Okay. Well, thanks very much. Good morning, everyone, and welcome to TC Energy's 2018 Investor Day. I'm David Moneta, Vice President of Investor Relations, and I'd like to start this morning by thanking you for taking the time to join us. We very much appreciate your interest in the company and obviously, your support. We intend to use this morning to provide you with an update on the many initiatives that are underway that are obviously expected to create significant shareholder value. We hope to also provide some insight into the trends that will help shape the future of our industry. We'll begin today with Russ Girling, our President and Chief Executive Officer. Russ will provide you with some comments on the progress we've made over the last number of years, our key priorities, and our promising outlook for the future.
He'll be followed by Tracy Robinson, Stan Chapman, Karl Johannson, and Paul Miller. Each of them will provide you with an update on our natural gas pipelines, liquids pipelines, and energy businesses. Don Marchand, our Chief Financial Officer, will close out this morning with a finance update. Copies of their presentations are included in your handout. For those of you listening via webcast, 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 with a number of opportunities this morning to ask questions. I would ask that you limit yourself to one question and a follow-up in order to give others the opportunity as well to ask questions that they may have. Sorry. I apologize, there seems to be a bit of a delay. Sorry, there we go.
Sorry about that. Before we begin, I would like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on those risks and uncertainties, please see the reports filed by TC Energy with Canadian securities regulators and with the U.S. Securities and Exchange Commission. Finally, a couple of comments on non-GAAP measures. We will make reference this morning to Comparable Earnings before income taxes, interest income taxes, depreciation, and amortization, or Comparable EBITDA, Comparable Earnings , and Comparable Funds Generated from Operations . These measures are used to provide you with additional information on our operating performance, liquidity, and our ability to fund our capital program. However, they may not have any standardized meaning under US GAAP and therefore are 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.
Thank you, David, good morning, everyone, and thank you very much for joining us today. We do appreciate you taking the time out of your busy schedules to support us and listen to our story. It's hard to believe it's been 12 months since we were here together last year. Looking back over the last year, I'm very pleased with the progress that we've made at the company. Today, our portfolio of high-quality, long-life assets are performing extraordinarily well, and our long-term strategy and financial discipline has positioned us well for continued growth for many years to come. Over the next few hours, we look forward to sharing with you some significant advances that we've made in our business over last year and the promising outlook that we see for this company in the coming years.
This slide right here provides you with the key themes that we're going to be covering today. First of all, the demand for our services, as many of you have heard me say, has never been greater. All of our systems are full. They're getting contracted for long periods of time, and we're looking at several expansions of the various pieces and parts of our system. As I mentioned, our businesses are performing extremely well. Comparable EBITDA, funds generated from operations, and earnings per share are all expected to hit record levels again in 2018. Our success is driven by a corporate strategy which has been in place since the year 2000, when we set out to become one of North America's leading energy infrastructure companies. We've stuck to that plan, and it has generated significant shareholder value.
Over the past 18 years, we've invested approximately CAD 85 billion into high-quality, low-risk pipeline and power generation assets. Today, our CAD 94 billion portfolio generates about CAD 8 billion of EBITDA, with 95% of that EBITDA coming from rate-regulated assets or long-term contracted businesses. More importantly, I think over that same period, we've built more than just a group of assets. As you'll see throughout the day, we've built significant business platforms that give us multiple platforms for future growth. They include our Canadian, U.S., and Mexico natural gas pipeline businesses, our liquids pipeline business, and our energy business. Looking forward, we are currently proceeding with CAD 36 billion of commercially secured projects that are all expected to enter service between now and 2023. In addition to that CAD 36 billion of secured projects, we're advancing over CAD 20 billion of projects under development.
As demonstrated here recently by the new project announcements, we expect our existing asset footprint will generate significant additional organic growth opportunities in the years ahead. Simply put, our strategy hasn't changed very much. Our strategy is to grow cash flow, earnings, and dividends per share by investing in high-quality, low-risk energy infrastructure assets across North America with a focus on generating superior risk-adjusted returns for our shareholders. We do understand the value that our shareholders place on a sustainable and growing dividend. Based on our positive outlook for the future, strong coverage ratios, we expect to grow the dividend at an annual rate of 8%-10% through 2021. Finally, over the last 20 years, we have maintained a disciplined and consistent approach to capital allocation. Our philosophy is simple.
It's to allocate our internally generated cash flow in a manner that strikes the balance between funding our growth and paying a sustainable and growing dividend to our shareholders. It has been driven by the belief that a self-funding model, along with a strong credit rating, will maximize shareholder value over the long term. This has provided us with the financial strength and flexibility to act at all points in the economic cycle. Today, we believe we offer compelling investment opportunities, given the quality and sustainability of the underlying businesses and the tangible outlook for growth and our financial strength and flexibility. With that brief overview, I'll take a few minutes here to delve into each of these key themes, starting with our approach to capital allocation.
This slide here illustrates our business model, and it's relatively straightforward and, as I said earlier, it's served us well for about 20 years. In fact, about 20 years ago in this room, I presented a slide that looked almost identical to this slide. The model is underpinned by a portfolio of critical energy infrastructure assets that generate stable, long-term cash flow streams. Our practice has been to take 40% of that cash flow and return to our shareholders in the form of a sustainable and growing dividend. The remaining 60% is being reinvested into complementary, low-risk energy infrastructure assets that have driven considerable growth for our shareholders. While others have continuously altered their approach to capital allocation, we have maintained this consistent approach, and it has served us well, generating double-digit average annual total shareholder returns since 2000.
The next three slides, I'll highlight where we've invested that and the resulting growth that's come from it. As you see from this slide, over the past 18 years, as I said, we've invested about CAD 85 billion into high-quality, low-risk pipeline and power assets. Through that investment, we have transformed this company from a Canadian-regulated natural gas pipeline company into a leading North American energy infrastructure company. Much of that growth has come through the expansion of our legacy assets. As you can see on this slide, it has been supplemented by opportunistic acquisitions. They've included an interest in Bruce Power in 2003, GTN in 2004, ANR in 2007, the Keystone Pipeline System over 2008 to 2010, and finally, the Columbia Pipeline and Columbia Pipeline Partners in 2016 and 2017.
Each of those acquisitions was transformational and expanded our North American footprint and has provided us with new platforms for continued long-term growth. As a result, today, as I said earlier, we have multiple platforms compared to one back in 2000. As evidenced by this slide, we've also had a long track record of living within our means. Historically, much of our growth has been organic, funded with internally generated cash flow. While we've issued significant equity over the last 18 years, it has always been tied to transformational activity that has created significant value for our shareholders. Evidence of that can be seen from this slide, where you can see significant growth in earnings and cash flow per share over that same period. As you can see on the chart, earnings have increased from approximately CAD 1 per share in 2000 to nearly CAD 4 per share today.
Cash flow per share has increased from approximately CAD 2.50 per share to more than CAD 7 per share today. That equates to an annual average growth rate in earnings and cash flow per share of approximately 7% since 2000. This growth in earnings and cash flow per share has allowed us to increase our common share dividend in each of the last 18 years from about CAD 0.80 to CAD 2.76 per day. Not so coincidentally, that represents a compound average growth rate of about 7%, similar to growth in earnings and cash flow and equates to a payment of more than CAD 16 billion to our common shareholders over that period of time.
We've maintained the strong coverage ratios while doing that with our current dividend representing about 75% Comparable Earnings and approximately 40% of internally generated cash flow, leaving us with the financial flexibility to continue to invest in our growing businesses. Our strong financial performance and growing dividend has in turn resulted in significant increases in share price from approximately CAD 10 in 2000 to approximately CAD 52 today. The combination of the growing dividend, along with that share price appreciation, has resulted in a 12% annual total shareholder return since 2000. That compares very favorably with the performance of the broader markets over the last 18 years. As highlighted in this slide, our 12% average annual return equates to a total return of about 775% over that period. In contrast, the TSX and S&P 500 generated returns of less than 200% in the same period.
As we think about it, not a bad outcome, particularly when you consider the low-risk nature of the businesses that we're running. Today, we have an enterprise value of about CAD 100 billion. We have our own interest in about 91,000 km or 56,000 mi of natural gas pipelines that move 25% or one-quarter of North American demand from the continent's two largest and most cost-competitive natural gas production basins to the premium markets in North America. We are also the largest provider of natural gas storage in North America, with 653 Bcf/d of capacity. In liquids, our Keystone Pipeline System delivers approximately 600,000 bpd , or about 20% of Western Canadian crude oil to export markets, to key refining areas in the U.S. Midwest, and Gulf Coast.
In energy, we have interest in about 11 power plants capable of producing 6,600 MW of electricity, enough to power 6 million homes. All of these assets are critical to the functioning of North America, and as I said, the demand for all of these systems continues to grow. That demand has translated into record financial results for 2018. For the first nine months of the year, Comparable Earnings per share were CAD 2.82 per share, an increase of 24%. Comparable EBITDA was CAD 6.1 billion, a 12% increase over last year.
Comparable Funds Generated from Operations was CAD 4.6 billion, an 11% increase over last year. These strong results clearly support our board of directors' decision earlier this year to increase our quarterly common share dividend to CAD 0.69 per share. That equates to CAD 2.76 per share on an annual basis and represents a 10.4% increase over our dividend in 2017.
In addition to delivering record financial results in 2018, we've also made significant progress on many other fronts that position us for continued success for many years to come. We successfully navigated U.S. tax reform and the 2018 FERC actions. We continued to advance CAD 36 billion of commercially secured projects, which includes CAD 12 billion of new projects that have been added to that backlog since the beginning of this year. We also placed approximately CAD 2.5 billion of new assets into service, including the Columbia Leach XPress system. By early next year, we expect another CAD 10 billion of those assets to enter service. We also advanced over CAD 20 billion of projects under development, including the Keystone XL system and the Bruce Power Life Extension program. Turning to our funding, we raised over CAD 8.1 billion across the capital spectrum on very compelling terms.
In addition to that, we completed the sale of our Cartier Wind assets and were reimbursed a significant portion of our development costs on the Coastal GasLink project, resulting in another CAD 1 billion of proceeds that will be used to fund our capital programs. As a result, our overall financial position remains very strong, and we are well-positioned to fund our sizable capital program and achieve our targeted credit metrics without the need for discrete common equity. In summary, I would say that it's been a very busy year for our team and I'm very pleased with the progress we've made, and I'm confident that we're well-positioned to continue to grow this company for many years to come. Looking forward, we remain focused on six key priorities, and again, these are the same priorities that you would've seen in our slides 20 years ago in this room.
The first is to ensure that our assets continue to operate safely and reliably every day. Second, we'll improve the profitability of our existing assets by maximizing the revenues and reducing the costs in each of our businesses. Third, we'll remain focused on executing our CAD 36 billion capital program on time, on budget. Fourth, we'll continue to advance our more than CAD 20 billion of projects that we have under development in a careful and cost-effective way. Fifth, we'll continue to cultivate a portfolio of low-risk organic growth projects that emanate from our existing footprint across North America. Finally, we'll continue to allocate our internally generated cash flow in a manner that allows us to maintain a strong balance sheet, fund our growth, and to support a sustainable and growing dividend.
Well, obviously, we're proud of the history of delivering significant returns to our shareholders, what we know in the days ahead, that our long-term success depends on our ability to balance profitability with the safety and social responsibility. Above all else, safety is our very top priority. We have a 65-year track record of reliable operations, we recognize that's probably not good enough and we need to continually improve. We believe at TransCanada that all safety incidents are preventable and will not be satisfied until we reach our goal of zero incidents. That is why we're spending about CAD 1.5 billion a year on pipeline integrity and facility maintenance, We continue to be an industry leader when it comes to supporting research and development on things like pipeline integrity and leak detection.
We also have a long history of collaborating with stakeholders and communities across the geographies in which we work. We treat all of our landowners with fairness and respect, which enables us to create long-term relationships with the thousands of landowners that we have today. Understanding stakeholder issues and engaging with local officials and landowners to identify how to best address their unique concerns is critical to our success. The most near-term example we have is our approach that we used on the Coastal GasLink project. From the time we announced that project in 2012, we engaged with communities early, often, ultimately resulting in agreements with 20 elected Indigenous bands along that route and setting us up for success.
While our customers will always look for competitively priced services, they're becoming more selective in choosing a partner whose values around safety, environmental stewardship, and respect for others is aligned with theirs, and clearly, we're seeing evidence of that. We believe that our world-class capabilities, operating practices, project execution, strong track record of working collaboratively with stakeholders, and a strong financial position means that we're well-positioned to be the partner of choice as our customers try to move forward their objectives. Evidence of that can be seen on this slide, and I've talked about this earlier today. We are advancing CAD 36 billion of commercially secured projects that will expand and extend our footprint across North America. Our growth program includes a series of projects in jurisdictions where we see relatively normal course permitting and construction hurdles.
That includes CAD 31 billion of natural gas pipeline expansions in Canada, the U.S., and Mexico, CAD 4 billion of power projects, including the Napanee project here in Ontario, as well as the Bruce Power Life Extension program, and about CAD 1 billion of liquids and other projects. To date, we've invested about CAD 13 billion into that program, with the remainder to be spent over the next five years. Notably, each of these projects is underpinned by a long-term contract or a cost-of-service business model, giving us strong visibility to the sustainable growth in earnings and cash flow as they enter service between now and 2023. This slide highlights the significant growth in EBITDA that is expected to result as we advance that secured capital program. As you can see on this chart, Comparable EBITDA is expected to grow from about CAD 5.9 billion in 2015 to approximately CAD 10 billion in 2021.
