Good morning again, and welcome to TC Energy's 2019 Investor Day. I'm David Moneta, Vice President of Investor Relations, and 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 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.
He'll be followed by Tracy Robinson, Stan Chapman, François Poirier, and Paul Miller. They'll provide you with an update on our natural gas pipelines, liquids pipelines, and power and storage businesses. 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 one with a follow-up, if you don't mind.
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. Finally, just a couple of quick comments on non-GAAP measures. We will reference comparable earnings before interest taxes, 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. 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. A year's already passed. I can tell you that it's been a very busy 12 months at TC Energy. Looking back over the year, 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. 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 four 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 tenets or what we call our beliefs that have guided our business for the past two 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 moving forward. Today, we are advancing CAD 30 billion of commercially secured projects that are largely in corridor, and they're expansions of existing assets, and we have another CAD 20 billion 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. 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 approach 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 each of these themes, starting with our approach to capital allocation. This slide illustrates our business model. It's straightforward. You've heard me talk about it many times. Actually, I believe when I was 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 has served us well, generating double-digit annual shareholder returns since 2000. In fact, over the past 19 years, we've invested about CAD 100 billion in pipeline and power assets. Through that investments, we've transformed our company from what was a Canadian-regulated natural gas pipeline company into a leading North American energy 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 2004, ANR in 2007, various parts of the Keystone system in 2008 and 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 five 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. The 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 CAD 1 per share in 2000 to more than CAD 4 per share today. While cash flow has increased from about CAD 2.50 per share in 2000 to approximately CAD 7.75 today. That equates to an average annual growth rate of approximately 7% and 6%, respectively, since the year 2000.
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.
We have largely insulated ourselves from, as I said, both commodity and volumetric risk, but as well, interest rate risk, allowing us to 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 CAD 0.80 per share in 2000 to the current level of CAD 3 per share. That represents a compound average growth rate of about 7% and equates to a payment of approximately CAD 20 billion 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% of earnings, and approximately 40% of internally generated cash flow, leaving us with substantial financial flexibility to continue to 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 approximately CAD 10 per share in 2000 to approximately CAD 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 1,100%. In comparison, TSX and S&P 500 generated returns of just over 200%. We would say that would be a very good outcome from our perspective, particularly when you consider the low-risk nature of our business.
Today, we are an enterprise that's valued at about CAD 115 billion, and we own or have interest in about 91,000 km or 56,000 mi of natural gas pipelines that move about 25% of all the gas demand in North America from the continent's two largest, most cost-competitive natural gas production basins to the premium markets, both here and now growing internationally. We're also North America's largest provider of natural gas storage, with 653 Bcf of storage capacity. In the liquids business, we deliver approximately 555,000 barrels a day or 20% of Western Canadian crude oil exports to key refining markets in the U.S. Midwest and the Gulf Coast. In power and storage, we have interests in our own 10 power plants capable of producing about 6,000 MW of electricity, which is enough to power about 6 million homes. Over half of that electricity is comprised of emission-less nuclear energy.
Our strong financial performance continued into 2019 for the first nine months, ended September 30th. Comparable earnings were CAD 3.11, or up 10% over last year. Comparable funds generated from operations of about CAD 5.3 billion, 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% to CAD 3 per share on an annualized basis.
In addition to delivering record results, we also made significant progress on many other fronts throughout the year. We continued to advance a CAD 30 billion portfolio of commercially secured projects. Our portfolio now includes CAD 3 billion of new projects that have been added to our backlog since the beginning of 2019. We also placed CAD 8 billion of new assets into service, including Columbia's Mountaineer project, Columbia's Gulf XPress project, as well as the Sur de Texas project in Mexico.
By the end of this year, we'll complete another CAD 2.5 billion of NGTL projects, bringing the total new projects entering service in 2019 to about CAD 10 billion. We also advanced CAD 20 billion of projects under development, including Keystone XL and the Bruce Power Life-Extension Program. Turning to our funding program, we took significant steps to finance our capital program to strengthen our balance sheet by monetizing about CAD 6.3 billion 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 fourth quarter 2019 dividend.
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 for continued success. Looking forward, our focus isn't going to change. We remain focused on six key priorities, and again, these are the same priorities that have guided us for the past two decades. The first is to ensure that our assets continue to operate safely and reliably every day. Second, we continually seek to improve the profitability of our existing assets by maximizing revenues and reducing our costs in each of our businesses. Third, we'll focus on executing our CAD 30 billion capital program on time, on budget, and on quality. Fourth, we'll continue to advance the more than CAD 20 billion of projects that we have under development in a careful, cost-effective manner.
Fifth, we will continue to cultivate a portfolio of new, low-risk, organic growth opportunities in our existing businesses and in our existing geographies. Finally, we'll continue to allocate our internally generate cash flow in a manner that allows us to maintain a strong balance sheet, fund our growth, and support a sustainable and growing dividend. While obviously, we're proud of the success that 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 a 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. I'm extremely proud of our organization and how it reacted to that incident and other incidents that we've had. However, for us, no safety incident is acceptable, and we're not going to be satisfied until we achieve our goal of zero 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 landowners with fairness and respect, enabling us to create long-term relationships.
When we get on their 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. 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 with 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 CAD 1 billion 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, 365 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 business 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. 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. 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 2040 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 2018 and 2019 than it has over the last 10 years. As you know, the IEA is considered one of the most respected and comprehensive, credible agencies that do this kind of work, and it's one of the many sources that we use in our planning processes. As you can see again on this chart, renewables such as solar and wind power are expected to continue to grow significantly. However, in the 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 that 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. Given the abundant supply of competitively priced natural gas, it's likely that natural gas-fired generation will also play a key role in meeting that demand. The bottom line for all of our businesses is that 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 billions of dollars of investment in energy infrastructure. Looking forward, our growth plans are aligned with that long-term energy supply and demand fundamentals. We are confident that we're well-positioned to continue to capture a 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 km, or 15,000 mi, 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 km, or 9,000 mi, pipeline that provides a critical link between the prolific Western Sedimentary Basin and key markets in Eastern Canada, the Midwestern, and Northeastern U.S. Columbia Gas is an 1,100 mi pipeline that's a 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.S. systems averaged about 25 Bcf a day last year, with a peak record day of 33 Bcf a day last January. 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 Marketlink, we 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. Keystone XL is the most efficient and environmentally sound way to move that production to markets. Finally, in our power and storage business, Bruce Power is one of the world's largest nuclear facilities, generating 6,400 MW 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 the potential for gas-fired additions in our core markets, we are well-positioned to capture additional contracted power opportunities along our pipeline footprint. 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. That is our competitive advantage. It's an enviable position to have in a world where demand continues to grow. It is extremely difficult to site new greenfield infrastructure. Today, these platforms provide us with line of sight to over CAD 50 billion of organic growth opportunities. They include CAD 30 billion 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 CAD 23 billion of natural gas pipeline expansions in Canada, the United States, and Mexico, CAD 2 billion associated with ongoing work under the Bruce Power Life-Extension Agreement in Ontario, and approximately CAD 5 billion in 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 achieve 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 CAD 20 billion of development projects, including Keystone XL and the balance of the Bruce Power Life-Extension program.
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 the 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%-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 five 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. 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, François, Paul, and Don are all here to provide you an update on their respective areas of responsibility. As well with us, and some of them you met last night, Patrick, Leslie, and several of our Senior Vice Presidents. 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 that you can connect with them. They are 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.
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 two decades. In each of our businesses, our Presidents are here to provide you an update and more granularity on just exactly how they're going to go about doing that. We'll start with Tracy, Stan, and François. They'll provide you an update on our North American gas pipeline business. As they make their way to the stage, 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.
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, and it was great to have a chance to chat with some of you about our business last night. Now, before I get into the Canada Gas, I'll make just a few remarks on our overall gas infrastructure. TC Energy's natural gas pipeline infrastructure includes more than 92,000 km of pipe that stretch across Canada, the United States, and increasingly includes a meaningful presence in Mexico. It is anchored in our position on two of the most prolific basins in North America, the WCSB and the Appalachian. This infrastructure, combined with our 653 billion cu ft of storage capacity, allows us to connect that cost-effective gas from 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.
We leverage this network to move 25% of the gas that North America relies on every day. We're well-positioned to do this. This is a supply picture of the natural gas basins across North America. On this map, the smaller circles represent the resource estimates of each of these basins in 2007, and the larger ones, the resource estimates of those same basins in 2019. You'll note the tremendous increase in supply in all basins. 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 two basins in which TC Energy's assets are positioned, the WCSB and 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. 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. 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 and electric generation. The growth to feed the LNG exports will be stronger, about 11% CAGR or by 2035, 21 Bcf a year. In this year, 2019, North America fulfilled 10% of the world's demand for LNG. We project that by 2035, this continent is expected to become the world's largest LNG supplier, providing 26% of global LNG.
