know there have been puts and takes. So we've got the asset divestitures, we've got the 501 gs settlements and the backlog has changed. So where is that roughly the $10,000,000,000 EBITDA for our models?
Where does that sit, directionally speaking, in your internal projections?
To reconcile the trend from last year to where we are today, you would have to take off the asset sales. Some normalization of the Canadian regulated EBITDA. I think Bruce even 6 was in last year. And then liquid strength that we're seeing in terms of market like in TCLM. So there's thumb in the air, probably a good $500,000,000 that from last year to 2021 to where we are today.
I think as Don has highlighted, the key difference would be the execution of the $6,000,000,000 of asset sales this year, but obviously wouldn't have been included in the model last
year. Thanks, Selim. Just in terms of just one quick follow-up. Sorry,
go ahead.
In terms of forward looking growth, the 5% to 7% EBITDA growth, am I right in thinking about since this growth is coming from predominantly the regulated part of your businesses that the earnings growth, the net income growth is, directionally speaking, lower than the EBITDA growth?
Yes. The 5% to 7% is a dividend growth rate. So it would be backed up by earnings and cash flow. And where we fall out in that range, as I mentioned, it depends on the mix of the projects and the cadence. So right now, we have a pretty heavy weighting to NGTL, which is probably at the lower end of the spectrum.
But over time, that shifts around and then how we execute on these projects. So the 5% to 7% range, it will be somewhere in there, but it will depend on mix, cadence and execution.
But let's say through 2022, just the EBITDA growth number, the 8% guidance. Is the earnings growth actually in line with EBITDA growth? Or should we be modeling earnings growth which is below?
Yes. We don't give earnings specific earnings guidance. Where you guys add all the magic. But yes, you can generally look at earnings and cash flow and dividend growth as moving largely in tandem. In any specific year, it can bounce around.
But over time, there is a very, very high correlation to the 3 of them.
Sure. Andrew? Andrew Kuske, Credit Suisse. Just given the duration of contracts you have across the whole portfolio, should you have more leverage in the system?
Well, we're comfortable with our leverage and we do look to the credit rating agencies as to where they see comfort as well. So we do value their input on this. So you can argue on a specific asset. Could you lever them up higher? Yes, potentially, but you end up with structural subordination on that.
So no, I would say we're generally comfortable with the capital structure of the $100,000,000,000 asset base taken as a whole. You could again, you could drill down into specific assets. Could you leave them in eightytwenty? Probably could on this. But we were cognizant of simplicity and we're cognizant of what the agencies want to see in terms of metrics.
We take the long view on this one.
So more limited opportunities to do things like Northern Courier and then CGL?
Yes. We'll be cautious. The trade off there is adding structural subordination and complexity. So and where our principle of keeping it simple is, yes, at some point, you trip the wire and the credit rating comes under pressure, but that's not where we want to be. We don't want to test that.
Thanks. Robert?
Don, just when you look at your capital plan, you're pretty much fully funded, but there's not really wiggle room. So as you see additional projects, especially some of the larger ones, you've mentioned some of the levers you have to pull. But as you look at it right now, where do you see the most attractive levers, whether it's asset monetization, JVs or hybrids?
Yes. I'll approach that in 2 ways. Well, firstly, large project any new projects that come into the fold here, with the exception of, say, a KXL, it's a fairly long tail from when you land the project to when you get a permit and actually start spending money. So in terms of landing new stuff right now, we wouldn't see any material spend probably until the 'twenty two, 'twenty three time frame by the time you get through all the regulatory hoops and permitting. If a KXL, for example, went ahead here, it would really depend on what's the CapEx, what's the spend and what's the spend profile look like.
Yes, we would look at everything on a per share basis. If it's a large project, it would come with some hybrid capacity. If it's particularly a new build, it probably wouldn't have any senior debt capacity through construction, but we would add hybrid capacity over time. And then you're into do you issue equity if it's a big enough investment or sell assets, looking at things like financing overhang versus accretion and the like. We will always look to our portfolio first, given the amount of 3rd party money out there chasing hard assets right now.