That equates to a compound average annual growth rate of about 9%. Just as important, I think, as the magnitude of the growth is the quality of the growth. Over 95% of that EBITDA will be coming from rate-regulated assets or long-term contracted businesses. Based on the confidence and visibility we have in our business plans, we expect to grow our common share dividend at an average annual rate of 8%-10% through 2021. As I've said many times, that 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 maintain a strong balance sheet and continue to grow and continue to prudently fund our capital programs.
In addition to our CAD 36 billion portfolio of commercially secured projects, we continue to advance about CAD 20 billion of projects under development. They include the Keystone XL Pipeline project and, as I said, the Bruce Power Life Extension program. Paul Miller, Tracy Robinson, Karl Johannson will provide you an update on all of those projects later this morning. As we said, proceeding with either or any of those initiatives would create significant additional shareholder value and position us for continued growth. Looking forward in our industry, we expect the global demand for energy will continue to rise. This will require billions of dollars of additional investment in energy infrastructure, and I believe we are well-positioned to capture a sizable share of that growth. As you can see on this slide, North American gas demand is expected to grow to about 130 Bcf/d by 2030.
Much of that is driven by industrial demand, natural gas-fired generation facilities, and LNG exports. Our extensive natural gas pipeline network is positioned well to meet that demand by connecting growing supply from the Western Canadian Sedimentary Basin and the Appalachian Basin, which are the continent's two largest and lowest-cost supply sources to the premium markets. In our liquids business, crude oil supply is expected to grow, and that does include growth in heavy oil production in Western Canada. We and our shippers continue to believe that the U.S. Gulf Coast is the largest and most attractive market for that growing heavy production, and that the Keystone XL Pipeline is the safest and most efficient, environmentally sound way to move that production to that market.
Finally, on the power front, new generation capacity will be needed to meet growing demand, to replace aging infrastructure, and facilitate a shift to a less carbon-intensive energy mix. Renewables will play a role in that. However, given the abundant supply of competitively priced natural gas, it is very likely that natural gas-fired generation will also play a role in meeting that demand. With the potential for gas-fired additions, we see replacements in Alberta, Ontario, and Mexico, and we are well-positioned to capture those kinds of opportunities along our asset footprint. At the same time, we have expertise to participate in new forms of generation, as you've seen us done in the past, in wind and solar, as well as the attractive nuclear refurbishments at Bruce Power.
In summary, we believe the long-term fundamentals continue to create tremendous opportunities to connect growing natural gas and crude oil supplies to markets and to replace aging infrastructure as North America shifts to a less carbon-intensive energy mix. The scale and scope of our asset footprint, along with our technical expertise, financial strength, and approach to responsible development, I can tell you, are real competitive advantages. Today, we own multiple platforms for growth, and they include the NGTL system, which is a 24,000-km pipeline network that moves about 12 Bcf /d or about 75% of the gas that moves in the Western Sedimentary Basin through an extensive and cost-competitive network. The mainline is a 14,000-km pipeline that provides a critical link between that growing supply and key markets in Eastern Canada, the U.S. Midwest, and Northeast.
The Columbia Gas system is an 11,000-mi pipeline network that sits on top of the Appalachian Basin, as you know, that's the continent's largest source of natural gas supply. Our broader U.S. gas pipeline network also includes Columbia Gulf system, the ANR system, the GLGT system, Northern Border, Iroquois, Portland, and the GTN system, which all link both the Appalachian supply basin and the Western Sedimentary supply basin to key markets across the U.S. Finally, in Mexico, our natural gas pipeline network is forming the backbone of that country's natural gas infrastructure. Turning to liquids, Keystone moves, as I said, approximately 600,000 bpd of Canadian exports to U.S. Midwest and Gulf Coast refining markets. In energy, Bruce Power provides the platform. It's the world's largest nuclear facility, generates about 6,400 MW of emissionless power, and about 30% of Ontario's daily needs.
These growth platforms, as you've seen in my overview, provide us with line of sight to over CAD 50 billion of organic growth opportunities and an enviable position to continue to grow this company. As a result, we're highly confident that we will add to our industry-leading portfolio of commercially secured projects in the years ahead. Before I conclude and pass it on to the team to give you the details here, I wanted to make a few comments on our executive leadership team. You've seen these faces before, and while we have great assets, I can tell you they don't produce results without significant human ingenuity and expertise. Now I'm obviously very biased in my view. In my 35 or so years of being in this business, I believe we've assembled the very best talent in the industry, starting with our executive team.
Many of these faces are very familiar with you today. Tracy, Stan, Karl, Paul, and Don are all here today to provide you with an update of their respective areas of responsibility. But we have others, Christine, Dean, and François, along with several other senior vice presidents and vice presidents with us today, and I'd encourage you to continue to ask them questions at the breaks or over lunch. That team is supported by about 7,500 talented employees in Canada, the U.S., and Mexico that are expert in their fields, and they work tirelessly to build safe and operate a blue-chip portfolio of long-life infrastructure assets on behalf of our shareholders. I truly believe it's their efforts that will drive the success of our business in years ahead. So that concludes my overview.
I'll be available for questions later in the day, but I'd like to turn it over now to Tracy, Stan, and Karl. They'll provide you an overview of our North American natural gas pipeline business and where that's headed. Turn back to them.
Sorry. Thanks, Russ. As Russ indicated, Tracy Robinson, Stan Chapman, and Karl Johannson will join us here now. Given obviously the integrated nature of our natural gas pipeline business, I think they'll all start with some introductory comments with their respective areas of responsibility, and then we'll open it up to questions on the broader natural gas platform. Tracy.
Good morning. I'm very pleased to be here with you today to talk a little bit about our great Canadian natural gas franchise. I'm going to set a couple of context comments on the fundamentals of our natural gas business that'll provide kind of an overlay for all of us. I'll dig a little deeper into our Canadian business and then hand it over to Stan and to Karl, who will speak more specifically about our business in the U.S. and Mexico. First, the fundamentals. To put our natural gas pipeline network into perspective, our assets are positioned on top of two of the most prolific basins in North America, the WCSB and the Appalachian Basin.
We have more than 90,000 km of pipeline that connect the supply in those basins to important markets across the continent, including some very healthy local markets in Alberta and Northeast B.C., and increasingly some jumping-off points into the international markets as well. That, with our storage capability, that infrastructure moves about 25% of the gas that is consumed in this continent every day. The importance of this infrastructure is underscored if you consider the growth in the basin reserves over the last 10 years. On this map, the smaller blue circles represent the reserve estimates in 2007. The green circles represent estimates for the reserves in those same basins 10 years later in 2017. Now you'll note that the reserves have increased in all of the basins with the advent of shale.
In fact, we have enough natural gas in North America now to supply more than 100 years of our own demand. The most dramatic increases in the reserves, of course, have been in the WCSB and the Appalachian. Both of those basins now have about 1,000 TCF or more in the case of the Appalachian in reserves. There's more gas here than can be consumed in North America. This means that all of that supply must compete for share in each of the markets. To be successful, it's critical that production is low cost and that we have cost-effective and reliable transportation to markets, and that is the focus of our business. The primary role, of course, of natural gas supply in North America is first to feed our demands, our own consumption in North America. This consumption is growing.
In 2018, demand on this continent will average about 100 Bcf /d . As we look forward, we see growth driven largely from the industrial sector and from power generation. This growth in these areas will be driven to the tune of about 20 Bcf of incremental demand by 2035. Additionally, our ability to respond to gas needs globally through competitive LNG projects, which has already begun, is expected to add another 20 Bcf by 2035. That's growth of about 40% in demand over the next 15- 20 years, and it provides our industry with the opportunity to develop a network that can handle an incremental 40 Bcf/d over this time period. Now, the basins in North America can clearly respond to this, and two that are very well-positioned are the WCSB and the Appalachian Basin.
Our infrastructure is in the right place in order to facilitate this growth. With that framework, let's talk a little bit about the Canadian natural gas pipelines business. In this business, we're focused on the growth of the WCSB and getting that supply competitively into every market. We have three systems within the Canadian network. With the NGTL system, which sits on top of the WCSB in Alberta and British Columbia, it effectively serves the breadth of that basin through a network of more than 1,100 receipt points. More than 12.3 Bcf /d comes into the basin. That's more than 75% of the basin's volume. Once you're in, you're in a trading hub that's large and liquid at NIT, or you can deliver into a sizable local market through about 300 delivery points.
That local market right now averages about 5.5 Bcf /d and it peaks at over 7 Bcf/d in the wintertime. This system also provides producers with options to connect to any number of markets across the continent through our downstream Canadian and U.S. pipes. You can reach California and the Pacific Northwest through the GTN system. You can reach the Midwest through Northern Border, and you can have access to the mainline. Now, the Canadian Mainline is an important part of this equation. It extends from Empress, where it connects to the NGTL system, down to Emerson, where you can go south through Great Lakes or proceed down the Mainline north of the lakes, and through those two paths, serve Eastern Canada and the Northeast U.S.
This system transports actually north of seven now, nearly almost 8 Bcf /d , and provides that important link between the basin and our eastern markets. We have what will be our third and our newest part of the Canadian network when we complete the construction of the Coastal GasLink. In October of this year, LNG Canada and their five joint venture partners took a positive FID on their LNG terminal in Kitimat. With that, we'll be building the Coastal GasLink pipeline from a point in Dawson Creek in Northeast British Columbia to Kitimat, BC. It will provide initially 2.1 Bcf /d of gas to that facility, and we will begin construction of this pipeline in January of next year.
Our team has made some meaningful progress with shippers over the last year in leveraging this Canadian network and our connectivity to the U.S. network to the benefit of both the basin and the markets it serves. We've done that in three ways. We've increased the utilization of our existing pipe system to facilitate supply that wants to get to market. We've done this by tweaking the system where we're a little tight in capacity to increase flows, and we've done it by offering services on the parts of our network where we do have capacity, notably the Western Mainline, to incent volume to move out of the basin and down into markets. Secondly, we have worked to create certainty through our regulatory process on tools for our shippers and our own returns.
We, earlier this year, reached a settlement with the NGTL shippers for revenue requirement for that system for 2018 and 2019. We have been through a process with the NEB for tools on the Mainline between 2018 and 2020. We are awaiting a decision from them, and we hope to receive that prior to year-end here. Finally, the teams worked effectively with industry to put plans in place to expand our system to drive that next level of flows from the basin into market. That includes a CAD 9.1 billion expansion of the NGTL system, a CAD 200 million of expansion work in the Mainline in the east, and a CAD 6.2 billion build for the Coastal GasLink project. It's been a very good year.
We've been working in the same direction for a number of years now, we start to see this in the flows that are moving through our systems. We've had some great success in increasing our volume. Since 2013, our flows on the NGTL system are up by more than 22%, from about 10 Bcf to 12.3 Bcf on average. On the Mainline, the impact's been even more dramatic now. On the Western Mainline, this was an asset that we thought would fall below 1 Bcf /d at one point in time. Since 2013, flows on the Western Mainline have increased by more than 50%, and more importantly, the firm contracts on that system have more than doubled. Pipeline utilizations have increased substantially. The demand on our system is very strong, and there's more that we can do here.
We'll talk about what our plans are now for each of our systems. First, the NGTL system. That large resource in the WCSB has some of the most economic gas in North America, particularly as you get up into the Montney region. The challenge for the industry and for us is to get that gas out of the Montney and into market. Market's critical. We've been working on collecting more receipts into the NGTL system, more supply. Importantly, we're connecting that supply to an additional 3.2 Bcf of market access over the next few years. By 2022, if you look at the intrabasin market, we're going to increase our delivery capability within Alberta by 1.3 Bcf /d .
This is being driven by that transition of coal to gas in the power sector, by the growth of the petrochemical market in Alberta, and by the oil sands as they transition to lower emission fuel supplies. That market right now is about 5.5 Bcf /d on average. The addition of the 1.3 Bcf will take it to north of 6.5 Bcf, 6.8 Bcf, actually. Over that same time period, we have agreements to add another 1.3 Bcf of incremental capacity for delivery of volumes to Eastgate. That's where they'll connect with the Mainline system. That will bring the Eastgate capacity to 5.8 Bcf /d . We'll add another 600 million cubic feet a day to our Westpass capabilities for delivery to GTN.
It's going to take the Westpass capability of 3 Bcf /d , 2.8 Bcf of which will go down to GTN, and the other 200 Bcf we connect with other pipelines in Southeast B.C. These expansions are fully contracted, and they form the basis for our CAD 9.1 billion capital program on the NGTL system. This is a very significant investment in this basin, and one that will increase our average investment base by about CAD 6 billion by 2021 to reach a level over CAD 15 billion. There's more delivery capacity coming to the basin. We've all been waiting, or had been waiting, for that positive FID on LNG Canada's facility in Kitimat. In October, we got it. We'll be building a CAD 6.2 billion Coastal GasLink pipeline to provide gas to that facility.
CGL will provide the first direct access to the LNG Canada facility to world markets for WCSB gas, we are very proud and very excited to be part of that project. The Coastal GasLink is a 670 km of 48-inch pipe that will provide initially 2.1 Bcf /d of the basin's gas to the LNG facility. That pipe is expandable to 5 Bcf /d with the addition of some compression. We are in possession of all the permits that we require to build CGL, we have the support of the communities and the First Nations along the right of way. In fact, as you heard Russ talk about, we have agreements with all 20 of the elected First Nations along that pipe path, we'll begin construction in January.