As you will hear today, our company is positioned well to aid in this transition. If we look a little bit closer at Canada Gas, our Canadian system focused on moving that low-cost WCSB gas to key continental demand centers. The NGTL system attracts about three-quarters of the 16 Bcf that the WCSB produces every day, it offers multiple benefits. You can trade that great trading hub at NIT. You can access the intra-Alberta markets or access markets across North America through our downstream pipeline network. Of the about 12 Bcf of gas moving into the NGTL system every day, about 40% of it is consumed within Alberta. This is for power demands, petrochemical production, and demand in the oil sands. This local market's really important for the WCSB, it's growing.
In fact, last February, we hit record intra-Alberta flows of about seven and a half Bcf a day. 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 to the West Coast of the U.S., and the rest of it, 35%, goes down the Mainline and other downstream pipes to markets in the East, Northeast, and the mid-continent. 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. We're working with other LNG proponents in Eastern Canada and on the West Coast to increase access to markets outside North America. 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. We've been successful. Since 2010, our investment base in Canada Gas has grown by almost 40%. 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.
The Canadian Mainline is one of the largest pipelines in North America, had seen flows diminish as Eastern markets turned to supply in the Appalachian, 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, 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. On NGTL, for example, the competition for access to the scarce egress has driven terms on our new export capacity to more than 24 years. On the Mainline, our newer longer-term contracts average in the 20-22-year range.
This is good for the basin and for security of access to the market. By 2023, we'll have an incremental 5.6 Bcf of new market access in place to the WCSB and a total investment base that will reach CAD 23.4 billion, 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. Despite all of the challenges, we have a track record of getting permits approved and projects built. We're continuing to build on this momentum. Last year's Investor Day, we said we're going to do three things. Firstly, we said we'd execute our capital program safely, on time and on budget.
We are executing now a CAD 17 billion capital program that will add 5.6 Bcf of egress from the WCSB to markets in North America and Asia. So far, by the end of Q3 this year, we've spent CAD 2.5 billion to achieve these capacity expansions. This is a significant build for our Canadian system. 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.
We continue to work to find ways to open up short-term capacity on our system without additional capital. This year, our team released 1.6 billion cu ft a day of short-term capacity across the network. They did this through 16 quick turnaround capacity projects and by actioning a number of smaller operational improvements and optimizing some of our demand parameters. We need to continue to push these boundaries. Thirdly, we said we'd facilitate growth in the WCSB access to market, our efforts on this continue. We recently announced a CAD 1.2 billion West Path expansion, which is a coordinated effort between our Canadian and U.S. gas teams, involves the expansion of the NGTL system and the Foothills system, in conjunction with what Stan will tell you is the GTN expansion.
This is underpinned by 258 million cu ft a day of new firm service contracts with terms that exceed 30 years and will 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 the 85 million Riverbend expansion, which will connect 308 million cu ft a day of supply to a new petrochemical facility in Alberta. Looking further east, this year we signed 167 TJs in long-term contracts on our Parkway expansion. This is now a picture of the expansion program that we have underway.
NGTL's CAD 10 billion capital growth program extends beyond 2022 and will add 3.5 Bcf a day of delivery capacity, 1.5 Bcf a day into the intra-Alberta market, and two Bcf a day of egress out of Alberta, 700 million 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 one, 2.1 billion cubic feet a day of international market. In the Eastern Triangle, we are investing CAD 400 million to facilitate the flow through that area and down into our U.S. pipes in the Northeast U.S.
To do this safely and effectively, we maintain our assets in good operating condition, and over the last three years, we put CAD 1.9 billion in maintenance. Sorry, over the next three years, we'll put CAD 1.9 billion or so in maintenance capital into this system. That's about CAD 600 million a year, and that CAD 600 million is a good run rate based on expected volumes. We do adjust maintenance capital over time to reflect the demands on our system and by our regulators. 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. 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. As the basin's need for our market grows, we are working to provide egress to a variety of markets, our expansion program will achieve this. Our 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 respond to our regulators' requests on tolling for our North Montney Mainline. The NGTL System is underpinned by strong fundamentals and experiences high demand for capacity. Contracts on our system continue to be highly utilized. These contracts are held by a group of predominantly strong, credit-worthy 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 credit-worthy 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 first 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 2.1 billion cu ft a day of gas to Kitimat. This is phase one capacity, and it'll be built at an estimated cost of CAD 6.6 billion. Phase two, should LNG Canada elect to proceed, will move 4.3 billion cu ft a day of gas through a fully compressed pipe capable of about 5 billion cubic feet a day. Now, we've made significant progress this year. We're well into pre-construction, clearing roads, workforce accommodations, grading. We remain on track to meet our committed in-service date.
Make no mistake, this is a very technically challenging and environmentally sensitive project, traversing some difficult and 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 CAD 6.6 billion capital estimate represents an increase of CAD 400 million. 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. 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 through pipeline tools subject to certain conditions. We are working with our partners on this now. The Coastal GasLink project is special in a number of other ways. It's a strong environmental story. The gas that moves through this pipeline and LNG Canada's facility will increase emissions in Canada by about 3 million tons-4 million tons a year. It'll also reduce annual emissions in Asia by 60 million tons-90 million tons a year by offsetting coal. This reduction equates to more than the total annual emissions in British Columbia and about 10% of our Canadian annual emissions. It's a very positive story. The project is also setting a new standard for how our company works with our indigenous partners.
We're engaging meaningfully, and we have an unprecedented level of support. As you know, 100% of our elected leaders along the route have entered into agreements with our project. Indigenous groups are also participating in other 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 CAD 1 billion into local and indigenous businesses and create 2,500 high-quality construction jobs. So far, we've awarded CAD 720 million to indigenous and local businesses, and indigenous staff have done more than one-third of the pre-construction 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. Shifting from the West Coast to the Canadian Mainline, this is an asset that's very much in demand.
It's an important conduit to markets in the Prairies and in Eastern Canada, and through our U.S. downstream pipes to the Mid-Continent, Dawn, and Northeast U.S. markets. We've now essentially sold out most of the available capacity on the Canadian Mainline. The Canadian Mainline has contracted up for 2021 to reflect the additional flow that will result when our expansion program on NGTL delivers 1.3 Bcf a day of incremental volume to the Canadian Mainline. On the eastern side, the Eastern Triangle is fully contracted. We're spending CAD 400 million in capital to expand this part of the Canadian Mainline, including expansions at Station 130, East Hereford, TQM, and that'll 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 markets. We're in discussions now with our customers on how to advance this value as part of our post-2020 framework. We're making good progress on these discussions. The details will be made available as we come to agreement. I will tell you this, that we are aligned around the table in the importance of the Mainline connecting the basin's gas to the markets in the East. 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 on solidifying their needs for growth in local gas consumption.
We're looking to leverage the benefits and the capacity of the Canadian 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. We'll continue to work with the many efforts underway in industry in both Eastern Canada and the West Coast to increase access for the WCSB volumes into international markets through the development of new LNG capacity. 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. 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 and investment base of about 9% between 2015 and 2022 to more than CAD 21 billion. Net income will grow by that same pace from about CAD 500 million in 2015 to more than CAD 850 million by 2022. It's also important to note that from a cash perspective, we're pulling more than CAD 1 billion a year of depreciation out of our Canadian system. Looking forward, our priorities are clear. We will execute our CAD 17 billion 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 amounts in 2019 and is already working on opportunities ahead of us in 2020 and beyond. They've done a great job in leveraging 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. With that, I'm going to turn the podium over to Stan Chapman in our U.S. business.
Hey, good morning, everybody, I appreciate the opportunity to share with you some of the ongoings in our U.S. natural gas business. Before I do, there are three things 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. Third, while building new infrastructure is more and more difficult, we remain well-positioned for additional growth that I would describe as bite-sized opportunities that are permittable, that are constructable, and are largely made up of in-corridor compression-type expansions.
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. We have an ownership in 13 different pipelines that span 31,000 mi across 40 states of the United States. We operate 535 Bcf of regulated storage capacity, making us the largest such provider, and we move about one in four 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 WCSB 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 U.S., most predominantly in the form of LNG exports, where we currently connect to five terminals and have plans to expand to three 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 is 3,400 trillion cubic feet of proved probable reserves in the U.S., which was 20% higher than the 2017 report and the largest amount ever reported. On top of that, another 400 trillion cubic feet of proved reserves and another 1,000 trillion cubic feet of potential reserves in Canada.