It's been a pretty rewarding process for us to sell assets. We're into the really good stuff now. So we hate to part with anything in our portfolio. But given the valuations out there, unless it's something very, very large scale, portfolio management asset sales is probably the first place we would look.
On KXL, is it still an all of the above strategy?
Still is. It's still an option out there. Let's see what it looks like. Let's see what our comfort level is. Do we bring in partners?
Do we what's the time frame? What is the actual cost figure? But yes, I don't think we would rule anything out at this point, but it's quite preliminary. We need to get our permits all in line and then see how we feel, whether the risk reward is truly compelling enough to proceed.
I'll just put one in. Can I get your take on some of the distress we're seeing in U? S. Midstream share prices? Do you see that as an opportunity?
Or is that a case of cheap stocks or cheap for a reason?
We always have our wish list, but I wouldn't say there's enough in the job jar right now. There's nothing that's distracting us at this stage. Corporates versus asset acquisitions are a little more involved. But if there's 1 crown jewel in there, do you take on something even bigger to get that crown jewel? Bottom line, I think as Russ, we talked about, you guys talked about earlier, there's nothing really on the radar screen right now
that It wasn't me, sorry. Sorry, go ahead, Ben.
It's Ben, BMO. Don, I just wonder if you can quantify where your payout ratio goes next couple of years through 2021, whether it's EPS or you care about distributable cash flow now?
Yes. So we've historically, we've been into 80% to 90% comparable earnings, 40% cash flow payout range. It's where we've largely run the last couple of decades. We don't see veering away from that. Can it creep below or above that for some short period of time?
It can. Like right now, we're probably in the mid-70s on an EPS basis. It's not a huge wildcard, but in terms of cash taxes, that's something we're watching here where there are draft U. S. Tax regulations that are yet to be finalized that could impact cash taxes to some extent.
But right now, we don't see any significant bearing away from what's worked over the past 20 years. And then I ask on the durability of the cash flows at Slide $10,000,000,000 through 2030,
looks rock solid. Is there
an element of First Nation decent expiration that could become a wall board for you in that 10 year view?
Sorry, 1st Nation involvement in that 10,000,000,000
Eastman expirations or state easement expirations that maybe becomes a wall bore in 8, 9, 10 years for you guys?
I don't have the granularity on that one, but I'm not aware of anything material that could come out in that time frame.
That's there's we have some of those kinds of arrangements. They're not material, and there's not material expiring in those time frames. We have, as I mentioned earlier, pretty solid relationships with the indigenous communities that we that are partners today. And as those arise, I would them to be renewed in normal course, but they're pretty small.
Chairman Tannen, JPMorgan. Just wanted to come back to the 5% to 7% dividend growth looking further out here. Is there a target level of CapEx that gets you to that end? Or how do you think about, I guess, how those 2 interrelate there? And then just curious with the payout ratio, you've been at 80% to 90% for some time now.
That's been historical practice. If you were of the belief that a lower payout ratio may valuation because it seems like most of the business screens more similar than the valuation because it seems like most of the business screens more similar than not to kind of utility risk profile. Would you pursue that? Or any thoughts around, I guess, those topics?
Yes. In terms of the payout ratio, yes, we debate this at length in terms of where's the right place to be. We're nervous to mess with success on that one, especially in a low interest rate environment right now when you're you've got a you can debate the 4.5% area yield that we have right now with a 180, 10 year treasury. But we think there's compelling value over time for our shareholder base. And we're not getting a lot of inbounds from the shareholder base saying that you should go and cut the dividend or reduce the growth rate substantially and we'll pay you more money for your shares.
But it's something to bear in mind, but at the same time, this seems to be the right balance right now. It's important that we turned off the direct and the increase in the common shares outstanding. That's step one here. And then but this trajectory has worked over time, and there's nothing that we see structurally that says we should move off of that.
And as far as
the 5% to 7% growth rate, is there a certain amount of capital per year that we keep?