You have the 2.1 Bcf in incremental delivery capacity out of the basin for CGL, 3.2 Bcf on incremental market access from the NGTL system. That's 5.3 Bcf of incremental delivery capability from this basin by 2022, 2023. That's a very strong support for the increase in production that we want to see out of the WCSB. Finally, we have the Mainline. The Mainline is that path to get the WCSB volumes into the eastern markets. The Western Mainline has become, in this market, a strategic asset. Pipe in the ground with capacity is very valuable. We're working to make the Western Mainline an effective conduit to the markets in the East, Northeast, and the Mid-Continent. The more competitive that Western Mainline becomes, the shorter the distance between the WCSB and those markets.
We've increased flows in the Western Mainline by 50% in the last five years, we have opportunity to do more. You'll recall in 2017, we completed a long-term fixed price agreement with a number of producers in Alberta. This was an important step because it was the first time in about 20 years that producers had stepped out to take mainline transportation. That deal has served them very well. We've recently closed an open season for another LTSP. This one is a pull from the eastern markets. It's an LTSP from Empress to North Bay Junction. One has matching contracts from North Bay Junction into the Eastern Triangle, and in some cases, through the Triangle to connect a downstream with our U.S. pipes. We've had a very strong response on this open season, more than 500 million cubic feet a day.
We're just finalizing these contracts now, in a couple of weeks, we'll know exactly what those volumes will be. This service uses existing capacity on the Western Mainline to North Bay. East of North Bay, depending on where that volume goes, it will use up our existing capacity, it will trigger a small expansion of the Eastern Mainline and potentially an expansion in Stan's assets in the Northeast U.S. You'll hear him talk about that. This is in addition to the CAD 200 million expansion we have underway right now to facilitate a growth in volume down to the PNGTS pipe in the Northeast. Important feature of this open season, we have the first time ever, the Maritimes market coming into Empress, all the way back to Empress to buy transport on the mainline. This is the kinds of things that we want to see.
We want to pull as much as we can from the WCSB to fulfill the increase in demand in the East. We do have a second season, open season, open now to facilitate demand from Dawn into the Eastern Triangle. That open season closes prior to the end of this year. We do expect the demand to increase in the East. We have growth expected in Northeast U.S. We know the Maritime needs some more volumes as their offshore supply diminishes, there are a number of dialogues underway in the potential for LNG exports off Canada's east coast. This demand makes that Western Mainline very critical to us. The rate base, the average investment base in the Western Mainline, is declining as that asset depreciates, but it's becoming more valuable as it does that.
The investment base on the Eastern Triangle is increasing as we invest in that infrastructure. You see the two of those offset each other. Overall, a very good story. Let's sum up the capital program on the Canadian pipes. We have CAD 200 million underway on the mainline in Eastern Canada to be completed by 2023. We have that CAD 9.1 billion expansion of the NGTL system to be fully in service by 2022. The Coastal GasLink, CAD 6.2 billion project, will be complete and in service by 2023. Our maintenance capital is settling in at about CAD 600 million a year. I'll remind you that financially, that capital is treated the same in the Canadian pipes as expansion capital. It receives a return of and on capital immediately. That's a total of CAD 17.3 billion in secured capital expansion and maintenance capital.
You've seen my colleagues today discuss their financial performance in terms of EBITDA. In the Canadian regulated business, the items that you need to adjust in order to get to EBITDA are actually mostly flow through into toll. As a result, the appropriate financial metric for this business is net income. Net income is tied pretty closely to investment base and to our capital program. That program is going to drive a CAGR and investment base of about 8% between 2015 and 2021 to more than CAD 19 billion. Net income will go by that same pace from about CAD 500 million in 2015 to more than CAD 800 million by 2021. It's important to note that that growth is fully secured by contractual commitments.
I also want to mention that from a cash perspective, we pull more than CAD 1 billion a year in depreciation out of the Canadian pipe system. As we look forward, our priorities are clear. We will execute on what is a very substantial capital program. What I mean by that is we will bring this in safely on time and on budget. We'll continue our efforts to maximize the value of our existing pipe network in a manner that serves the interest both of our shippers and ourselves. Importantly, we have an effort ahead of us in the restructuring of the Mainline system post-2020, when we will separate the Eastern Triangle from the Western Mainline and provides us with an ability to think about how to use those assets a little bit differently.
With the industry, we'll continue to facilitate the growth of the basin by driving expansion to our system to serve all markets in Canada, the Intra-Alberta Basin, across the continent through our downstream pipes, and of course, globally through LNG. Let me finish where I started. The Canadian network is situated on top of a very important basin, one of the most prolific in North America. We have a strong team that's done a great job in leveraging both our Canadian and U.S. network to drive benefits to the basin, to our shippers, and to our bottom line and our financial results. Very proud of the team and the work that they've done and the work they have coming up. With that, I'm going to hand the podium over to Stan Chapman and our U.S. business.
Thank you, Tracy, good morning, everybody. I appreciate the opportunity to share my enthusiasm with you about the U.S. business and our company overall. My hope is that by the end of my remarks, you'll take away three things. One is that demand for our assets remains strong. Two, that our revenues are underpinned by long-term take-or-pay contracts. Three, that future growth opportunities are supported by sound market fundamentals. What we do is relatively straightforward. We deliver the natural gas that millions of individuals rely on every day to live their lives and run their businesses. To do that, we lean heavily on our portfolio of 13 FERC-regulated pipelines, which spans across 31,000 mi and includes operations in over 40 states. These pipelines are either wholly owned or in some cases, partially owned via our ownership in TC PipeLines, LP or through various other joint ventures.
In conjunction with our best-in-class pipeline network, we also operate about 535 Bcf of natural gas storage, as well as a non-regulated midstream business across Northern Appalachia. Collectively, we serve about 25% of the natural gas demand across the United States, we do that by linking two of the best and lowest cost supply basins, the WCSB and the Appalachian Basin, to the fastest-growing demand centers in the United States. I'm glad to report that the natural gas resource base across the United States is as strong as ever. Technically recoverable resources across the U.S. are estimated to be over 3,100 trillion cubic feet. To put that in perspective for you, at current consumption levels, that's over a 100-year supply.
More than a third of these resources sit in the Appalachian Basin, home to the Marcellus and the Utica, which rests right underneath our Columbia Gas and our Columbia Midstream systems. We continue to see strong production of these resources, which total production across the U.S. is expected to grow at an annual rate of about 3% between now and 2017. We like to think of our assets, such as GTN and Northern Border and Great Lakes, as being a big catcher's mitt to catch growing WCSB production, which is expected to grow annually by about 4% and reach 23 Bcf /d by 2017. While the hypergrowth out of Marcellus and the Utica is expected to moderate, the outlook for future growth still remains strong as production is expected to grow to 44 Bcf /d by 2027, which is an annual growth rate of about 6%.
This continued production out of the Marcellus is quite impressive given its size relative to smaller but growing basins like the Permian, which actually are growing at a similar rate. Shifting over to demand, we see that demand growth lags that of supply slightly, but still grows at a relatively robust 2.8%. Demand growth will primarily be led by LNG exports, which between now and 2027 grow at a rate of 14% per year and are expected to increase to 12 Bcf /d by 2027. Additionally, exports to Mexico are expected to increase by 5% per year, both the power and industrial sectors are expected to grow at about 2% per year. Overall, 2018 was a very solid year for our business unit.
In addition to focusing on providing safe and reliable service for our customers, one of our primary objectives was to close out and place in service our project growth backlog, I'm pleased to report that we're on track to do just that. Just over CAD 2 billion of capital was placed in service during the first quarter of the year when our Leach XPress and Cameron Access projects went live. During the month of October, we very quietly placed another CAD 650 million of capital in service, which was predominantly linked to our modernization program and the west path of our WB XPress project. Subject to FERC authorization, in the next few days, we'll close out our WB XPress project by placing the east path in service, which is another CAD 700 million capital investment.
Lastly, we expect to be in a position to flow gas on our CAD 3 billion Mountaineer XPress and our CAD 600 million Gulf XPress projects at year-end or shortly thereafter. As an aside, the pictures on this slide are construction photos of our Mountaineer XPress and WB XPress projects. While they don't do it proper justice, hopefully you will get some sense of the terrain and the challenges that we face in building through the Appalachian Mountains. This is something that TransCanada does quite well, leveraging on its prior experiences with projects in Western Canada and Mexico. Combined, these projects represent more than CAD 7 billion of capital investments that will be placed in service and will start generating cash flow for the company.
2018 also marked the successful close out of the initial five-year, CAD 1.5 billion Modernization I program on the Columbia Gas system. We immediately began work on the three-year, CAD 1.1 million Modernization II program. We are successfully collaborating with our customers to address FERC actions related to U.S. tax reform. To date, we have reached settlements with our GTN and Hardy Storage customers, which are currently pending FERC approval. We will continue to make our 501 filings with FERC as applicable. As we have previously stated, we do not expect this to have a material impact on our earnings. Demand for our assets is robust as ever. We are on track to achieve record EBITDA levels.
Earlier this year, we set a new peak day sendout record with over 30 Bcf sent out across all of our pipelines. Our average day load factor has now increased to almost 70%. More importantly, 95% of our revenues continue to be supported by long-term take-or-pay contracts. Lastly, our business development team continues to pursue additional growth opportunities, which I will highlight in further detail in a few slides. As production growth continues and new projects come online, we are beginning to see changes in flow patterns across our system. Most notably now that our Leach XPress and Rayne XPress projects are in service, the turnaround of the Columbia Gulf system has largely been completed as we are routinely flowing over 1 Bcf /d south towards the Gulf Coast.
Given that most of our historical growth projects were supply push in nature, we are now going to turn our focus to adding new demand centers to our pipes. In that regard, our Canadian and U.S. marketing teams are acting in unison to ensure that growing WCSB supply has access to U.S. markets. We are beginning to experience the benefits of this as demand for our assets are as strong as ever. For example, annual average load factors on GTN have increased by 30% since 2015. The system is essentially fully subscribed come 2020. Increased usage on the Great Lakes system is even more dramatic, with annual average load factors having increased by over 173% since 2015. As I mentioned previously, the fastest-growing source of demand in the U.S. is tied to LNG exports. You will see that our pipelines are strategically located to serve them.
For example, if you look at this map and you start on the upper West Coast, Tracy has already talked to you about LNG Canada and Coastal GasLink. Moving clockwise to the Pacific Northwest, Jordan Cove LNG would require supply to be sourced off an expanded GTN system. Further south, our North Baja Pipeline can be economically expanded and is well-positioned to serve Costa Azul. In the Gulf Coast, our ANR and Columbia Gulf pipelines are uniquely situated to serve several existing and proposed LNG facilities. We missed Elba Island. Can't get them all. Cove Point is already served in part by Columbia Gas and our WB XPress project. Lastly, our PNGTS and Canadian Mainline systems provide key connectivity to serve any East Coast Canadian LNG terminals that may develop.
As you can see, our pipeline footprint provides for unparalleled access to most of the existing or proposed LNG terminals across the continent and sets us up nicely for future growth opportunities. I mentioned earlier that we are largely winding down and placing in service our historical growth project portfolio, I wanted to quantify the impact of that for you and put it in perspective. CAD 7.1 billion of the CAD 7.4 billion portfolio is either already in service or is on track to be placed in service within the next few months. Based on our current capital forecast, our portfolio is on track to be constructed at a 7.4x multiple of CapEx to EBITDA. Furthermore, you could think of this portfolio as generating over CAD 1 billion in incremental EBITDA and generating an after-tax unlevered return in the upper 10% range.
Given the complexities of building new projects in today's environment brought on by legal and regulatory challenges, compounded further by an extremely tight labor market and the wettest weather in the past 124 years across our construction footprint, I'm really proud of our team's accomplishments. In addition, our three-year CAD 1.1 billion Modernization II program is now underway and includes a mechanism for us to recover this investment annually as capital is deployed. Maintenance capital, which cumulatively is CAD 2 billion from 2019 through 2021, due in large part to additional integrity and reliability work that needs to be done to support the increased demand we're seeing across our pipelines, will continue to be recoverable as we file future rate cases.
Post 2021, when the majority of this incremental reliability and integrity work is completed, we expect our annual maintenance capital to moderate down to a run rate of about CAD 600 million per year. In the aggregate, you can see that this represents about CAD 10.5 billion of capital investments, of which approximately 60% has already been spent and is or soon will be generating cash flow. As shown on the attached graph, our U.S. gas business has undergone transformational change, brought on in large part by the Columbia acquisition in 2016. 2017 EBITDA of just under CAD 2 billion represents the first full year of the Columbia acquisition. YoY EBITDA between 2017 and 2018 shows the impact predominantly of our Leach XPress and Rayne XPress projects being placed in service, as EBITDA for the first nine months of this year approximates that for all of 2017.
More importantly, using 2017 as an anchor, we're on track to generate strong compounded annual growth rate of 10.5% between now and 2021. This growth is generated by our resilient base business, which includes long-dated take-or-pay contracts with average durations of 11 and nine years on our two flagship pipelines, ANR and Columbia Gas, respectively, as well as the CAD 1 billion in new EBITDA generated by our growth projects that I previously highlighted. Going forward, our game plan is simple. It's more of the same. For the remainder of this year and the beginning of next, we'll focus on closing out the balance of our growth projects and safely and reliably placing them in service. Now and through 2019, Tracy and Karl and I will continue to challenge our collective marketing teams to take advantage of cross-border synergies.
Also in 2019, we'll finalize our customer negotiations and settlements related to U.S. tax reform. We'll begin conversations with our Columbia Gas customers related to a Modernization III program. We'll begin preparation for ANR's next rate settlement proceedings. At the same time, we'll be diligently working on the next wave of new growth projects. As you can see, we have projects in various stages of development across virtually all of our pipelines. Some of these are cross-border opportunities, some of them are unique to the U.S., and some are owned by TC PipeLines, LP. Now, given our time constraints, I'm not going to go into the details of each of these projects, but I will tell you that we'll be taking the second project listed herein, our Louisiana XPress project, to our board for approval towards the end of this month.