Says that our continent is sitting on 4,800 trillion cubic feet of reserves. Put that in perspective for you, that is somewhere around 150 years' worth of supply at current production rates. Know that this production, this 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 1,300 Tcf can be produced at prices less than $4. With respect to 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, it 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 forecasts for production in 2020, production is likely to grow somewhere between 0 and 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 Algonquin are somewhere around $1.40, $1.50, and gas prices in the Permian around $0.90 or so.
On the demand side, the demand continues to grow across the U.S., as shown in the 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 2040. Renewables grow even faster than natural gas, the important takeaway is that by 2040, 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-6 Bcf, likely to double again by 2023 from 6 Bcf-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 U.S., 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, 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 CAD 4.5 billion worth of capital, which largely concluded the historical backlog of Columbia projects. In the aggregate, we placed in almost CAD 8 billion of capital and service, which is now generating about CAD 1 billion or more of EBITDA per year.
We closed out year two of our Modernization II program successfully on time and on budget. 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 1.1 million 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 1.6 million hours. 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 our 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 CAD 1.3 billion in new projects, which I'll talk about in a 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 sendout 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 sendouts 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 seven to eight to nine 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 the transportation capacity that they hold. Overall, against our top 10 producers, we hold collateral that's equal to about one year's worth of coverage, primarily in the form of a letter of credit. 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 CAD 8 billion worth of projects on the Columbia backlog, which generated about CAD 1 billion worth of EBITDA for us. We're now executing on about CAD 2.1 billion worth of new growth projects. Some of these are still subject to FID and customer counterparts, in the aggregate, you could think of us as having a build multiple on this CAD 2 billion of projects that we're executing on, somewhere around the 6x EBITDA to CapEx going forward. Very attractive build multiples. Modernization II, 2020 will be the third and final year of that program, where we'll conclude a CAD 1.1 billion investment.
With respect to the maintenance capital that we've included on here, a three-year look at our overall maintenance capital coming in at CAD 2.1 billion, 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 PHMSA issued back in October.
Post-2022, I would expect our maintenance capital, our three-year average maintenance capital, to moderate down to something in the CAD 1.9 billion run rate going forward. Mentioned earlier that LNG demand continues to be one of the prime focal points for growth going forward. We currently access five LNG terminals directly or indirectly, and we have plans in place to access three 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, 2 Bcf out of 6 Bcf. Going forward, we expect that to increase to somewhere between 40%-45%. Key focus areas for 2020 and beyond continue to be the safe, reliable operations of our pipeline. If we don't operate safely, we lose. 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 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 timeframe.
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. That, to me, is just a testament to the strength of the footprint that we have going forward. A lot more opportunities, both with respect to being what I call a catcher's mitt 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 CAD 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 CAD 1 billion worth of EBITDA for us. 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.
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 CAD half a billion to CAD 1 billion of growth projects annually, and I think that we very much could do that. With that, I will pause and turn the podium over to François to talk to you about the Mexico business.
Morning, everybody. Okay, 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 five revenue-generating pipelines today. In the Northwest, we have our Topolobampo and Mazatlán systems. On the 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 Tamazunchale 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 first quarter of next year, the lateral to Salamanca in Q2, and then finally La Lira to Tula in the third quarter.
Once we've had that into service, we'll have over $5 billion 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 SENER's indigenous consultations prior to building the middle 90 km 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.
I don't think we brag enough about some of the technical stuff we accomplished, 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-inch line being laid through shallow waters down to the seabed of the Gulf of Mexico. As you can see here, the concrete weightings, which ensure minimal buoyancy for the pipeline. 2019's 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 2.6 billion 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 into 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. The construction of Sur de Texas included an incremental $150 million investment to tunnel underneath environmentally sensitive areas near Altamira. The construction of that tunnel ensured protection of a water crossing, a mangrove forest, a beach, and a nearby reef. 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. 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 ends 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. We expect in service in 2020. Once the Villa de Reyes pipeline is complete, many of CFE's power plants in the central region of Mexico will 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 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. 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 will 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 Agua 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 CRE 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. Over the long term, the Mexican Pacific Coast appears to be a logical location for a potential LNG export terminal. Our port area in Topolobampo is the shortest path to connect abundant Texas natural gas to Asian markets. On a very preliminary basis, we're in conversations with many LNG project proponents to that effect. Again, here pictured at left, you can see the Sur de Texas pipeline has two entry points to land. One is in Altamira and one is down in Tamiahua.
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. Here you can see in this photo, part of the nearly 2.2 km Altamira micro tunnel, which is the longest of its kind in the world. 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.
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. This, of course, is expected to lead to additional organic growth on our pipelines that goes beyond what's portrayed on this graph. 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 three-phased 2020 in-service program. We will cultivate organic opportunities through compression additions and laterals using our marketing arm as a lever to optimize utilization and drive those expansions.
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.
Those are the end of my prepared remarks, and I think we're going to move now, David, to questions.
Thanks very much, François. As highlighted, we will provide the opportunity here for you to ask your questions. We thought it'd be most efficient to cover all elements of our natural gas pipeline business together. With that, I 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. Again, just a reminder, one and a follow-up, if you don't mind, just in the interest of giving everybody an opportunity.
Hi. Jeremy Tonet, JP Morgan. Just wanted to start off with the natural gas segment here in the U.S., and just wanted to see, you guys have spent a lot on modernization in Columbia 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.
Yeah, sure, Jeremy. 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 back 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 ANR system to all of our pipelines. 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. The environmental aspect is something that, quite frankly, is going to be a key focus point for us going forward.
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. There's lots of opportunities for us, and it's going to be a key focus going forward.
It sounds like the capacity creep with the compressor additions has been pretty meaningful recently, and it seems like it's very easy low-hanging fruit in so far 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, that capacity creep in any of these projects?
Again, you look at GTN project in and itself, it's 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. 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?
Andrew Kuske, Credit Suisse. I think both of you alluded to just the dynamics of the in-corridor building, and I think, Stan, you mentioned sort of half a billion dollars to CAD 1 billion sort of down the fairway stuff that you can do. In totality, when you look across really the three 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 CAD 2 billion-CAD 3 billion, 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 half a billion CAD to CAD 1 billion 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 CAD 1.3 billion worth of projects. Again, one or two of them are still subject to FID.
In terms of overall capital investment, we're going to spend somewhere around CAD 600 million or more in maintenance capital. We're going to spend about CAD 300 million - CAD 400 million on modernization programs, and we're going to spend about CAD 1 billion or more on growth projects. CAD 2 billion - CAD 2.5 billion a year is kind of what I think of a capital run rate in the U.S. business.
Andrew, on the Canadian side, I think we have more than CAD 10 billion right now in capital expansion in corridor. Everything except the CGL program is in corridor. 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 CAD 600 million a year. 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.
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. I think you'll see a pretty modest capital outlay from us over the next two or three years in the CAD 100 million-CAD 200 million a year or that range.
Maybe the only other thing that I would augment that with is CGL will become InCorridor once built. 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 that looks like that, I know Tracy has the cost of the build to add, double the capacity of the system, so another CAD 3 billion of InCorridor expansion. As we think about our gas business, the combination of InCorridor expansion plus maintenance capital, which is recoverable and both get a return on capital, I think you can easily see CAD 3 billion or CAD 4 billion a year of spend in our gas business for the foreseeable future.
Thanks. Chuck? Oh, sorry, go ahead.
Hi, it's Ben Pham, BMO Capital Markets. Maybe this question is for Russ or François if the corporate development hat, you switch it off there. Just curious, what's your appetite for maybe adding a utility to your energy infrastructure platform? I ask 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, maybe even a price-earnings valuation accretion as well.
You look at our growth trajectory here. We have CAD 30 billion 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 close eye on. I would say that, as you look at our core competencies on the power side and power and 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. 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. 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. 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.
Just to augment, 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. As we do our math, we don't chase multiple expansions and things like that. It has to work 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. We haven't had to chase that kind of asset at high prices. As Stan said, if we can do sort of InCorridor rate-regulated expansion at a 6x build multiple, that adds tremendous shareholder value.
As we talked about our growth rate of 5% - 7%, it's reflective of where we've been historically and where we think we can, for 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%- 7% have been driven by some tailwinds, a large acquisition, falling interest rates, a number of those things, which gets you a short-term bump to 8% - 10%. Those would be more in line with what our historic growth rates are. I would argue today that we're very utility-like, and if you look at our Canadian rate-regulated business, which I think has most of those characteristics, that's the largest growth component of our business going forward. 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.