Yes. So right now, our capacity is probably in the $4,500,000,000 to $5,000,000,000 a year range of capital that's available for us. That compounds over time with the extent we retain it. And then where we fall into that is how we spend it. If it's 6% to 7% return Canadian reg stuff versus high single digits or higher, bolt ons in the U.
S. Or MEXCORBERS will inform us where we fall in that range, hence the 5% to 7% range. So over any specific 1 or 2 year period, it's hard to move it around. But over a long period of time, longer period of time, we can move upward in that range if it gets redirected to things like Bruce, like Mexico, like bolt on USPL Investments.
And then maybe just a quick housekeeping item. You noted the FX sensitivity there before. I was just wondering, is there any thoughts to kind of switching the functional currency if that comes into play? Or it seems like you've thought about that in the past and maybe decided that wasn't the route that you wanted to go?
It'd be great comp wise, but other than that, the we've looked at it recently. There are strict GAAP criteria as to when you would shift your functional currency, but we're not near the threshold right now. So right now, Canadian dollar remains the functional currency. And we with our current suite of projects in that, we don't see that changing unless there was a material increase in U. S.
Dollar investment through M and A or just a 10 year string of really heavily concentrated U. S. Dollar versus Canadian dollar investment?
Sorry, go ahead, Rob.
Yes. Rob Hope, Scotiabank.
Just a
clarification. So you're talking about $10,000,000,000 of EBITDA in 2021 with I think you said $400,000,000 or $500,000,000 of headwinds, Does that mean that you're going to see a strong growth in 2022? And I'm just wondering, is that in part driven by some of
the rate cases that you're
seeing in the U. S. Pipelines there?
Yes. In terms of the specific year, I wouldn't say so. We do have significant assets coming on stream next year as well. So that's really the driver there. So is it a spike in a flat line?
I can't really give you that trajectory. It's more linear, I would say.
Okay. I think just in the interest of time, thanks Don, very much again appreciate folks taking the time this morning. I think Russ just going to wind up with a couple of brief closing comments and then lunch will be served.
So we have done our congratulations to Dave and his team. Obviously, we're as I got out of my clock, it's exactly 12 So great job on keeping us all fed and on time and comfortable over the last few hours. Just a couple of quick closing remarks. Again, thank you all for joining us today. Hope the last few hours has given you some insight into our long term strategy, the significant advances we've made over the last 20 years and the promising outlook that we see for our future.
You've seen the theme many times and reiterated by all of us this morning. Simply put, we believe the long term fundamentals will continue to create tremendous opportunities to connect growing natural gas and crude oil supplies to markets and opportunities to replace aging infrastructure as North America shifts to a less carbon intensive energy mix will create significant opportunities for us. As outlined earlier today, we are a leading North American Energy Infrastructure Company, and we have a proven business model that delivers results. The demand for our services, again, as you've heard many times this morning, has never been greater. And as a result, comparable earnings per share and comparable funds generated from operations are expected to reach record levels again here in 2019.
Looking forward, our 5 operating platforms in 3 core geographies provide us with substantial multiple platforms for continued growth. Today, as you heard, in granular form, we are advancing $30,000,000,000 of commercially secured projects with another $20,000,000,000 of projects under development. Those as well as other growth opportunities that will emanate from our extensive North American footprint are expected to drive future growth in earnings and cash flow per share. That in turn is expected to support an annual dividend growth rate of 8% to 10% through 2021 and a 5% to 7% growth thereafter consistent with our the past 2 decades of performance. At the same time, we expect to live within our means and maintain strong credit metrics to ensure that we have financial strength and flexibility to act at all points in the cycle.
This will allow us to capture transformational opportunities that could supplement our organic growth rates as we move forward similar to what we've done in the past. So in summary, we believe that we offer a compelling investment proposition given the quality and stability of the underlying businesses, our tangible outlook for growth and our financial strength and flexibility. So again, thank you all for joining us today. And as you know, we've got an opportunity to meet with some of the other senior vice presidents and the rest of the management team here over lunch. So if you have the opportunity, you're more than welcome to join us.
But again, thank you for taking as much time as you have out of your schedule, both last night and today to join us and for your continued support of our company. Thanks again.