In fact, some of you may have seen that we launched a binding open season for this project just yesterday. Consistent with the strategy that I've laid out for you today, this CAD 400 million capital project is a further expansion of our Columbia Gulf system to serve a credible Gulf Coast LNG export facility, and it's underpinned by long-term take-or-pay contracts. With that said, I hope you now have a better appreciation and a sense of enthusiasm for our U.S. gas business and how it fits into the overall success of TransCanada. Thank you for your attention. I'll turn the podium over to Karl, and I'll be around to answer any questions you have afterwards.
Good morning, everybody. It's nice to be here and see everybody again this year. It's always nice to get up here and talk a little bit about the businesses that we've been running over the last year, and it's my pleasure this year to talk about our Mexican business and the status of them. With that, if I put a picture up here first, I just wanted to give people a feel for some of the work we're doing down in Mexico. This is the staging area for one of the onshore-offshore interconnects for the Sur de Texas Pipeline. If you recall, the Sur de Texas Pipeline is about an 800-km subsea pipeline that's going really from Brownsville, Texas, right through to Tuxpan in Mexico. And this is actually at Altamira, kind of the midpoint where we have the compression facilities.
This is the staging area for those compression facilities. We have two pipes, one coming in and one coming out, so to speak, into the compression facilities. This is a man-made island that we've put into. We had to drill a micro tunnel, 2.5 km micro tunnel here, to get underneath the mangroves, to get underneath the beaches, which was a turtle hatchery, and to get underneath the coral reef. We built a 2.5 km micro tunnel, about 10 ft in diameter, to move the pipeline through so that we would have a minimal impact on the environment here. What you see here is really a string of pipelines. There's two pipelines put together. We're going to push two pipelines through the micro tunnel at the same time.
There'll be seven of these strings that we ultimately weld up and we push through to interconnect it. It just gives you an idea of some of the scope and the scale of what we're doing. This is 42-inch pipe, about an inch and a half thick in that area, and it's quite a job doing a 2.5 km tunnel underneath the ocean sea beds in order to make it work. I wanted to start just to talk a little bit about Mexico's supply and demand. The establishment of supply and demand in Mexico is still more what I'd say art than science. You have to understand, the actual market for natural gas doesn't have a long history to it yet. It still is in its infancy.
When we take a look at the supply part of this, or let's take a look at the demand part of this, that industrial bar really is still in development. The industrials in Mexico still use a lot of fuel oil, a lot of LP products. They don't use natural gas. Traditionally, natural gas has not been that reliable of a fuel for the industrials. Therein lies the key to kind of some of our growth strategies, which I'll talk about in a few minutes. We're talking about a market that's going to be, we believe, in the next 10 years or so, about 10.7 Bcf /d . We believe there's some upside to that because we haven't baked in all the industrial opportunities yet.
Certainly, this is going to be a good demand not only for our pipeline system, but also for North American gas going from the U.S. into Mexico. I think everybody's looking forward to supplying this additional demand. I think it is, when we talk about trade stories in North America, this is one of the solutions to balance the trade issues between the U.S., Mexico, and quite frankly, Canada, as we start moving gas from Canada to the U.S. and the U.S. and Mexico. You saw those graphs earlier from Russ' and Tracy's talks about our systems. Really, with the completion of the Sur de Texas-Tuxpan Pipeline, which I'll show you in a moment, we can literally move a unit of gas right from Northern Alberta, Northeast B.C., all the way down to Mexico City now. We're getting very close to being a completely integrated market here.
What are our accomplishments over this last year? We are advancing our last three projects, Surtexas, Tuxpan-Tula, and Villa de Reyes, about a little less than $3 billion U.S. in projects. They are all advancing. The completion of Surtexas is scheduled, really, we'll be calling for gas in December. We have one more interconnect to do, which is the one I just showed you on the picture. That kind of relies on some calm seas, which we actually, quite frankly, haven't seen calm seas for the last couple of weeks, so we are waiting for the seas to calm down a little bit. Once we get that interconnection done, we will be going right to commissioning. I would expect that we'll be calling for gas in December sometime. We're looking forward to that. That'll be the last kind of tricky part of this particular project.
The Topolobampo was in full in service this year. If you recall, we had some issues with some Aboriginal concerns of our pipeline running, so we routed around that community. We got it in service this year, so the Topolobampo now is flowing gas and completing service. I would say for our other projects, the Tuxpan-Tula, Villa de Reyes, they're both operating under force majeure events that have been recognized by the CFE, our customer. The Tuxpan-Tula's force majeure event is for an Aboriginal community that we're having difficulty getting our consultations done, or the government's having difficulty getting their consultations done with that community. That pipeline is pretty much done except for that. We've actually demobilized that pipeline, so we're just waiting for that consultation to be completed. The Villa de Reyes Pipeline is progressing well. We have run into 90 archaeological sites on that route.
I can assure you the first archaeological site is pretty exciting. We get to see some pretty new stuff. The 90th is not so much. We've discovered a lot of new settlements and new foundations and whatnot. The good news is it doesn't stop us from construction. The government has to go through the process to map out the archaeological site, and then they let us go around it. It's just delaying us. Both of these projects, I would say, are both under force majeure with the CFE. Both are recognized as outside of our control, and we are receiving our regular capacity payments on these facilities as if they were operating. I would say for the Surtexas, it's the same thing on force majeure events.
As of November 1st, we are getting paid our full capacity payment for them, even though we won't be in service till late December or in January. What is our position? This is the map that I like to show. We have four pipelines operating right now. We have three under construction. When you take a look at it, and Russ talked about platforms for growth a little earlier. I mean, that's the way I view Mexico as well. We've managed to get what I consider very solid platforms, almost franchise-like businesses, both on the West Coast of Mexico and down in the central part of Mexico. These are areas that we kind of targeted when we did it. Up in northern Mexico, where all the interconnections are, there was lots of U.S. firms there, lots of infrastructure there that we didn't have own or have control of.
We decided to concentrate where the population was, and this is where the population and industry are. When you take a look at the central part of Mexico, approximately 60% of the population and GDP are from there. The western side is a very, very highly industrialized part of the country. These are the regions that we're going to grow and enhance. All these facilities are underpinned by U.S. dollar-denominated long-term contracts. I think they're well-positioned to not only follow the growth in the Mexico economy and industry, but actually to plow some new ground on natural gas in Mexico. The industry here, as I said, does not generally use gas. I think our marketing of our next little well is going to be set up to try and get them to convert from the fuel oils and LP products they use right now to natural gas.
You can just see from both these graphs on the western side and the central Mexico, we tried to parse out here what type of industries are there, what type our targets are for. These are going to be all bread and butter for us. It's going to take a while to accumulate them all. We're going to have to build connections to them. We're going to have to convince them to get off of the fuels and whatnot. There's going to be a compelling economic story for them. Once we get them, we'll have them for a very long time. I'd like to remind everybody that even though the CFE has backstopped all these pipelines, all seven pipelines are backstopped by the CFE, we get a good return by the CFE contracts itself.
Every time we convert one of these industrials to natural gas who uses our system, we get to keep all that revenue fully for ourselves. There's a big incentive for us to market hard for these industrials and get this gas based on our system. The Comparable EBITDA for our business. I think the graph kind of says it all. We're going to go from a very small $100+ million back in 2015. We're going to have a 20% kicker on 2021, about $550 million U.S. dollar kind of business. That's just with these projects right now coming in service. That's without, we haven't put any enhancements through marketing to industrials. I would say this is not the end of the growth in Mexico. As you can see, there is still some gaps in that map.
The CFE has slowed things down right now on the new project for a couple of reasons. Number one, everything with land issues that they've had with the aboriginal consultations, even the power plants have been a little bit delayed. They have slowed it down. We'll have the infrastructure catch up. Once the infrastructure catches up, we fully expect more projects to come along in Mexico. I firmly believe we will be seeing things like the Mazatlán, the Guadalajara line come one day, and then there'll be other instances where they're going to fill in their grid. We've seen a very good solid position in growing market here. I don't think that's the end for the big inch pipe construction. But from our perspective, we're going to hopefully continue to grow it through our marketing and industrial activities at the same time.
What is our key areas for the future? Obviously, we have to execute our capital program. We have to figure out Tuxpan-Tula . It's nice that we're getting paid, but we have to figure out how to get around this aboriginal group. Either the government's got to finish their consultation, or we got to figure out a way to put that in service. It's nice that we're being paid for it and all that, but we want to see gas flowing in our systems. Tuxpan-Tula , we will finish that. That's just archaeological sites. Of course, in Southern Texas, we're doing our last complicated tie-in right now. I would say that we have good organic growth opportunities in the business, and we also have some step-ups that we can still do outside of the industrial marketing, outside of new gas pipelines.
There's still some ANR business that we can do. First one is storage. They've actually started talking about it. It looks like they're about ready to let a contract for some storage in the eastern part of Mexico. The storage is right up what we do. As you can tell from the maps that both, what I'll talk about in energy and Stan's business, we are one of the largest storage players in North America. Quite frankly, electric transmission. We are watching electric transmission business. There are several electric transmission businesses that are going to go out to bid. Right now, the contracts aren't where we want them, but we are in the process. We are talking to partners, and we are talking to the government. I would say the government is starting to understand our concerns over the contracts. You never know.
If we can get those contracts to look more like gas transmission-like contracts, you'll see us playing in the power transmission business as well. Having said that'll conclude the Mexico, I think I will open the panel up right now for questions.
Sorry. Thanks, Karl. As I mentioned, we're through the prepared remarks on natural gas pipelines. For the benefit of the people in the room as well as the people on the webcast, we'll take questions now. Chuck, Stephanie, and Dwayne have got microphones, so if you just raise your hand, we'll get a mic to you as quickly as we can, and we'll start with Q&A. Go ahead, Jeremy.
Jeremy Tonet, JP Morgan. Stan, that was an interesting slide on the LNG that you guys have able to touch there. I'm just wondering how much more gas can you send to those different endpoints if the LNG continues to expand, particularly in the Gulf Coast? Seems like there's a lot of potential expansion there.
Yeah, great question, Jeremy. We'll start with Louisiana XPress, the project that I mentioned at the end. We're going to add three midpoint compressor stations to the Columbia Gulf system. We're going to create about 450,000 a day of new capacity. We're going to match that up with about 300,000 a day of available capacity. In the aggregate, think of that one project alone as adding 850,000 a day of new capacity to an LNG export terminal. Similarly, we have expandability on the southeast head station on the ANR system. When you go over to the West Coast, we could economically expand our GTN system probably to the tune of about a 0.5 Bcf /d .
In the aggregate across our footprint, it's not inconceivable to think that there's somewhere north of Bcf a day of additional supply that can get to these LNG export facilities.
That's helpful. Thanks. Thinking about the system further, Russ, especially New England seems to be particularly constrained, and they seem to prefer Russian LNG versus North American gas right now. How much more could you possibly put into that market as well, given the acute need?
Tricky part of the world to build in, particularly in New England. One of the good things with respect to the Portland Natural Gas Transmission System is we still have about 250,000 a day of what I would call compression expandability. Capacity that we can add to the marketplace without putting new pipe in the ground. That was a key factor in getting our last project up and down with respect to the Portland facility. Somewhere around a quarter would be, I think could be done economically and with a minimal environmental impact.
Thanks, Jeremy. Ben, go ahead. Sorry. Go ahead, Ben.
Ben Pham, BMO Capital Markets. You painted a pretty robust picture of demand growth in North America, gas-wise, high cash flow quality take-or-pay contracts, regulated exposure. Could you maybe comment on the counterparty side assessment of investment grade versus non-investment grade? It seems like no one's talking about it today. Maybe three years ago, everyone was talking about it. Maybe comment on that and how you think about also the return differences between the U.S. and Canada when you think about the counterparties.
I can start with respect to the U.S. business. If you could use 2017 as an anchor point, somewhere around 55%, maybe 60% of our customer base is made up of LDC customers, the balance being producers and marketers. Once our project portfolio is built out and Leach XPress, Rayne XPress, Mountaineer XPress, and Gulf XPress in particular come on, that mix shifts to almost about 55% or 60% being producer customers and the balance being LDC and marketers. Our producers do have a different credit profile, all things equal than LDCs. Our contracts in particular are made up of a mix of investment-grade producers and some non-investment-grade producers. Again, I think the most important thing is that we believe that the molecules are there. The molecules are in the ground to be produced.
Should something unfortunate happen to a non-investment-grade producer, we believe that somebody else is ultimately going to be there to step up and produce those molecules, which is why we believe in the basin.
On the Canadian side, we have a little bit of the same. In the NGTL system, you have a mix of producers and marketers. The unique thing about the Canadian system, it's a regulated system. If we have issues with some of our producers, the exposure is held by the collective in the Canadian system. Similar to what Stan has said, those molecules are going to be produced, and we have seen some of them change hands over time, but that basin is healthy, it's low cost, and all of that gas is going to want to move. If you get down to the other end of the system in Eastern Canada, that exposure is held mostly by very large, significant LDCs, which are strong counterparties, but the structure of the system from a regulated perspective is the same.
On a return perspective, given that regulated structure and that regulated risk, we get an appropriate regulated return on that. Right now it's 10.1 on 40% equity. We've had that for a period of time, we're looking for greater certainty in that as we go forward. We'd like to see that persist over a long period of time. It's the nature of the Canadian regulated infrastructure. You get that regulated risk for a regulated exposure, a return.
Thanks.