Linda? Sorry, go ahead.
Thank you. We're looking at CAD 3 billion-CAD 4 billion 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 vis-à-vis 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, and François might want to augment my answer here, but going back to our self-funded model, we derive the greatest value by reinvesting our free cash flow and spending the debt capacity that's associated with the retained earnings that we derive on an annual basis. Pick a number, CAD 5 billion a year.
If we're doing CAD 3 billion-CAD 4 billion on the gas side in terms of our free capital that we have available. A CAD 1 billion or CAD 2 billion available. I think of things like Bruce Power, for example. Our share of that build is, again, pick a number, we don't know exactly what those are going to cost. We have five more reactors, a couple CAD billion a reactor, CAD 2 billion , CAD 3 billion a reactor. Our share in real dollars could be up to another CAD 10 billion over 10 years.
Pick another number of, say, CAD 1 billion a year. Now we're at CAD 5 billion a year. We haven't 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. I think about our liquids business, for example, as what's driving that Permian gas production growth is really crude oil that's behind it. That crude oil's 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 and Hardisty. We've got expansions that have been approved on our Grand Rapids System, for example, that are approved. Our Heartland Pipeline has been approved as well.
While we're not seeing the growth rates we saw historically in Western Canadian supply, production continues to grow, and that production's got to find its way to market, and we continue to sign contracts to do that. I do expect that we'll see continued growth, Paul. We'll talk about that in our crude oil business as well. 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. We're probably not going to be able to pursue all of the ones that are in our corridor without accessing different pools of capital going forward. This is a segue.
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 Canadian, East Coast LNG project, Saguenay. They're looking at a reversal at Canaport, those kinds of things, which will drive incremental expansions of our system. Things we haven't seen yet will continue to arise going forward. That's my long list. I don't know if anybody else wants to augment those.
It's a long list. Just a very quick follow-up question for François 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 what sort of opportunity there is?
By white space, you mean in terms of buildings or connections from the basins into our assets in-market?
Yeah. Well, what's the utilization, I guess.
Oh, I see. Okay.
Effective utilization rate.
Yeah
versus the 93% elsewhere.
Sure. In the Northwest, where we have the systems that are predominantly being utilized, we're somewhere between the mid-50s on one system and mid-70s on the other. On our systems in Central Mexico, we're more in the 25%-40% range, depending on the system. Obviously, we'll be looking to increase that. There's plenty of room for us to actually add connectivity. I fly over the construction areas and the pipelines we have, and you see a lot of industrial activity in the area. 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, increase the supply of very inexpensive natural gas, but to the tune of 40%. I think you're going to see a lot of industrial activity come to Central Mexico.
Okay, sorry. Pat, go ahead.
Sure.
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 B.C. 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 better reflect those flows in the system. If you think about 10 years ago or so, about 28% of the basin's volume was flowing into Alberta markets. Now it's about 40% of the volume. The volumes have changed pretty significantly, including where supply is coming from. 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 pull it to better reflect exactly what you're talking about. That's in front of the CER right now.
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. 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.
Sure. Go ahead, Rob.
Yep. 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 equity self-funding model, as you do have a number of in-quarter growth opportunities. You also did mention M&A. When you're looking at M&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, so 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 unless there is some financial dislocation that occurs in the marketplace. That's what we position ourselves and wait for. If it was to occur tomorrow, we would act tomorrow.
I'm not saying that's available to us, but if it's two years from now, that's when we would act. We're not going to try to force something that doesn't add shareholder value. We'll bide our time, we'll wait, if something arises that Columbia, for example, we'd always had our eye on and kept an eye on that asset. When the MLP market started to contract, we saw an opportunity to advance a conversation, that's what we'll continue to look for, is some event that would allow us to access a good asset at reasonable price. That's why we think financial strength and flexibility in all points of the cycle is important. Every time that one's occurred, whether that be the British Energy bankruptcy in 2002, 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&P company and a midstream company. GTN, we bought out of the USGen bankruptcy. 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 are 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. 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.
We'll be very careful about how we approach it. I think our narrative around M&A is that we're not frightened of it. We'll have the capacity to access it when it comes available, and that's what we're trying to do, is just trying to position ourselves for those times.
Then maybe just as one quick follow-up there. I'm assuming, and in the past you've said that, the crown jewel assets that you covet would be large contracted low-risk assets. 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. They don't necessarily have to be contracted upfront. It's can we turn it into a contracted 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 two operating reactors. Now we'll have eight operating reactors and a growth platform going forward. It's fully contracted through to 2064. 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.
We'll take on the risk, and then we'll look to mitigate the risk. If it is something like Columbia, it had a large cash flowing asset. The contracts weren't as long-term as they are today. It had a great growth profile along with it. 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. We've monetized those to parties that are looking to buy those kinds of assets.
The marketplace for that is very attractive right now with low interest rates. Look to redeploy that capital into assets where we thought there was a better long-term growth profile.
Rob. Go ahead, Rob.
Hi, good morning. Rob Catellier from CIBC Capital Markets. Thanks for your comments this morning. That last answer actually addresses some of my questions here. Knowing those strategic criteria for acquisition, I'm curious as to how important an investment in an 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. In terms of construction risk, acquisition risk, or all the other types, how do you view the importance of an LNG terminal, and what risk are you willing to assume?
I'll start. 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. Just the sheer scale of those, and there's enough other risks in those kinds of opportunities. Construction cost, for example, has been one that has been difficult for most parties to manage. There's only so much risk you can take on in those kind of projects. 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. I would say that we are not afraid of the notion of moving downstream into the LNG market.
I think, as we've said before, it would 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'd have mechanisms by which we could lay that off to construction contractors 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. I would just be clear on that criteria of commodity risk. Global LNG pricing is not a thing that we have a lot of experience with and don't have a lot of experience on how to lay off that risk.
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 may be on your radar screen, just biding your time. Can you just talk about how many, roughly speaking, assets you might have on that longer-term radar screen? If you can give some colors to breaking down, is it mostly gas pipelines, or is there power? Is there other platforms that you'd be looking at?
I think both Don and François 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. 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 buckets of larger themes. François, you guys see the inbound every day. Is that approximately what we're looking at?
Yeah, that would be accurate. 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. They're happy to deploy capital with us, and we have operating expertise, we have construction expertise. 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. 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, 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, the U.S., 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. We do keep an ongoing view of what those assets are doing and how they would fit with ours if those situations were to arise where we could buy those assets or pull those assets out. 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 up front. 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?
I can't say too much right now, Robert, because we are in discussions. Let me just say this. This framework will continue that separation of the Eastern Triangle from the Western Mainline. The Eastern Triangle will stand on its own. The Western Mainline 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 markets. We have seen there's something that happens on the regulated pipes is when volume goes up, tolls go down. We've seen volumes go up on the Western Mainline. We've seen that asset contract up considerably. That's, as I said earlier, when the magic happens.
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, 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. We are, I would say it's going very well. 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.
Go ahead.
Becca Followill, 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 four rate cases planned: Columbia Gas, 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 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. 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 Gas 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.
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. 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 FT. 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 TCO pool pricing, you get a premium price relative to Dominion or TETCO. All things equal, a producer who is long transport capacity on Columbia is going to want to keep that capacity to get a higher net back 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. They make up a very small portion of our overall producer portfolio.
Okay. We'll take one more. Go ahead. We'll stop for a break. As always, as we've highlighted, if 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? 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. 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. For Coastal GasLink in 2022, it doesn't come into service until 2023. It's not in rate base until 2023. When we put up numbers for 2023, we adjusted the Coastal GasLink to what we anticipate will be something like a 25% ownership level. Does that make sense?
That makes sense, but I 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. You're saying you're excluding it from the EBITDA analysis, but you're getting cash?
We don't. As I said a little bit earlier, our analysis on the regulated pipes is more of a net income analysis. We do as you say. It comes into service, it goes into rate base in 2023. In advance of that, we do have cash AFDC that comes into our cash flow.
It essentially is going to be a below the line item, Michael. You're not going to see it in EBITDA.
With respect to Mexico, as I mentioned, I think it's going to be some time as 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. 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 siting issues that we see in the rest of North America. 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, that 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. As François said, we're not shy of it. Obviously, Mexico is going to need new infrastructure, whether that be gas transmission or even electric transmission. 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, to find paths to make that happen. It's going to be core to their economic growth going forward. I actually do see they're mindful of those issues as we are, as we try to manage our risk. Just like we do in the rest of North America, as we look at a project, we will look at what those risks are and how we're going to manage them and mitigate them. Certainly, we believe that they will work through their issues. Right now, as you point out, there's a few bumps along the road. There's a few bumps along the road in all places in North America, and Mexico is not unique in that regard.