I think just to conclude on the Mexico side, the CFE, we're still comfortable with the CFE and the government of Mexico risk. Maybe when we put new customers on the system and you saw the maths on the industrial, we'll start getting down on credit quality at that time. As long as we're careful with the amount of money we spend hooking up our customers, I think that we can absorb a little bit of poor credit on that particular part of the business without any negative impact. Given that every dollar falls right into our bottom line on that, I think we could absorb some lower credit on that. For the most part, the CFE is still a good credit for us.
Thanks. Rob? Do you want me to go ahead?
Good morning. Rob Catellier from CIBC Capital Markets. You've mentioned LNG a few times in the presentation. I'm curious to know how far down the value chain TransCanada is willing to go in terms of putting investment dollars to work and under what circumstances. I'm referring to what type of contracting you might need there. In your answer, if you could touch on the strategic value of having that option available to your shippers and what that would mean for optimizing the load on your system.
In terms of the overall deal structure, contract portfolios, again, you could think of these as having contract terms of 15-20 years in duration. You could think of them as having returns in the 10% range on an after-tax unlevered basis, or maybe a better way of thinking about it is we're going to continue to add these new projects and build these new projects at about a 5x-7x times EBITDA multiple going forward. There seems to be lots of synergies between these LNG export terminals and what we do.
If you look again at the connectivity just in the Gulf Coast between the Columbia Gulf and the ANR systems, the value of us having these big demand centers that are going to export multiple Bcf a day of gas on a routine basis, matches up nicely with all the supply that we've been adding with our projects over the past two or three years. It really is a pretty symbiotic relationship.
With that answer, are you suggesting you would be interested in taking an ownership interest in LNG?
I look at it in this perspective. Intriguing opportunity. One of the things that I liked about our company is that we have very simple risk preferences. We like doing deals with long-term contracts that are take-or-pay in nature and have investment-grade counterparties. When you look at an LNG terminal and their paradigm, it seems to fit, all things equal.
All right. Robert?
Thank you. This question's for Tracy. You mentioned earlier the potential to offer some different services or do some different things on the mainline post-2020 once you've been able to decouple it. Just wondering if you can give some additional color on what those might be, why you can't do that now. Is it just because until you get there, you'll have a lot of competing interests and what that might mean in terms of regulatory approval?
Well, thanks, Rob. I think we are trying to do some of that now in advance of 2020 with our pricing discretion, so we've been able to offer out some fixed-price deals, and we've seen that drive the flows on the Western Mainline up meaningfully. There still is a certain amount of cross-subsidization that goes on back and forth between the Eastern Triangle and the Western Mainline.
As we separate those assets will stand on their own, and that just gives us a little bit more flexibility to think about the types of services that we can offer, particularly on the Western Mainline, and how we can think about the Western Mainline and the NGTL system potentially, for example, as one system to create the ability and the effectiveness of getting into market from the basin, even north in the basin, a little easier, a little more cost-effectively.
Got you, Tracy. Are you kind of intimating that maybe you're going to take another run at NGTL Western Mainline integration physically or synthetically?
I think what we're interested in is creating cost-competitive access to market, right? I think that's what the producers in the basin are interested in. There's a number of options of how to think about that. One of the options would be the kind of service, Robert, that you're talking about. We'd be willing to talk to producers about that if that's an interest. We think that there are some good economics for that, depending on how you structure it. Yes, that's one of the options.
Great. Thank you.
Thanks, Robert. Go ahead.
Hello. Rob Hope, Scotiabank. Just taking a look at your next wave of growth projects, especially in the U.S., they seem to be largely focused on your existing right of ways. I just want to get a sense of what you're looking on to expand the system beyond that and whether or not there are specific white spaces that you want to build.
One of the reasons I think we've been relatively successful compared to some of our peers is that a majority of our historical growth projects have been in corridor expansions. In the aggregate, we've added somewhere around 6 Bcf /d of capacity, and we're only building about 300 mi or 350 mi of greenfield build. We like running below the radar, if you will, and staying within corridor. In terms of white spaces, and I got asked this question last year, and I'll give you a very similar answer. One of the things that is intriguing is the Permian. You hear a lot of talk about the Permian and why don't we have a project out of the Permian. I go back to what I just answered with respect to risk preferences.
Our risk preferences are to do long-term deals that are take or pay in nature with investment-grade counterparties. That's not the mechanism right now out of the Permian. We do not have a competitive advantage in the Permian. All things equal, you're likely to see contracts that have terms of five, seven, maybe 10 years at best. You're likely to see contracts that have volumetric pricing or acreage dedications rather than take or pay in nature. You're likely to be dealing with counterparties that, for the most part, are not known names.
While it's a bit of a white space on a map perhaps, given the fact that we have a CAD 36 billion backlog of growth projects that meet our risk preferences, it doesn't make sense to me at this time for us to step out just to fill in a white space for the sake of filling it in.
Thanks, Rob. Linda?
Thank you. Linda Ezergailis, TD Securities. I wanted to expand on Rob Catellier's question about downstream extensions and look at other downstream markets beyond LNG. Specifically, what are your updated thoughts on investing in utilities potentially, and then maybe some updated comments on upstream on your G&P business. Have you evolved your thinking in terms of do you maintain your interest there? Do you increase it or do you exit?
I just go back to the comment about our risk preferences. I don't see us getting into the production side of things and more into commodity risk. That's just not who we are or what we do, all things equal. Getting into the utility space and trying to manage millions of customers and multiple regulators across multiple states. Again, maybe it's intriguing, but it's just at least one deviation removed from what we do. What we do best is we match the fastest-growing supply basins with the fastest-growing demand centers, and we like regulated pipeline returns. We like the process that we have. Just go back to when we have a CAD 36 billion backlog of growth projects that meets our risk preferences, why should we step out and take undue risk at this point in time? It doesn't seem to make sense to me.
Would you be able to give us some sense of magnitude of the sum of the value of your projects in development on your future opportunities slide?
Yet. It's a little bit tricky because in some cases, like the Northern Border system, we have a joint venture partner. I'll give you an eight-eighths number. I'm not going to break that ownership share. In the aggregate, that could be up to a CAD 1 billion-CAD 2 billion capital investment. Again, think of those projects being built at a 5 x- 7x EBITDA multiple going forward. Not all those may hit, we're certainly going to pursue all of them, and we do expect to compete for and win more of our fair share.
Sorry. Praneeth Satish, Wells Fargo. This is for the U.S. gas pipe business. I guess a high-level question. Given all the regulatory risk that you're seeing in the Northeast with new pipes being built, has there been any thought about maybe incorporating some kind of development risk into the tariff? Recognizing you're building at a seven times multiple, could future projects be done at a six times?
One of our New York customers actually tried that with the New York State Public Service Commission, and unfortunately, it was turned down. The notion was for us to come in and develop a project in that part of the world, we are not going to put CAD 10s million or CAD 100s of millions of dollars of development capital at risk. That is a big challenge. It is a big challenge for anybody to step up and do that. In this particular case, unfortunately, the New York PSC said no, that they are not going to allow the ratepayers ultimately to bear that cost. In the meantime, what you are seeing is parts of New England and parts of California paying the highest energy costs anywhere in the U.S. We are getting clear price signals that new infrastructure is needed, but we have regulatory paradigms that say otherwise.
Just one other quick question, just on the potential Northern Border pipeline expansion. Can you just discuss the logic behind that, how big that would be?
Couple CAD 100,000 a day in terms of capacity with a couple different capacity options out. To use a golf analogy, this is a long putt, but we have made long putts in the past. We potentially could reverse flow on Bison and take Bakken production south on Northern Border into Bison. We also could bypass Bison and just take new production all the way down to Ventura. Again, you look at the value of the NGLs and the liquids that are behind that gas stream, you look at the growing production. It seems to make sense that a new residue line out of that region is needed.
Thanks. Go ahead, Pat.
Pat Kennedy, National Bank. You mentioned demand is lagging supply growth over the coming years. I'm just wondering how storage might be integrated into your growth plans going forward.
In terms of developing new storage facilities, I just don't see that, at least in the U.S. Now, Karl may have a different paradigm in Mexico. In the context of given all the flowing production that we're seeing, again, Marcellus ramps up from 30 Bcf /d- 44 Bcf/d over the next 10 years. That spread between summer and winter pricing just isn't there to justify new storage build, so that there's so much flowing gas, and it's almost virtual storage, 365 days a year. In terms of building new storage facilities, I just don't see that from the arbitrage value. However, on pipes like ANR and Columbia, storage is an integral part of providing service to our LDC customers. It's used for liability purposes more so than an arbitrage purpose.
Thanks, Pat. Tom?
Tom Abrams, Morgan Stanley. Looking at the Panhandle region and wondering if all the success you have in the upper Midwest is causing an issue for the gas coming out of the Panhandle region. Do you need to find a different destination for that gas, either south or southeast?
I think as the Permian begins to grow, and again, we see growth there pretty much on pace with that of Marcellus growing at 6%- 8% per year. Maybe Permian hits 12 Bcf, 13 Bcf between now and 2027. I think a lot of that gas is going to go into Mexico, all things equal. Some of it likely will leak into the East Coast of Texas and compete with some of the LNG coming down from Marcellus. Again, when you have growth of about 14% per year, we're growing that pie and there seems to be enough molecules and enough demand, particularly driven by LNG exports for everything.
Do you need connectivity, though, that you would own and build?
In terms of coming over from the Permian, I think I've addressed that in terms of additional connectivity coming down from the Midwest to the Gulf Coast. Once we complete our Gulf XPress project, we'll have taken a 2 Bcf Columbia Gulf system that has historically flowed from south to north, added seven midpoint compressors or thereabout, and turned it into a 3 Bcf /d system that flows north to south. Once you get to about 40 Bcf, 44 Bcf, you're probably in relative demand between all the pipes that could be reversed above and beyond that. You may need a new greenfield line that goes down to the Gulf Coast to serve all the Gulf Coast export facilities.
Thanks, Tom. If no other questions, then we're running a little ahead of time, which is good. We will break now then for about 30 minutes. Maybe if I could ask that folks return at 10:00, we'll pick up at that point. Again, people are available through the break, so feel free to approach any member of TC Energy with any other questions you may have.
[Break]
Sorry, folks. Sorry to interrupt what I'm sure is good conversation. If you could maybe start to make your way back to your seats, we'll get started again here in the next minute or so. I assume this is forward.
This is back?
Yes.
Yeah. That's right.
Okay.
At least we can turn our phones off.
Okay. Thanks, everyone. Hopefully, you enjoyed the 30-minute break there and had a chance to catch up with folks. As I mentioned, just before the break, we'll pick up now with Paul Miller, who is president of our Liquids Pipeline business. Paul's going to provide you with an overview of that business. That'll be followed by Karl Johannson, who will cover Energy a little bit later this morning. Don Marchand will wind things up with a finance update. I'll turn the podium over to Paul.
Thank you, David, and good morning, everyone. It's good to be here to discuss the Liquids Pipelines business. We've been doing a lot of good things. We've been looking to expand our reach, both upstream to attach to new supply and downstream to extend our market reach. Consistent throughout this approach is we target quality, sustainable performance. This is achieved by securing long-term take-or-pay contracts, and we always strive to maximize our contract volume. In many cases, however, we're required to set aside capacity for spot or uncommitted shippers. Because of this, we site our pipelines in areas where we have growing supply and strong market fundamentals, which support the movement of those spot barrels through our system. Our EBITDA is driven by three primary sources: long-term contracted volume spot volume and activity through our marketing affiliate.
Looking first at the contracted volume, our base EBITDA has very little variability because of these contracts. Keystone is about 94% contracted and the remaining 6% is set aside for the spot shippers. Marketlink is about 80% contracted. Grand Rapids has recovery through a 25-year cost-of-service model. Northern Courier Pipeline return of and on capital is fully recovered over the 25-year contract term, White Spruce Pipeline recovery of and on capital is recovered over the course of the contract term. When we take a look at spot revenue opportunities, the southern end of our system has open capacity, Marketlink has benefited from the increase in U.S. production, largely driven by light tight oil out of Permian and the Williston Basin.
Today, we see a shortage in pipeline capacity in that cushion to the U.S. Gulf corridor, this is causing the Brent-WTI spread to move out, that wider spread encourages spot volumes onto Marketlink pipeline. I anticipate this scenario to persist throughout the remainder of 2018 and throughout 2019. We're responding aggressively to the shortage of pipeline capacity in this corridor by increasing the capacity on Marketlink. Marketlink has historically run between about 400,000- 500,000 bpd . When we saw and foresaw this demand for additional pipeline capacity, we started increasing our throughput capabilities on Marketlink in late 2017. This program continued through 2018 and will continue into 2019. We're doing this through scheduling efficiencies and the use of drag-reducing agent, all at very low cost.
The result of this program is we've been able to increase our throughput capabilities in MarketLink to the mid-600,000 bpd range. I would anticipate in 2019, we'll be able to increase our throughput into the mid-700,000 bpd range. We have other opportunities to increase this throughput further that does require modest capital, but can be done on a fairly short timeframe. We're monitoring market developments, we're monitoring the fundamentals, and we'll make the call on additional increases in due course. As we increase our pipeline capacity, we look to term out that incremental volume, staying consistent with our business model to term out as much of our volume as we can. We're in an open season today, and we'll see how that open season plays out here over the course of the next few weeks.
Our pipelines are all located in areas of growth with strong, sustainable market fundamentals, and we're seeing this result in our primary pipelines, Keystone and MarketLink, which are running full. The high WCS-WTI differential attracts spot onto Keystone. The wide Brent-WTI differential attracts spot onto MarketLink. Our marketing affiliate benefits from these high differentials out as well. With committed pipeline capacity, marketing can move product between pricing points and seize this value from these differentials. This multifaceted approach to creating value has served us well and has created strong results. We continue to enjoy strong performance from the contracted Keystone system. We brought two new intra-Alberta pipelines, contracted intra-Alberta pipelines into service in late 2017, and they are now contributing to EBITDA. Our uncommitted pipeline space is in high demand, and our marketing affiliate contributes incremental EBITDA. This strong performance will continue.
Our results in Q4 should track what we saw in 2018, and I would expect a similar performance through to 2021. I'm going to jump ahead here, which is always dangerous because it means I have to then backtrack, to the Keystone XL status slide. I think the status of Keystone XL is top of mind given the court decision we received last weekend from the district court. This judgment was received sooner than anticipated and gives us insights into the suggested deficiencies and the remedies. We're going through the decision. We're reviewing the deficiencies to determine how best to address the deficiencies. I will tell you, I believe that they are manageable. However, at this point, it is too soon to determine what impact the ruling will have on our schedule.
In the meantime, we await the decision from the Nebraska Supreme Court on the challenge to the approved route through that state. All of the proceedings are complete, and we're awaiting the court's decision. The comment period for the State Department's supplemental environmental impact statement is complete, and we would anticipate having the SEIS issued here in December, and that should be followed shortly by the decisions from the Bureau of Land Management and the Army Corps of Engineers decisions here in January. As we navigate these hurdles, we will continue to be very measured in our approach, and we will continue to spend very little until we have certainty. Throughout this all, we remain fully committed to Keystone XL. Keystone XL is an attractive investment for TransCanada, and it is an economic proposal for the shippers. This can be seen in their level of support.
Keystone XL is now fully committed. We have commitments from multiple parties to bid into a follow-on open season for Keystone XL capacity. When you combine these commitments with the existing contracts we have in hand, Keystone XL will effectively be full when you consider the amount of capacity we have to set aside for the spot reservation. This volume will provide a return to TC Energy on total capital invested since 2009, consistent with projects of a similar nature. It's important to remember our commercial model on XL has not changed materially. All historical costs, plus AFUDC since 2009, are captured for toll determination. The write-down we took in 2015 does not remove these costs from the rate-making purposes. We share capital cost variances equally with our shippers, and there's a formula-based sharing of the next phase of development costs.
We're firming up our capital costs, but with what visibility I do have, I believe we can construct Keystone XL for about 6x contracted EBITDA on the to-go costs. The completion of Keystone XL will create a significant integrated pipeline system. With the expanded footprint, we'll have more opportunities to enhance operations and increase efficiencies. The first step will be to move those contracts, which currently flow on the system down to Cushing in the U.S. Gulf Coast, onto the Keystone XL lake. What this does, this frees up space on the legacy system. With that freed-up space, we have a means today to contract up that space with new long-term 20-year contracts.
What you'll end up is two very efficient bullet lines, one running from Hardisty down to Cushing in the U.S. Gulf Coast, and the other one running from Hardisty down to Wood River and Patoka. You will have an integrated system with about 1.4 million barrels per day of long-haul capacity from Alberta, which will be underpinned with approximately 1.2 million barrels per day of long-term contracts, the majority of which will be new 20-year contracts. We're pursuing many growth opportunities. Oops. One slide behind. Sorry about that. We are pursuing many growth opportunities besides Keystone XL, but Keystone XL will accelerate some of them. Three of note are within our intra-Alberta system, and each of these projects are fully approved by the regulator. Grand Rapids Phase II is a fully permitted pipeline.
It's a looping of 460 km of 36-inch pipe, which will connect the producing areas of Northern Alberta with the Edmonton and Fort Saskatchewan market hubs. The Heartland Pipeline is a fully permitted CAD 900 million investment, which will connect those market hubs of Edmonton and Fort Saskatchewan down to Hardisty. The Keystone Hardisty Terminal is a fully permitted CAD 300 million, 2.6 million-barrel facility, which will provide long- and short-term contract storage, as well as batch accumulation facilities for our shippers. We are progressively increasing the level of long-term contract support for these opportunities. Our ultimate goal is to create a seamless, contiguous path from the producing areas of Northern Alberta down to the marketplace, where shippers can make one nomination and flow their barrels efficiently down to the marketplace. While all the attention is on Keystone XL, we continue to advance a number of other growth projects.
In Alberta, we have commenced construction on the White Spruce Pipeline, which will move Canadian Natural Resources production from their Horizon facilities into the Grand Rapids system. In Cushing, Oklahoma, we are in the final stages of commissioning an additional 1 million barrels of storage, and we have started the development of additional storage at our Houston tank terminal. Market fundamentals remain strong for the liquids business. In Canada, there is increasing supply of Canadian heavy oil. At the same time, we're seeing declining supplies of heavy oil from Latin American sources. This creates a tremendous opportunity for Canadian heavy to the U.S. Gulf Coast, and we see evidence of that today. Keystone XL is fully committed, and our operating pipelines today are running full. It's a similar story south of the border.
There is increasing production of U.S. crude oil, driven largely by light tight oil out of the Permian and Williston Basin. The U.S. demand for light oil is largely satisfied, so much of this product is finding its way to export markets. We're well-positioned to meet that infrastructure requirement for this increase in supply. Our current footprint and assets are near these growing basins, and in addition to pipe in the ground, we also have other facilities around these basins, such as interconnections and terminals. This existing infrastructure provides us with a competitive advantage, and we're increasing that competitive advantage by increasing our reach into the Lake Charles, Houston, Texas City markets. We are increasing our capabilities at our Cushing facility, and we are expanding our Houston facility as well. We're actively working these opportunities.
We're out in the marketplace in discussions with customers, and we're seeing significant interest in moving these growing volumes to key markets such as the U.S. Gulf Coast. Our strategy is working. We have generated growing EBITDA from our highly contracted quality assets. Our multifaceted approach provides the right balance to maximize returns. Our highly contracted pipelines provide quality, stable cash flow. Our assets are sited around strong market fundamentals, which provides upside opportunities from spot barrels, and our marketing affiliate seizes market differential opportunities. Thank you for your time here today, and I look forward to taking your questions.
Thanks, Paul. Again, similar to earlier this morning, if you do have a question for Paul, if you could just raise your hand, we'll get a mic to you, and we'll go from there. Go ahead, Rob.
Hi. Rob Hope, Scotiabank. Not surprisingly, the first question's on Keystone XL. I'll leave the regulatory stuff to someone else. Just taking a look at the 6x EBITDA build multiple, can you give us some additional color on two parts, I guess? One would be the incremental capital to go there, secondly, whether or not there'd be any knock-on effects on EBITDA related to MarketLink and Keystone one, and if that 6x would be inclusive of that.
Sure. On the first question, we continue to refine our cost estimate. As you can appreciate, there's a lot of moving pieces on a project of this nature. We do have some of the activity in from contractors, et cetera. With some of the outstanding court cases, et cetera, we are going to wait to provide visibility into the number once we have greater certainty. We don't want to be refreshing our number constantly based on some of the changing variables. No visibility yet, but we'll provide that in due course. In regard to what's included in that number, that really just captures Keystone XL, which, as defined, is the pipeline that runs from Hardisty down to Steel City.
There will be additional pumps, stations that we'll have to add to what is the segment between Cushing and the Gulf Coast, as well as Steel City to Cushing. That will be captured in that incremental capital. Really the primary build is pipeline build, about 1,800 km from Hardisty to Steel City, all the pump stations associated with that segment of the pipe, as well as additional pump stations along the existing system.
All right. Thank you. Maybe as a follow-up, just in terms of timing, I think historically, you've really pointed to that early 2021 in-service date. With the uncertainty of the next administration in the U.S., would you be okay pushing that out into 2022 or beyond?
We don't know the impact yet on the timing of the Montana court case. We'll wait and see how it is we're going to address the deficiencies identified by the judge. Remember that it's the State Department which is the lead on this, and we continue to work with the State Department in that regard. As far as timing around the pipeline, the need for Keystone XL has never been greater. When you're looking at CAD 40-CAD 50 differentials on WCS versus WTI, whether it's in this administration or the next administration, XL is a project that the industry needs and is a valuable piece of infrastructure for the North American economy.
Thanks, Rob. Go ahead, Pat.
Just to follow- up on that thought there, Paul. The need for KXL, as you said, never been greater. I'm just wondering if there's an opportunity here to revisit the cost-sharing mechanism with producers, just to ensure that construction does commence by that June timeframe.
Thanks, Pat. We do have a cost-sharing mechanism with the producers, and thank you for that. I forgot to mention it. In our commercial model, our capital cost variances are shared equally with the shippers, and we have today a formula for development cost risk-sharing with the shippers for the next phase of activity.
Sorry, go ahead, Praneeth.
Hi. Yeah, I was just wondering if you could talk about any opportunities you're looking at in terms of takeaway out of the Bakken that you could help facilitate on your system. Is that something you're looking at?
We are. When you go back to the map that showed the various emerging basins, whether it's Niobrara, whether it's Williston, whether it's Permian, we are well-situated around those basins. It does provide us opportunities with our existing assets, with our existing relationships with the stakeholders in those areas. Our project development process involves us working those opportunities and securing the commercial support before we go live with it. We have folks on the ground taking a look at the opportunities, and they're very good opportunities. They're strong fundamentals. It's something we do well, project development, and we will do it consistent with our business model, which looks for those long-term, highly contracted opportunities.
Sorry. Any other questions for Paul? Linda.
I realize your plate's quite full right now, but long-term, strategically, down the road, how do you think about refined products and delivery of those and how they might fit in your model? I know in the past you've looked at that in Mexico, can you give us an updated sense on whether that's something that you think about over the long term or not?
Thank you. We do, and we today move refined products. Our Northern Courier Pipeline is a dual pipeline with the one leg moving northbound with refined product, largely diesel. Refined product is in our scope. It is something that we think about. It's something that we look for, again, we will develop those opportunities consistent with our risk preferences, seeking out the long-term opportunities. We view liquids to be our area of focus. We're not going to get into upstream production. We're not going to get into downstream refining and processing. Everything in the middle is something that we're focused on and hopefully the takeaway of those refined products from the refinery.
Thanks, Linda. I guess we'll leave it at that then. Thanks, Paul. We very much appreciate that update. With that, we will turn the podium over to Karl Johannson. Karl is going to provide you with an update on our energy business.
Here we are. Perfect. Thanks, David, I'm pleased to be back to talk a little bit about the energy business. This is a business that I have personally been involved with for about 22 years now. I think we started it in earnest, about 1995- 1996, in those days, we had a couple of really very small plants interconnected, taking heat off of our mainline system. It's been quite an interesting ride with this business. Since that time, we have actually built it to be one of Canada's largest privately owned power companies. Notwithstanding the fact that we've recycled some capital over the last couple of years, it is still at about 6,600 MW, one of the largest privately owned power companies in Canada. I'd also point out that our mix has changed, of power options has changed with the rationalization of the portfolio.
We're now about 50/50 nuclear and natural gas, which is, I think, pretty good carbon footprint for this business. Obviously, I'll talk a little bit about our nuclear position in Bruce in a minute here, but our gas fleet is one of the most modern, efficient gas fleets in Canada and North America, as a matter of fact. We run the spectrum from peaking plants to several cogen plants in Alberta and Quebec and, of course, efficient combined cycle plants in Ontario. It is a platform that I think is a high-quality business, even though we have recycled some capital here, and we may recycle some capital in the future. It is a business that TransCanada is going to continue to hold on to.
We consider it one of the pillars of this company, and it is an important part when you match it with our natural gas business and the rest of what we're doing. It's an important part of those businesses. Just to take a look at what underlines what we have in the power business. If there's one thing that I'd like to emphasize that these are very, very high-quality cash flows that we're pulling out of this business. When you take a look at our contract portfolio here, literally, 95% of our capacity is underpinned by long-term contracts. We run the gamut from some maturities coming up in mid-20s right to 2064, which will be the end of what our current agreement is with the nuclear refurbishments we're doing. A very solid long-term contracted portfolio.
This is, quite frankly, what makes this a good candidate for some recycling of some capital. Once you get plants that have these types of cash flows and this type of longevity with it, this is what brings us the opportunities where some people maybe value the cash flows more than we do, and which is why you're seeing some of the circulation of the capital over the last couple of years. This is a very highly contracted portfolio. Quite frankly, there still is some opportunity, although we would admit that the opportunity going forward in the market is not getting greater as time goes by, but we still are seeing some opportunities to add to this in the future. Our accomplishments over the last year were really we're still generating solid results.
I'm going to show them in a few minutes, and I'll show them with Napanee and with the refurbishment of Bruce in them. We still are generating solid results. We're still seeing good growth in this business, even though we have cycled some capital out. Our construction programs are progressing. The Napanee power plant, almost 1,000-MW power plant in Ontario. It is proceeding. We've had some difficulties. It is a little late and a little over budget. We've had some difficulties with the contractor on that, but we are getting through that. We're about 92%-95% constructive on that plan now, about 60%, 65% commissioned. You will see in the first quarter here, we'll finally bring that online. That, again, it's a Mitsubishi 501G machine. It's a two-on-one.
It'll produce about 1,000 MW, just a little less than 1,000 MW of capacity, and it'll be a good flagship for the business as soon as we get that up and running in the first quarter here. We're advancing Bruce Power life extension program. Beginning at six, I'll talk a little bit about this, but we have submitted the major component replacement MCR program beginning in 2000. We have submitted that to ISO, I'll update that. Closed the sale of Cartier Wind this year for CAD 630 million, which will help our funding program and our capital program. Closed the sale, really, of the rest of the U.S. Northeast business, which is the retail book. We have a small wholesale book, which we're running down right now, but that was really the last of the U.S. Northeast business that we closed off.