Great. Thanks very much. At this point, we're just running a couple of minutes over, but we'll stop for a break now. If I could ask people to make their way back into the room at 10:15 A.M. We'll restart at that point with Paul Miller and an overview of our Liquids Pipelines business. Good. 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. 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. Good morning, everyone, and thanks again for joining us here today. I will start off with an overview of our pipeline system, which runs from Northern Alberta, the producing areas of Northern Alberta, down through the Illinois market and down to the U.S. Gulf Coast. 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 six million barrels per day of refining capacity. This pipeline network is underpinned by long-term take-or-pay contracts with creditworthy counterparties. The spot capacity that we are required to set aside remains in large demand.
We continue this vision by securing additional support for planned pipelines, accessing additional supply, and accessing new markets. We have three 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 toll design, where the fixed portion provides us with a return of and on 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 Marketlink, up to 100% in the case of some of our Alberta pipelines. Our marketing affiliate generates EBITDA around these pipelines, as well as third-party pipelines.
I'm first going to take a look at Canadian production, Canadian producers, and this slide here represents global producer ESG scores from three different firms. You can see where Canada is situated, on the left there at the top end of the range with the 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. Canada possesses the unique and successful combination of high ESG scores and high reserves, and production of those reserves continues to grow. 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. U.S. Gulf Coast refiners are the most profitable in the world, and they need access to heavy crude oil.
This creates opportunity for further market penetration for Canadian heavy crude, potentially serving the entire market within the next two decades. This opportunity in the U.S. Gulf Coast aligns very well with the TC liquids business. Oil sands production is sustainable, cost-effective, and growing. TC provides direct and cost-competitive transportation to this market. Latin American supplies are in demand, and 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 of transportation to that marketplace. Looking now at U.S. production, the story over the last two 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.
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 two million barrels per day added, ± 2 million this time period, and that will have an impact on differentials, and that will cause differentials to tighten up a bit. 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 on transportation capacity will exceed the transportation capacity.
We very quickly started increasing the capacity of Marketlink from about flowing 400,000 barrels per day in 2017 to an excess of 700,000 barrels per day in 2019. As we increased 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. 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. Like in 2017, we're not going to sit back idly.
We're working with various producers in various basins, Bakken, SCOOP, STACK, DJ, to encourage that production to come into Cushing and onward down to the U.S. Gulf Coast. Then some of our activity will include new competitive tolling to divert that volume to Cushing and down Marketlink. We'll continue with the Keystone capacity enhancements and continue to direct that volume to Cushing and down the path. In 2020, we're going to increase the 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 Marketlink from other carriers, be it through our ability to deliver to different future contract pricing points in the prom 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. We'll apply the same approach of active management to the entire pipeline network. We have a very good strategic corridor right down the Mid-Continent. We're close to the emerging supply, and we're close to the marketplace. 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 CAD 1.15 billion of proceeds, retaining 15% as well as the operatorship. 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. We have many growth projects besides Keystone XL. Three 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 is a CAD 700 million 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 CAD 900 million 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 Terminal, which is a CAD 300 million 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 through Keystone XL project. 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 three 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 Nebraska. 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, remobilizing them.
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. 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. 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. Our marketing affiliate captures value through both locational and time differentials. With the Permian build-out over the next two years, there will be some volatility. There will be some choppiness, our results will come from our base contracts of stable cash flow, as well as what value we capture from this market volatility. Directionally, we're showing that in that light blue cap on top of the column in 2022.
Going forward, we'll keep doing what we're doing. Our focus will be the safe and reliable delivery of energy through 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.
Okay, thanks, Paul. Similarly, if you could just raise your hand, we'll get a microphone to you quickly, and be happy to take your questions.
That good?
That may be a record. Sorry, we've got one back there.
Hey, guys. Michael Lapides with Goldman. When you think about repurposing assets, how would you think about what's on the hit list for that? 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 it's 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 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 siting new greenfields as well as repurposed assets and acquisitions, for that matter, within your existing footprint, and that'll be where we retain our focus.
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 two or three years, increasing our capacity on the storage side. Just last year, we added an additional one million barrels of storage at our Cushing terminal. 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. I think storage will continue to be a very important part of our infrastructure.
Thanks, Michael.
There's a second part, Michael. I'm sorry, I can't remember.
Export.
Oh, export. Yeah. 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 a diversity of supply, as well as a producer looking for markets to enhance net back. We continue, and in 2020, we are going to increase our connections to various terminals, including export, probably add four 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? 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. On the cost side, two aspects to cost. The first is material cost, we have much of the material on-hand today, the valves, pipes, pumps, motors, et cetera. 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 course, would be your lay contracts, your contractors. That remains a fairly competitive market, and it's going to ebb and flow depending on what other projects are underway. We watch that very closely. We do see costs moving around a bit, they're still within the fairway of what we anticipated and what we need to make Keystone XL a very competitive pipeline.
Pat?
Yeah, 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 from capital cost, if you wish. The capital, the fixed toll, provides that return of and on capital, and our operating costs are recovered through the variable toll. 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 are passed through to the shipper.
Okay, great. I know it's still early days. You'll be operating at reduced pressures, but any timeline to get back to full operating capabilities and also be setting the stage for that 50,000-barrel-a-day expansion?
It is early, Pat, and there's no timeline yet. How the process works is we've extracted that piece of pipe that was damaged or that suffered the leak, and we've sent it off to an independent lab. They take about two months to determine the root cause failure analysis. In the meantime, we will be operating under the de-rate. Again, the de-rate is not the entire pipe, it's select sections of the pipe, on either side of the feature, if you wish. 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'll set the stage for us to resume the full pressure and ramp up the volumes at that point.
Key for us, though, is to find out what happened, and restore the pipe to full pressure, full capacity safely.
Okay. Oh, sorry, Rob.
Sorry, just to follow up on Patrick's question. 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. 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?
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 derate, 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 those are all the questions for Paul, well, thank you for providing an overview of liquids. François Poirier will make his way back to the stage now. Amongst his other capacities, François is President of our Power and Storage business. François is going to provide an update on that now before we turn it over to Don.
Great. Thank you, David Moneta. 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, also ownership of the Bécancour Generating Station in Quebec and the Grandview facility in New Brunswick. Our net interest is approximately 6,000 MW, made up of low-cost, low-emission, base-load generation underpinned by long-term contracts. We also own about 115 BCF of non-regulated natural gas storage in Alberta, which makes up approximately one-third of the total storage in the province.
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 late in the first quarter 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 US$450 million. As I previously mentioned, in July of this year, we entered into an agreement to sell the interest in our three natural gas-fired plants in Ontario for approximately CAD 2.87 billion. We expect the sale to close by the end of the first quarter 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. I can tell you that the replacement equipment has now been delivered to the site and commissioning activities have restarted. We expect to reach COD on Napanee late in the first quarter, then closing on the transaction in fairly short order. I want to say that Ontario continues to be a core market for us. Our investment in Bruce Power remains a high priority. 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 MCR 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. 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's operating safely and having achieved excellent safety and operating results for many years now. Bruce is finding ways to improve overall site production, as exemplified by Unit 1's eclipsing of the previous record of 361 days of continuous generation and the highest power output production over a continuous three-year period in its history from 2017 to 2019.
You can see on this 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. 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. The contracts have all been executed and contractors have been mobilized. 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. We received in April of 2019, an increase from CAD 68 a megawatt hour to CAD 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 Bruce Power Life-Extension Program through 2023 is CAD 2.2 billion. We've got about CAD 900 million of that spent to date. The remaining program capital cost estimate in 2018 dollars for the remaining five units is $6.0 billion. 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 CAD 8 billion capital program underpinned by long-term contracts spanning to 2064. Throughout the first few MCRs, as we continue to invest capital, Bruce will generate steady equity income. As generation increases beyond the fourth 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. Bruce Power is also evaluating opportunities to increase site capacity, resulting in reduced emissions and system costs in the province.
You may see some announcements 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. 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. 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 MW of offtake from a solar facility to be built in Southern Alberta. The facility's 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 MW of capacity whenever it is produced. 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 in 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.
In Alberta, in December 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's working with Siemens to build a plant for this innovative technology, which will generate about 10 MW of emissions-free electricity at the site. If you think about the number of compressor stations we have across our entire system, there's definitely a very exciting opportunity here for us to leverage this technology once it's been proven out. The project's in-service date is 2021 with an estimated capital cost of CAD 45 million. Renewable power continues to increase its market share, we also believe there'll be an increased demand for firming resources.
As such, in March of 2019, we were again awarded a grant by the province of Alberta to help fund a proposed 10 MW solar project with 5 MW 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, with a proposed in-service date of July 2022, with a capital cost estimate of CAD 45 million. The application process is underway with the Alberta ISO. Finally in Ontario, we're proposing to develop a pump storage hydro project that would provide 1,000 MW 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 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 five Bruce MCRs, as well as the waste heat and solar and battery projects that I mentioned on a previous slide. 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. That's the end of my prepared remarks, and I'd be pleased to take questions.
Thanks, François. Sorry, just go ahead, Dean. Sure.
Hi there. It's Dean Highmoor from Mackenzie. Just had a question on the pump storage. Just at a ballpark, what would 1,000-megawatt pump storage project, what would the CapEx be on that? What are the next steps you have to overcome for this project to actually happen?
Yeah. 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 Defence land. 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 CAD 3 billion-CAD 3.5 billion 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, a more advanced version, obviously, with the latest and greatest technology. 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. It worked great the first time, but the technology was no longer cost competitive as things advanced. It needs to compete on a cost basis for us to be able to replicate this across our system. The new technology, we're working with Siemens and we'll see what the initial investment bears in terms of actual cost of production.
Ideally PPAs as you have in the past?
That's typically our approach, yes.
Okay. Thanks, Andrew. Go ahead, Jeremy.
Thanks. Jeremy Rosenfield, Industrial Alliance. François, you said new technologies and solar and storage are certainly interesting and emerging technologies that are becoming more popular. 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. 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. Is that on the radar at all?
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. We've found the returns to be quite moderate. It is an opportunity to deploy a fairly sizable amount of capital. Frankly, on a risk-adjusted basis, it didn't really compete well with our current opportunities and our footprint. It's something we're continuing to watch, but it's not been a priority for us.
Robert, sorry. Yeah, please.
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 Bécancour and it's great to be paid per plant not to run, but it's still not running.
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 recontracting projects at comparable cash flow streams as were under the contracts is a mixed bag. I think that to some extent has informed our decision to monetize some of our assets. Clearly, 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. As we look at terminal value when 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. 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.
By our calculations, there are often very robust assumptions of power prices post-contract expiry that we don't think are realistic.
Especially with the chunk of your potential investment on the pump storage and it being in Ontario, recognizing it's a different technology than you've ever constructed there.
Right.
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-based route. We haven't actually landed on that. 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.
Thank you.
Thanks, Robert. Any other questions for François?
Just another capital allocation question here, and maybe Russ wants to weigh in. 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 pipeline 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.
Yeah.
We think that all the assets that we invest in are sustainable for the long term. We look for return of and on 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 we're an extremely responsible company across all forms of energy. As we look at investments, it's primarily math-driven. To François' 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.
When the cost of capital that folks are willing to buy those assets is lower than our cost of capital, we look at it as a funding source. We look at shareholder value first. Our strategy around ESG will be straightforward, transparent, and it'll provide all the information that we need across all of our assets. 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, Pat. Okay. Thanks, François.
We'll turn the podium now over to Don Marchand, our Chief Financial Officer. Don's going to provide you with a finance update to close out the morning.
Good morning. The coveted last speaker of the morning slot, where there'll be a few people checking their watches and playing Fortnite in the back of the room, the guy who sets my compensation, not too upset if I dare drag it out and have no time for Q&A. I'm not sure where to go here. I was thinking of how to try to characterize the overall story here, and thought, is it stylish or sexy? No, rarely. Rarely, if ever. Is it effective and reliable? Yeah, this thing works over time. That reminded me, it sounds very similar to when I proposed to my wife, actually, and she just asked, "Are you asking me to marry you, or are you trying to sell me a set of snow tires?" With that, we'll tie into it.
It's been a year of great accomplishment here. We're in a very good spot. We 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. I think we're positioned for a decade of double-digit TSR ahead of us, if we can execute. We're always climbing the proverbial wall of worry. There is always something on the horizon that's of concern. Just going back 20 years, remember Y2K? Everyone was worried about that about 20 years ago today. 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's the growth? Is there too much growth? There's always something, but it's a very resilient business model. 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. This does work over time. I'll 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 up front here, I'll generally refer to Canadian dollars. We're using a 133 exchange rate within the presentation. In terms of depreciation, we generally depreciate things over 40 years, about 2.5% of gross PP&E.
If you're modeling income taxes, extract Canadian regulated gas pipeline income, which is flow-through equity AFUDC as well, and apply a mid to high teens effective tax rate. In terms of cash taxes, it would be in between rails of about 40%-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. I'll walk you through what that looks like on the various charts where it is incorporated into there. As for the LP, it's status quo in terms of ownership within the presentation materials. With that, we've had a fairly straightforward doctrine or philosophy that's 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. 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. It's rarely different this time when it comes to the latest funky financial or commercial structures. The model's pretty simple. Creating long-term annuity streams, finance it with long-term capital, capture a spread, repeat, repeat. We see value in building things. We actually have over 1,100 engineers on our team. Building things at a high single-digit EBITDA multiple, then having them 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 debt financing at the FERC asset level for rate-making purposes. We do finance at Bruce, given its unique nature. Similarly, at Coastal GasLink and one candidate in the future would potentially be Mexico to have a debt at the asset level. Generally, we prefer to keep it simple and finance things from the center. Thoughtful capital allocation is critical. We look for a balance between reinvestment and a valued payout to our shareholders. Everything is looked at through the lens of per-share metrics. 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 proportionately 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 to 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 Marketlink business, good cost control, and turning on capitalized interest in AFUDC into actual cash earnings. We'll see CAD 10 billion of assets come into service this year.
CAD 8 billion was complete by the end of September, with another CAD 2 billion here in the fourth quarter. In terms of asset sales, we've announced CAD 6.3 billion year- to- date. We have closed on Coolidge, Northern Courier, and Columbia Midstream for CAD 3.4 billion with the Ontario Thermals deal, as François mentioned, for CAD 2.9 billion to close, we expect in the first quarter of 2020. We believe we're on track to achieve a high fours run rate in terms of debt-to-EBITDAs 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. Those are our two key credit metrics going forward. We were disappointed to lose our A rating at the two agencies here over the past couple of years.
That said, we respect it as their grade and their opinion. We accept that. We reiterate, we intend to be the top credit in our sector going forward. We see real value there for all of our stakeholders, 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, that's between now and the end of the year. We are very pleased with the, as I mentioned, the quality and the quantity of interest there. 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. We turned it on again in 2016 when we acquired Columbia Pipeline Group. 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. It just has a fancy new moniker. It's just fallen under the realm of risk management as we look back into the rear-view 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. We are on track to do that. We have added resources to our IR group this year and throughout the company. As was mentioned earlier, we've added sustainability to our HSSE 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. In terms of 2019 funding, it was about CAD 15.2 billion that's represented in each of these bars. On the left-hand side, we will spend CAD 8.8 billion this year. It's actually about CAD 1 million an hour, for context, on capital programs. Coastal GasLink is about CAD 1.1 billion of that, which remains fully consolidated in these numbers. We will pay about CAD 3.1 billion in dividends and distributions, and we have redeemed CAD 3.3 billion of debt maturities.
On the right-hand side, we will expect record cash flow of about CAD 6.9 billion for the year. We have sold CAD 3.4 billion of assets, as we mentioned earlier, excluding the Ontario Thermals, which is 2020. We'll see about CAD 925 million of DRIP proceeds over the course of this year. That includes the Q4 2018 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 $1.1 billion hybrid at a rate of 550 in September in the U.S. market. That attracts generally about 50% equity credit from our agencies. On top of that, CAD 2 billion 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 412.
To complete that, it's about CAD 500 million of movements in CPPL cash. That has contributed to what has been a pretty exceptional four-year funding run here of about CAD 72 billion. 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 CAD 34 billion of CapEx, CAD 15 billion of acquisitions, which was primarily CPG and CPPL, CAD 12 billion in maturities and CAD 11 billion in distributions. Consistent with our theme of community service, making sure no banker goes without a hot meal or a hot car.