We're left with two core markets here with the exit from the U.S. Northeast. One being Ontario, the other being Alberta, which we'll talk about in a minute. I think as thermal power goes, as thermal power generation goes, and nuclear power goes to Ontario, these are two still pretty solid markets. There's still growth in these markets in the thermal power space. Don't know if we can say that with the rest of North America on the thermal power space. Certainly, in these markets, there's still growth. You can see this chart here with Ontario. This is a chart actually from the Ontario ISO on resource requirements going forward. I think this speaks volumes as to the health and the future of the assets that we have here.
Most of our assets, as you can see from the earlier slide, are contracted for very long periods of time. You can just see the supply deficit coming in Ontario. Many people may not realize that this deficit is on the horizon because of the overbuild they've had in renewables and so forth. I think it's masked the underlying thermal deficit in this market. This deficit is coming from a couple of things. Number one is we're going to lose a nuclear plant shortly with the Pickering plant. Number two is we're going to lose parts of the other nuclear plants. Starting 2000, Bruce is going to start having units out, and Darlington has units out right now. When you take a look at what's going on in the nuclear space, the refurbishment program, both OPG and ourselves, is adding to this deficit.
On top of that, some of the contracts that they've subsequently signed are coming to the end of their life at this period of time. As you can see, this core market here in Ontario still looks like it's a good market for the thermal to go forward. As our contracts roll off, we are expecting some back in life to come out of those contracts. Those facilities are still used and needed in the facilities, and we're quite comfortable where we're sitting with the core market there for both our thermal and our nuclear position. Napanee Generating Facility, I think I talked a little bit about that before. Again, when it does get commissioned fully in the first quarter of this coming year, it will have a 20-year PPA with Ontario ISO on it. Construction is progressing. I talked about kind of where they are right now.
I was personally at the plant a couple of weeks ago, I can tell you that it's starting to look like a plant that's in commissioning. All the scaffolding was down. It's looking like a plant ready to go. I am quite confident that the issues we had when we lost our contractor are behind us right now, and we are marching towards full commissioning here in the next couple of months. Total capital cost of CAD 1.6 billion. Again, we'll have a very long dated contract from the IESO behind that. Bruce Power. I want to spend a couple of minutes on Bruce Power. I think this is not only kind of our biggest asset right now, but is also the one that I think we're in the power space we got the longest-term commitment on. This plant right now is 6,400 MW.
It's about 30% of Ontario's needs for electricity comes from this one plant. Our ownership is slightly less than 50%. We're with OMERS here. Of course, the remaining percentage goes with the labor unions. We have recently, over the last couple of years, completed a contract to refurbish Units 3 through 8. If you remember, Units 1 and 2 were refurbished a few years ago. They're up and running now. We have finished that job, and they're able to start their life cycle again. Three through eight need refurbishment in order to carry on. With that contract came a contract for that capacity through to 2064. This is still the same plant that we had before with all the safeguards that we built in when we originally bought it. It is still a plant where we do not have the decommissioning obligation.
It's still a plant where we don't have the fuel liability with spent fuel. This still rests with OPG, and still at the end of the life, this plant will still be turned over to them if there is no further repowering at that time, and they will take that end-of-life cost. The investment through the life extension to units three through six, our percentage of it, is about CAD 8 billion. CAD 2.2 billion is for the first unit to go into refurbishment. That's Unit 6, and that will be CAD 2.2 billion until 2023, which will be the end of that refurbishment. It is a good sizable investment that'll happen over the next 12, 13 years, as we'll do one unit at a time. It will be steady work for that period of time.
I'd also point out just at the end, that we just received our 10-year license renewal from the Nuclear Safety Commission in late September, and that has passed all appeal processes and whatnot. We're in good shape on our licensing. I always get asked questions, what is different with this refurbishment than one and two? For many of you in the room, you probably watched me and other people up on this podium talking about the stresses we had on one and two. It was over budget. It was late. It was quite a difficult refurbishment. I believe this refurbishment is very much different, and I want to spend just a second just talking about it. First of all, Units 1 and 2 were shut down for many years, in one case, over 20 years.
When we went into actually refurbishment, there was a lot of unknowns in those plants. Every time we opened something up, we would find something new. We weren't ready for it. Units 3 through 8 are completely different. These are all operating units right now. Every year, they go into some sort of maintenance, either major maintenance or minor maintenance. Every year, we've got them down. Every year, we're opening various parts of it up to take a look at it. I would say, first of all, its comprehensive plant condition and assessment of the plant is much, much better than Unit 1 and 2. We actually know these plants very, very well. This is akin to a very large maintenance process, more so than a full refurbishment like we had on 1 and 2. 1 and 2 were actually new nuclear plants by the time we're done.
These ones will be very significant maintenance. I would say our governance is in place. We did take some learnings out of 1 and 2, and we incorporated them in the contract that we have with IESO. There's longer lead times before we put projects into maintenance now. There's more governance in place. We have people over at the Darlington refurbishment. We're working with OPG very closely. We're working with the same suppliers as OPG, such that the learnings that we get from OPG, who's ahead of us in refurb, are learnings that we can use in ours. We have taken both the learnings from 1 and 2 and the learnings that OPG is going through right now into ours. We have more governance in place. Improve process assistance, people, and project controls.
Just to give you an example, I was at the plant last week, and I was going through our readiness for Unit 6. They're not going to start Unit 6 refurbishment until they have every part they need on site. Just to give you an idea of we're not going to get into situations where all of a sudden our valves are the critical path items. We'll have every part on site before we go on. These are some of the learnings that we learned from, again, from 1 and 2. I talked about unit condition assessments. We know these very well. The project costs and execution schedule are well developed. I would add, the way we've priced this is that we go on with the first unit, which is Unit 6.
That'll probably be the most expensive unit because we have to develop all the tools and processes for this one. Each one should get cheaper. We've given ourselves the ability that each unit we can reprice. If we find things that we didn't know, we can reprice. We have a threshold with the IESO, such that if we come in under that threshold, and it's a 2014 adjusted for inflation threshold, that there's an automatic go. If we come in over that threshold, it doesn't mean the project doesn't proceed, just the IESO has to sit back and make an an assessment as to the economics of that process. We have good ability to reprice if we do find something that we didn't expect. Cost duration estimate is finalized 15 months prior. Every unit will be repriced.
You'll see in a second here that there's minimal overlap. This is the schedule. There is some overlap, but it always comes at kind of the end of the prior unit. We're not going to get in a situation where we get ourselves overwhelmed on the program. I'm quite comfortable this time that we're walking in. Much better processes, much better governance, much better assessments than before, and I am looking forward to bringing these in on time and on budget. I would add that OPG is doing a pretty good job over on their site, too. Every indication we got from being on OPG's site is that this plan is working. As I said, we have submitted Unit 6 MCR to Proceed as Planned. There's really two parts to the refurbishment.
One is the Major Component Replacement, and that's what we just submitted, and another one is asset management, which kind of goes on before and after the MCR. We have submitted the MCR as planned. We are expecting to hear back to them shortly. Again, it was underneath the threshold, so there's no decision to be made. It's just a completeness of determination. We will be proceeding and throwing the breaker in January 2020. You will notice when you look at our forecast, a bit of a pop in our revenue on Bruce this coming year, that's because we start getting paid. The way our contract has it is that we start getting paid for the power on the refurbishment during the time of construction. That way, we don't go for large periods of time without revenue for this product.
You'll see a bit of a pop in April because we start getting paid. Our unit's revenue goes from CAD 68 to mid-70s, starting April 1. Then, of course, in January, we'll bring the unit on. I'll talk just to finish up or talk about our core markets in Alberta. We're still a big fan of the Alberta market. I know there's some uncertainty in this market right now. The pricing has turned around. There's lots of upside to this market with the coal coming off. We've already seen some of the coal come off and seen coal start being converted to gas. As a matter of fact, some of what you saw Tracy talk about with our gas expansion in Alberta has been to feed gas to these coal plants to switch them from coal to gas.
Even with the coal PPAs gone now, we have a pretty decent position in this market. It is turning to a market with a capacity market, which we are quite comfortable with. We've spent a lot of time in the U.S. Northeast, and we are working with them on the capacity market. We'll see how that works. I still think that there's a good market to be had here, and I still like our position. Who knows? If the market turns out good, the capacity market turns out good, this might be an area that we can expand in, because I do know the power is growing here. We also have about 118 Bcf of storage capacity.
There was a conversation earlier on storage capacity, and we're holding onto that right now just because with the large gas, I agree with Stan that the seasonal variation has been muted with the number of gas, but I do see lots of operational storage needed for our customers. Once you adjust this for the sale of our assets, it's still pretty good. This is a billion-dollar EBITDA business. When I talk about 6,600 MW in the largest private-owned in Canada still, there's not actually that many private-owned power businesses in Canada that put off CAD 1 billion of EBITDA a year. It is, even though we cycled some capacity and even though we might cycle some in the future, it's still a very significant business, not only for TC Energy, but when you compare it against some of our peers in Canada.
One of our key focus for areas, well, obviously, I want to finish Napanee. I think that's very important to get that commission, get that in. It's a needed resource. You could see my graphs earlier. This is going to be an important resource for the province. Got to get that done. Right now, we've adjusted our portfolio a little bit. Some of our plants have gone. Some of our plants, we're putting new ones in. We have to get our assets operations and maximize the profits of the existing fleet. Right now, we're getting ready to throw the switch in Bruce, but we also have to get the next Bruce unit up and engineered and get ready for submission of that in a couple of years. We're working with Bruce on that life extension program. We are still pursuing some growth in this area.
We do have bids going out. There are some for the assets that fit our risk profiles. They're very hotly contested right now, and certainly, we make some bids where we don't win, but we're still in the process of putting bids forward, and we're still looking at some expansions to some of our existing plants and some expansions in the renewal space. There is some growth, and there's still some focus on that. I will admit, when they're contracted and they meet our risk preferences, they're very hotly contested, and they're tough to get in at the returns that we demand. As you can see with our portfolio of great projects right now, we have to make sure that we have competitive returns in order to proceed with these. Having said that, I think I'll turn it over to questions now.
Thanks, Karl. Sorry, Ben or Jeremy, go ahead.
Karl, curious, since 2015, any changes on the Bruce side, CapEx in service dates on the refurbs?
No. I think we're in pretty good shape. All of our insurance these days today are still sticking. CapEx, I put up CAD 2.2. Our original submission in the contract was CAD 2,014. Either you have to take today's dollars back to 2014 to those 14 todays. If you actually look through our contracts, you would see different numbers, and you'd wonder how they would match. I can tell you that the number we have today that we submitted, the full amount, of that CAD 2.2 billion, the MCR part is about CAD 1.3 and the rest is asset management. That is well under the threshold. We're in good shape on both budget and schedule right now.
Okay. If I may ask a second question. Bruce, strategically, overall portfolio, maybe this question for someone else on the team. What's the thought process on the rationale for continued investment in Bruce when you think about Ontario noise renegotiations? You think about construction cost pressures. I understand the thought of reducing that through Unit 1 and 2, but I haven't seen any nuke plants globally that's been on time, on budget, at least from what I've seen so far. You can effectively redeploy that capital, fund XL, pay down debt. Maybe just an update on that when you think about overall Bruce investment.
Yeah. It's a good question. Let me hit on a couple parts of Bruce that we like as a company. Number two, the return is commensurate with what we're doing is low double digits. The way we've structured our payment, it's such that we don't actually go without revenue for the facility even when it's down. I think that was a very important part of this contract negotiation. I wasn't going to get into 15-year, 12-year construction where every year I lost revenue because I had a unit down. The way that this works really is almost like a rate-based type investment. When we get our value of the construction approved, agreed to, that rolls in the rate base, and we immediately start to get paid on it.
There's a few differences right now in this than I would say with a traditional construction program that actually fits in our book very well vis-a-vis other projects that I would have. Second part, I'd say on the technical execution, I agree. We went into this eyes wide open saying that there has not been a lot of success in new nuclear or refurbished nuclear, and we're quite frankly, on Units 1 and 2, I was personally there feeling the pain as we were trying to bring that into service. We went into this with eyes wide open on that, understanding that we had to do it differently. We have done this differently by actually getting more time in our contracts to do the engineering so that we're not any way time-stressed on these particular projects.
By having only one unit at a time being priced and being able to update that price in the next unit, by having escapes, if us or the IESO, kind of after Unit 3, after we've done the third unit, either us or the IESO can opt out of this if it's not working for us. I think we've mitigated all the concerns that we have. Plus the process that we're doing right now, the people that we have at OPG, the fact that OPG is ahead of us, we're using a lot of the same supply chain, I think has really given us a big comfort that this is going to be different and that this is actually the right way to do projects like this. Only time will tell. I am comforted right now when I look at OPG.
OPG is in pretty good shape with their refurbishment. It's happening as they're planned. I do think that we have determined a process now that'll be successful. When you look at it, when you stack it up against other investments we have, I think it's certainly right there with some of the best investments they have on a return basis. I think the risk in this is totally manageable. I do think there's a good reason for being for Bruce. The nuclear industry is very important to Ontario. Ontario is kind of the center of nuclear industry in Canada. I think Ontario supports, even the new government in Ontario supports the nuclear business. The old government supported nuclear business. There's lots of technology and jobs that are in this business, and I think there's a good reason to be there.
I think the nuclear megawatts in Ontario play an important part in their stack. We're quite comfortable that this is where we want to be and there's good reason for being here.
Rob Hope, sorry. Yeah.
Maybe if I can continue on Bruce Power, just to confirm, Karl, those low double-digit, that's unlevered after-tax.
Yes, absolutely. Yep.