We've got CAD 24 billion of cash flow, with CAD 17 billion of debt issuance, CAD 8 billion of hybrids and preferreds over that timeframe, again with 50% equity credit, CAD 12 billion of equity issuance, eight of which was discrete issues, three on DRIP and one on ATM, and about CAD 11 billion from portfolio management. Included in that amount is about CAD 1 billion of project recoveries that we received on PRGT and CGL in this timeframe. In terms of de-leveraging and EPS growth, I think I showed you this chart last year. 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 sixes to the targeted high fours here, from 2016 post CPG to now. Very pleased about that.
On the right-hand side, EPS moving from CAD 2.78 in 2016 up to, call it the low CAD 4s this year. Again, a notable increase in quality as we've exited merchant businesses and invested more heavily into regulated contracted assets. Strain your eyes here in the next couple of slides. What this is meant to depict is the diversity and quality of our revenue streams, as 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 five distinct businesses. Again, very diverse. I would also highlight our ability to rotate capital amongst our businesses. The ability to invest in three different businesses in three different countries allows us to pursue opportunities as they cycle from one to the other.
We're not really beholden or tempted by having to force capital into one specific business or one geography. In 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 Marketlink 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 US dollars, and that includes our Mexican business where our revenue streams are paid in USD.
As a natural hedge, we have $25 billion of debt, including hybrids and the associated interest expense that comes with that. That leaves us long, thumb in the air, approximately $2 billion each year on an after-tax basis. We actively hedge that on a one-year forward basis. Our sensitivities would be, it would take about a $0.10 move in the currency to impact EPS by a $0.01 in the prompt year. 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 to medium-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, being quite topical right now. Our counterparty portfolio is diverse. It is heavily investment grade, 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, 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 assurances held. Looking forward now, turning to the capital program. Again, continuing with the strained eyes.
With just over CAD 30 billion of secured projects through 2023. Included in here is three years of maintenance capital, with CAD 5.4 billion of maintenance capital over that timeframe, 90% of which is recoverable through our regulated businesses. The portfolio here is diverse. It's mainly small to mid-size 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 non-recoverable aside from that. Again, a proven ability to replenish this list year after year. CAD 30.3 billion on this table. We've spent about CAD 9 billion to date, it'll be the CAD 20 .5 billion left to spend. About CAD 17 .5 billion of that will be in the 2020 to 2022 period, and about CAD 4 billion thereafter.
CGL is still fully 100% consolidated in these numbers right now, pending completion of a JV. What this is meant to do is depict 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 and term probably differentiates us from many of our peers in our sector. Just walking through this here, about CAD 23 billion of the CAD 30 billion is depicted here. What's excluded is maintenance capital and the Modernization II program for CAD 7 billion from this chart. I just note that six of the CAD 7 billion that's excluded here is actually rate base investments, just without contracts behind it. Moving left to right, NGTL and Mainline, it's about CAD 10.5 billion of investment there. U.S. PL has about CAD 1.5 billion of investment.
All that investment is included in rate bases where we do recover return on and of capital. In terms of belt and suspenders, we actually do have contractual backing beyond that. In the case of the Canadian gas business, they average about 12 and a half years. It's about 10 years for received capacity and about 16 for delivery capacity. 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 length, so there is no 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. Our Mexican business payment streams are in U.S. dollars. On the far right-hand side is Bruce Unit 6, major component replacement, and the asset management program. That's fully captured within the contract for Bruce that goes out to 2064. Again, very long life, very high quality backstopping for the capital program. Getting a little more granular here, it's about $18 billion, as I mentioned, of CapEx over the next three years, $7.2 billion next year, $6.2 billion in 2021, and $4.6 billion in 2022. $12.2 billion of this is growth capital, $5.4 billion is maintenance capital. There's about $400 million 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. What's depicted on here is actually a fairly minimal cash contribution to Coastal GasLink over this timeframe when you factor those two financing mechanisms in there. Again, fairly minimal cash contribution to CGL over the next three years. Maintenance capital, as I mentioned, is CAD 5.4 billion. Again, to put it in context, it's about CAD 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 on some of our assets, particularly in the United States. We've had new regulations come into force, as Stan mentioned, and a condensed timeframe to complete maintenance capital as dictated here in Canada. We expect that number to normalize, probably around CAD 1.5 billion once we get beyond this horizon. Again, right now, elevated in about the CAD 1.8 billion average range over this timeframe. 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 three years, nothing too sexy or stylish here for the bankers.
On the left-hand side, CAD 18 billion of capital, about CAD 11 billion of dividends, that is at an 8%-10% growth rate through 2021, and in the 5%-7% range for 2022 incorporated into that number. Cash from operations, about CAD 21.5 billion over that timeframe, we do expect the sale of the Ontario Thermals to close in early 2020 for CAD 2.9 billion. That leaves a funding need in the capital markets of about CAD 4.5 billion over this timeframe. That excludes debt maturities, which I'll touch on in the next slide, that is maintaining our credit metrics within the metrics outlined earlier of high fours debt to EBITDA and in the 15% 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. 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 drop-downs as something financially attractive at this point in time. We do have some residual assets from the CAD 500 million of contracted EBITDA that was mentioned last year as saleable assets. 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. We will weigh that against the tenet of trying to keep things simple, understandable, and maintain 100% of everything.
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 CAD 5.4 billion over the next three years. That's on top of the previous slide's financing need. It's about three and a $500 million . That's depicted in the dark blue on here. The currency exchange at 133 is in the light blue, we have about CAD 800 million maturities in green. Average term of the debt maturing is 4.2%. When you take it all together, the CAD 4.5 billion of senior debt on the prior slide, the CAD 5.4 here, we see about CAD 10 billion of senior debt issuance over this timeframe into the markets in Canada, United States, and potentially other markets should conditions or economics warrant.
In terms of liquidity, cash flow is robust and growing. We have over CAD 10 billion 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, 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 CAD 5.9 billion in 2015, consensus of CAD 9.3 billion this year, growing to CAD 10 billion+ in 2022, representing about an 8% CAGR over that timeframe. 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.
A bit of drama in there, but again, a fairly healthy growth rate over that timeframe. 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, again, credit metrics to be achieved, and the DRIP has turned off over this timeframe. I'd just note that about 70%-75% of our EBITDA does convert to cash, and we expect that to continue going forward over this timeframe. There are a number of normalizing items I just want to point out for you on here. In the 2019 number, there is EBITDA from assets that have been sold. It's about CAD 250 million related to the assets that were included in the CAD 6.3 billion 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. If you're looking at a point in time in 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 achieve the 8% growth rate out to 2022. I'd just highlight that 95+% of the EBITDA in 2022 is contracted or regulated. One last one is Canadian regulated EBITDA. This was a bit of a Kumon moment here. Canadian regulated gas pipes is a flow-through business.
One thing I would highlight here is we have seen new regulation, new tax rules come down in Canada where we have accelerated tax depreciation, and there's about CAD 75 million-CAD 100 million a year that we pay in less tax on that business that is passed through to our customers. If you're simply taking a multiple of EBITDA, we'll actually probably see EBITDA decline by CAD 100 million because we pay less tax, which we pass on to our customers. No impact on net income, but it's difficult to argue that the value of the enterprise has dropped CAD 1 billion because of that if you are just simply applying an EBITDA multiple to the business. Canadian-regulated pipes are an anomaly if you are strictly looking at EBITDA numbers. On the far right-hand side here, post-2022, in 2023, we see about CAD 10 billion of assets coming into service.
That includes Coastal GasLink, the NGTL 20 to 23 expansion, and Bruce Unit 6 coming back. This slide, we've taken it out to 2030. 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. What's reflected in here, aside from the purple arrow swooping upward, is if we complete our CAD 30 billion secured capital program, spend maintenance capital over this timeframe, normalize recontracting of our U.S. business, particularly, and a modest contribution from volumetric and market-exposed businesses. We have about a CAD 10 billion EBITDA base that goes out a decade with a pretty high degree of visibility. When you take all of our assets together, this portrays, we describe it as a pseudo-utility revenue stream. Reflected in there is everything spent in Canada goes right into rate base.
Our Coastal GasLink are 25-year contracts, as noted previously. Everything in Mexico is under a 25 or higher year contract base. This reflects our liquids business, the contracts that are in place right now. 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 that purple arrow upward. Again, the five core businesses, strong fundamentals, and an irreplaceable 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 CAD 10 billion, but nothing beyond that. There is a decade plus investment opportunity here.
This is emission-less, economic, well-supported in its jurisdiction, power that represents in the low 30s% of Ontario's power needs here, contract out to 2064, and returns that are probably at the upper end of our return spectrum of our portfolio. Bruce , should it go ahead, as we work through these various refurbs, does become quite accretive as you get towards the end of this timeframe and well into the next decade. Something to bear in mind here as we look at potentially a CAD 10 billion investment in real dollars in Bruce over the coming years. In terms of dividend policy, the only negative on this slide is it's bearing an unusually high correlation to my body mass index over this timeframe. Two or three more years of this, we'll have to reinforce the stage when I come up here.
Principles on our dividends, 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. It still does factor into our decisions. 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%-10% through 2015. That's really driven by the shale build-out and the acquisition of CPG. We do reaffirm the 8%-10% growth rate through 2021 that we've previously mentioned the past several years here. Again, no fundamental change to payouts. Post-2021, we see organic growth in the 5%-7% range. That's driven by continuous improvement in our asset base, completing the CAD 30 billion of secured projects we have underway.
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 three to four years visibility on that. By the time you permit, spend the money, get stuff in service, that's generally the timeframe that we do have where we put something on the secured project list. We do have CAD 20 billion of projects in development right now, including KXL, an entourage of Alberta liquids projects, the various Bruce restarts and beyond Unit 6, and the Merit 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.
Again, we see 5%-7% organically over this timeframe. Inorganic is not included in here. There's been a fair bit of discussion today about M&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. Somewhere over this timeframe, if something does appear that allows us to bolster this rate, we will pursue that. To wrap up here, the model is simple, understandable, proven. CAD 10 billion of EBITDA with high visibility through the end of the decade. That's a pretty nice base to build off of. Financial house is in 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 a disproportionate share of growth given our footprint. If we stick to our risk preferences, we should be able to achieve returns appropriate for the risk that we're taking on here. We will be cautious in developing new projects and how we parcel out risk and how much money we spend up front on that. 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. With that, happy to take your questions.
Durgesh Chopra with Evercore ISI. Thanks, Don. Can you touch on 2021 versus last year Investor Day? I know there have been puts and takes, we've got the asset divestitures, we've got the 501-G settlements, the backlog has changed. Where is that roughly the CAD 10 billion EBITDA for our models, where does that sit, directionally speaking, in your internal projections?
To reconcile the CAD 10 billion 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 Unit 6 was in last year.
Yeah.
Liquid strength that we're seeing in terms of Marketlink and TCLM. There's, thumb in the air, probably a good half billion dollars from last year to 2021 to where we are today.
Yeah, I think as Don's highlighted, the key difference would be the execution of the CAD 6 billion of asset sales this year that obviously wouldn't have been included in the model last year.
Thanks. Then just one quick follow-up, if I may?
Sorry, go ahead.
In terms of forward-looking growth, the 5%-7% EBITDA growth, am I right in thinking about since this growth is coming from predominantly the regulated portfolio of businesses that the earnings growth, the net income growth is directionally speaking lower than the EBITDA growth?
The 5%-7% is a dividend growth rate, so it would be backed up by earnings and cash flow. Where we fall out in that range, as I mentioned, it depends on the mix of the projects and the cadence. Right now, we have a pretty heavy weighting in NGTL, which is probably at the lower end of the spectrum. Over time, that shifts around. Then how we execute on these projects. The 5%-7% range, it'll be somewhere in there, but it'll depend on mix, cadence, and execution.
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?
Yeah. We don't give specific earnings guidance. That's where you guys add all the magic. Yeah, 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 high correlation to the three of them.
Thanks.
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?
We're comfortable with our leverage, and we do look to the credit rating agencies as to where they see comfort as well. We do value their input on this. You can argue on a specific asset, could you lever them up higher? Yeah, potentially, but you end up with structural subordination and all that. No, I would say we're generally comfortable with the capital structure of the CAD 100 billion asset base taken as a whole. Again, you could drill down into specific assets. Could you lever them 80/20? Probably could on this. We're 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.
More limited opportunities to do things like Northern Courier and then CGL.
Yeah. We'll be cautious. The trade-off there is adding structural subordination and complexity. Where our principle of keeping it simple is. Yeah, 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?
Thank you. Don, just when you look at your capital plan, you're pretty much fully funded, but there's not really wiggle room. As you see additional projects, especially some of the larger ones, you've mentioned some of the levers you have to pull. As you look at it right now, where do you see the most attractive levers, whether it's asset monetizations, JVs, or hybrids?
I'll approach that in two ways. Firstly, 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. In terms of landing new stuff right now, we wouldn't see any material spend probably until the 2022, 2023 timeframe 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 and what's the spend profile look like. 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. 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 third-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. 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? What's the timeframe? What is the actual cost figure? Yeah, 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 just have one last 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 are 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 one 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.
Wasn't me.
Sorry.
We're done. Sorry, go ahead, Ben. Sorry. While we're moving.
Hi, it's Ben Pham, BMO. Don, just wondering if you can quantify where your payout ratio goes next couple years through 2021, whether it's EPS or do you care about distributable cash flow now?
Historically, we've been into kind of a 80%-90% comparable earnings, 40% cash flow payout range. It's where we've largely run the last couple 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 wild card, 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. Right now, we don't see any significant veering away from what's worked over the past 20 years.
May I ask on the durability of the cash, was at a slide CAD 10 billion through 2030, looks rock solid. Is there an element of First Nation easement expiration that could become a headwind for you in that 10-year view?
Sorry, First Nation involvement in that CAD 10 billion?
Easement expirations or state easement expirations that maybe becomes a wild card in eight, nine, 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 timeframe.
We have some of those kinds of arrangements. I would say they're not material, and there's no material expiry in those timeframes. We have, as I mentioned earlier, pretty solid relationships with the indigenous communities that are our partners today. As those arise, I would expect them to be renewed in normal course. They're pretty small.
Jeremy Tonet, JP Morgan. Want to come back to the 5%-7% dividend growth looking further out here. Is there a target level of CapEx that gets you to that end? How do you think about, I guess, how those two interrelate there? Curious with the payout ratio, you've been at 80%-90% for some time now, that's been historical practice. If you were of the belief that a lower payout ratio, maybe slower dividend growth, could give you more of a utility-like PE valuation, because it seems like most of the business screens more similar than not to utility risk profile. Would you pursue that or any thoughts around, I guess, those topics?
Yeah. In terms of the payout ratio, 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 can debate the 4.5% area yield that we have right now with a 180 10-year Treasury. 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. 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 DRIP and the increase in the common shares outstanding. That's step one here.
This trajectory has worked over time, and there's nothing that we see structurally that says we should move off of that.
As far as the 5%-7% growth rate, is it a certain amount of capital per year that would be?
Yeah. Right now, our capacity's probably in the CAD 4.5 billion-CAD 5 billion a year range of capital that's available for us. That compounds over time with the extent we retain it. Where we fall into that is how we spend it. If it's 6%-7% return Canadian reg stuff versus high single digits or higher bolt-ons in the U.S. or Mexico or Bruce will inform us where we fall in that range, hence the 5%-7% range. Over any specific one or two-year period, it's hard to move it around, but over a longer period of time, we can move upward in that range if it gets redirected to things like Bruce, like Mexico, like bolt-on U.S. PL investments.
Then maybe just a quick housekeeping item. You noted the FX sensitivity there before. I was just wondering, have there already thoughts to kind of switching to 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. Other than that, we've looked at it recently. There are strict GAAP criteria as to when you would shift your functional currency. We're not near the threshold right now. Right now, the Canadian dollar remains the functional currency, and with our current suite of projects and that, we don't see that changing, unless there was a material increase in U.S. dollar investment through M&A or just a 10-year string of really heavily concentrated U.S. dollar versus Canadian dollar investment.
Oh, sorry. Go ahead, Rob.
Yeah. Rob Hope, Scotiabank. Just a clarification. When you were talking about CAD 10 billion of EBITDA in 2021 with, I think you said CAD 400 million or CAD 500 million of headwinds, does that mean that you're going to see a strong growth in 2022? 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?
Yeah. In terms of a specific year, I wouldn't say so. We do have significant assets coming on stream next year as well. That's really the driver there. Is it a spike and then 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 is just going to wind up with a couple of brief closing comments then lunch will be served.
Sorry about that. Yeah, with Don, congratulations to Dave and his team. Obviously, as I got on my clock, it's exactly 12 o'clock. Great job on keeping us all fed and on time, and comfortable over the last few hours. Just a couple 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. 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. 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 five operating platforms in three core geographies provide us with substantial multiple platforms for continued growth. Today, as you heard in granular form, we are advancing CAD 30 billion of commercially secured projects with another CAD 20 billion 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%-10% through 2021, and a 5%-7% growth thereafter, consistent with the past two 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. 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. Again, thank you all for joining us today.
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. If you have the opportunity, you're more than welcome to join us. 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.