Can you just refresh where you ended up on Units 1 and 2? Significant cost overruns and time delays, but I believe you still ended up in the high single-digits.
Oh, yeah.
Better than most of your projects.
Yeah. I don't have the exact number, but I think it was high single digits, probably in the 8%-9% range. Although there's some scars with the actual construction and doing one and two, we did have a good commercial agreement which helped share those costs, just that we came out with that. We started at a much higher rate of return, but it still came out and it's a pretty good deal for us. When you take a look at the high single digits, that's what we'll get for a pipeline, for example. It turned out pretty good even though there are some scars from it.
Can I just ask about Alberta and the growth side that you were talking about? Are you interested if the capacity market stays where it is? Is that something you're willing to invest in given just the one-year state of the market three years forward?
I would say if it stays where it is today, probably no. They don't have a long enough duration to best market. I believe that going to that capacity market, the market will speak and we will see adjustments to it going forward as they do want capacity to be there. Yeah, I don't believe anybody else is going to be any much different than us. I think people are going to demand a bit of a longer capacity market. Having said that, there are deals outside of the capacity market that people can do. Right now we're working on some renewables that have contracts associated with them that'll really be outside of the capacity market. We'll still look at them even though there's a poor, what I would call a poor duration of the capacity market.
If we can do a third-party deal, we still work on that. We got some work to do in that market regardless of the capacity market. I do believe the capacity market, the important part is getting one into Alberta. I've been an advocate of the capacity market, and I tell you, many years I was alone in this advocacy, but I've been an advocacy of capacity market in Alberta for many years. I don't worry that maybe the duration is a little bit light on the first pass because I do think the market will work. As long as we have a government in place that allows it to work, I think they'll start pushing that duration up. At that point, we'd probably be interested. I don't know what the magic number is.
It really depends on what our view is, what customers we got. Certainly where it is right now is probably not where it is. When it gets around 7- 10 years, we probably start getting our interest. Certainly we'll still be looking for customers even behind that for longer durations.
Thanks, Karl.
Thanks, Robert. If there are no other questions for Karl, we'll end energy there. Thanks very much, Karl. With that, Don Marchand, our Chief Financial Officer, will join us. Don will kind of wrap things up from a financial perspective and give you an overview of where we come from and where we're headed on that front.
There we go. Good morning. As Russ was reminiscing about going back 15, 20 years ago, it occurred to me, I think the last time we were trading through 14 times earnings, carbon was legal, marijuana wasn't, and I think the Spice Girls were on their inaugural tour. I'll spend the next 20 minutes or so, talk about where we are today, where we're going, where we've been financially. Just as an overview, frankly, operationally things have never been better. Our opportunity set is fantastic. We are about to bring CAD 10 billion of assets into service here. That will help underpin the 8%-10% dividend growth here through 2021, get our credit metrics to a point where we're into the high fours on debt to EBITDA, and an important step in getting back to our historical living within our means doctrine.
We remain laser-focused on share count and per-share metrics. With CAD 36 billion on the roster right now, projects are ready to continue this growth trajectory into the future. As I work through a presentation here, a couple of key assumptions. Canadian dollars, unless otherwise noted, using a currency of 130 to convert U.S. into Canadian. Depreciation on average over 40 years, so about 2.5% of gross PP&E. In terms of Coastal GasLink, we expect to be bringing in joint venture partners and have our ownership interest in the 25%-49% range. For illustrative purposes today, we're using 25% here. We will incorporate in here as cash funding of the project at those levels, effectively proportionately consolidating Coastal GasLink at 25%.
With that, as I usually start out with the financial tenets here, they get refined from time to time, but seem to go in and out of vogue. We don't chase flavor of the day. These really haven't fundamentally changed in about 20 years. Firstly, we invest in long-term annuity streams and regulated franchises backed by solid industrial logic. The second bullet point here, we have gotten a little more explicit with this this year in terms of balancing capital allocation and focusing on per-share metrics. We finance our long-term assets with long-term capital. Our debt is predominantly fixed-rate and long-dated. Effectively what we're doing is we're capturing a spread. We lock in revenues for 20, 30 years or regulated revenues. We finance it with long-term capital, capture that spread, repeat, repeat. We preserve our ability to act at all points of the cycle.
We never want to let short-term events impact our long-term prospects. As we've seen over the years, smiles can turn to dental records fairly quickly. A credit is an important component of that. We do value an A credit rating. We were disappointed with the actions earlier this year. That said, we will work to maintain those metrics, balancing shareholder interests with debt holder interests as we've historically done. We remain quite conscious of changing metrics and moving goalposts, however. We believe in simplicity and understandability of corporate structure. This has been a hallmark of the company for many years. We rarely see value in adding complexity to our structure. Some of you may use it as a hazing ritual for junior analysts, but we tend to keep it simple. We have one public LP. We tend to finance from the center.
Where we do finance at the asset level is really in four spots. One is at FERC-regulated pipes, which is a necessity for rate-making purposes. Then we pointed to three other areas where we have or will consider essentially asset-level or project financing. One is Bruce because of its unique nature. West Coast LNG projects, we'll pursue that for Coastal GasLink. The other one potentially is Mexico. If we do decide to cap political risk there at some point, we may consider that down the road. We like to build things. We tend to build low-risk stuff at an EBITDA multiple of 7x-8x . Then it's valued at higher metrics once it's completed. That's a good value proposition as far as we're concerned. We do buy things, and the tendency there is to do it when there is strain in the marketplace.
Thought it'd be useful to do a quick look back on where we've been since the transformational Columbia acquisition, which is about 2.5 years ago. Since that time, Columbia's fully integrated. We have captured the synergies we set out to capture. Merchant assets were sold. We added significance of more debt capital to our balance sheet. Over the coming months here, as we bring CAD 10 billion of assets into service, we will be de-risking the capital program, the execution risk of that that we took on at that time. We've maintained a simple structure. We bought in Columbia Pipeline Partners, and we retained 100% of Mexico, which is something we had contemplated selling down. The base business today, Columbia and TransCanada combined, is generating record results.
I think that underscores the value of pipe in the ground, as has been alluded to earlier in a couple of my colleagues' presentations. Having right of way is just invaluable in an environment where it is difficult to build anything anywhere. Having that pipe in the ground in the right places is very beneficial to us. We've actually seen assets that were considered stressed at one point, Mainline, GLGT, ANR, Portland, actually filling up full or actually, in some cases, expanding here. U.S. tax reform, as we outlined early this year, was not a major issue for us. Mildly positive to earnings. Mildly, and I stress mildly, negative to cash flow and EBITDA. Really no impact on coverage metrics. We're talking rounding errors of point ones here. No impact on financial flexibility.
FERC actions were impactful to our LP, although less so than initially envisioned, not material to big TransCanada. We've added CAD 18 billion of projects to our roster, I'll go through that here in a few minutes. As well, I'll touch on funding, portfolio management, and interest rates here in the next couple of slides. Looking back at 2018, our funding program is complete. Total needs were CAD 16.2 billion. CAD 2.8 billion was in the form of paid out in dividends and distributions, particularly in our Pipe LP. About CAD 10.5 billion of CapEx, about CAD 2.9 billion of debt maturities. The funding is on the right-hand side here. Funds from operations should come in at around a record CAD 6.4 billion this year. We raised CAD 6.1 billion of long-term debt. Average term was 22 years, average coupon of 4.6%.
We have used cash and CP to fund about CAD 700 million of our needs this year. We have the dividend reinvestment program running. It will generate about CAD 900 million in 2018, seeing about a 35% participation rate there. We issued CAD 1.1 billion of common equity under our ATM program. We do view that as complete at this time, the average price that was issued at was CAD 56.13. We sold Cartier Wind for proceeds of CAD 630 million, we will receive CAD 400 million of pre-FID cost back from the LNG Canada partners near the end of November as a reimbursement on Coastal GasLink. We will exit 2018 having funded CAD 57 billion of capital needs since the beginning of 2016. This should qualify as some award for humanitarian relief to the banking sector, probably the right trade in 2016 would've been to go long Lucite futures.
CAD 57 billion is shown on the left-hand side here. CAD 8 billion was in the form of dividends and distributions. CAD 26 billion was capital program. CAD 8 billion was debt maturities. We spent CAD 15 billion acquiring assets and companies, $10.3 billion on CPG, $900 million on CPPL, as well as the Ironwood Power acquisition, which was subsequently sold to fund CPG. Moving through how that was funded, funds from operations was CAD 17 billion. We issued CAD 15 billion of long-term debt, average of 17 years at a coupon of 3.98%.
We did take the opportunity through the cyclical low here of interest rates to term out. That's, in our view, a fairly attractive coupon for the term we achieved here. About CAD 6.5 billion was in hybrids and preferred shares. We issued CAD 5 billion of hybrid securities, which we received 50% equity credit for at a 528 pre-tax coupon there.
That is at about, pref and hybrids are at 15% of our capital structure, we have maxed out our issuance over the years to maintain that at 15%. CAD 2 billion was DRIP, CAD 1.3 billion was ATM. Just stress that the DRIP and ATM in the context of CAD 57 billion of requirements was more fine-tuning to make sure that we were achieving targeted credit metrics and the like here. Neither is a permanent feature of our funding program. DRIP is only run periodically. We had it on in 2007 when we acquired ANR and turned it off in 2011, reinstituted that when Columbia was acquired. The ATM only ran from the fourth quarter of last year until it was shut off in August of this year. We did issue CAD 8 billion of equity in 2016 in two tranches.
One on announcement of the Columbia acquisition, another in the fall of 2016 when we made the decision to retain 100% of our Mexican operations, as well as buy in CPPL. There's CAD 7 billion at the far right here in terms of portfolio management. That's the sale of our Northeast U.S. power assets, Ontario solar facilities, Cartier Wind. We did do a drop-down into our LP in 2016, and that's project recoveries on PRGT and CGL of an amount of about CAD 1 billion included in that figure.
This chart shows the results of the dual track that we've been on in the past couple of years here, where we're simultaneously improving the balance sheet as well as prosecuting a record capital program here. You can see on the left-hand side, debt to EBITDA, which is the principal credit metric people are looking at these days, is trending on plan back to the target that we have of the high fours, and we will achieve that in 2019 as CAD 10 billion of assets come into service and we start converting AFUDC income into actual cash flow. On the right-hand side, you can see the trajectory of EPS over the same timeframe.
I would point out that the EPS, in our view, is of higher quality as we have exited merchant power assets and converted back capital into regulated and contracted pipeline assets, as well as secured an incumbency position in the Appalachian Basin. The next couple of slides illustrate the strength of the left-hand side of our balance sheet. We would view our asset base as never having been stronger, more diversified, more predictable, and longer duration. I think this is something that differentiates the TransCanada story right now. What's on this chart on the outer ring indicates our EBITDA and our 2018 estimated EBITDA by business line, and the inner circle is by country of origin for that EBITDA. The keyword here is diversity. What this also highlights is our ability to rotate capital as opportunities cycle from one business, one geography to the next.
We're not really beholden to one specific business line or one specific geography. When you add in the ability to build or buy things, we don't really have a bias or predisposition to force capital into one specific sector at any point in time. I think you see that through where we are today, where we've had a significant build-out in Mexico. It should taper off for a while, but we are seeing significant opportunity in Canadian gas and about to embark on a Bruce refurbishment program. It gives us comfort that there are many places to put capital at any point in time. Again, we're not beholden to one specific marketplace. This breaks down 2018 EBITDA in a different fashion here. The outer ring is by commercial underpinning, and the inner ring is by currency.
The takeaways here is that 95% of our EBITDA is contracted or regulated. The 5% that is subject to volumetric or commodity risk is broken down as follows. About 4% is volumetric risk, and that is primarily short-term contracts, spot movements on the Marketlink portion of Keystone south of Cushing, Oklahoma. On the commodity side, it's about 1%, and that is our cogeneration and non-regulated gas storage assets in Alberta. About 60% of our EBITDA is now denominated in US dollars. I'll speak to the sensitivities on the next slide here and just remind everyone that our Mexican business, the revenues are virtually all denominated in US dollars. I'll spend a couple of minutes here on three key financial areas, interest, FX, and income taxes here. On the interest rate side, we would consider ourselves fairly well-positioned for any secular change in the interest rate cycle here.
As you can see on here, our cash flow is fairly immune to movements in interest rates. Our debt portfolio is very long-dated and predominantly fixed rate. We also have numerous regulatory and commercial buffers, including the flow-through of all interest costs to our Canadian natural gas pipeline business. Project sanctioning has never factored in these generational lows in interest rates, we've taken more of a normalized view as we look at sanctioning projects. It is conceivable that in a rising rate environment, our earnings would actually go up as regulated ROEs track interest rates fairly closely, albeit with a lag effect. On the foreign exchange side, we are structurally long and getting longer US dollars. As I mentioned, about 60% of our EBITDA is US dollar denominated. We have $25 billion of US dollar denominated debt and hybrids as a natural hedge to that.
That leaves us long a residual $2 billion U.S. after tax that we then actively manage on a rolling 12-month basis. Today, we would be hedging up on November the 13th, 2019, and tomorrow, November 14th, 2019, as well. We manage that on a rolling 12-month basis to give us some element of predictability and smooth things out. The sensitivities on currency rates for the prompt 12 months, it would take a CAD 0.10 move in the Canadian US dollar to impact earnings by CAD 0.01. Beyond that, it is fairly more dramatic. A CAD 0.10 move in the currency would be about a CAD 0.20 impact on EPS as given our long position in US dollars. On the income tax side, it has been a complex year with U.S. tax reform with a lot of moving parts.
We are benefiting from a higher proportion of our earnings being exposed to lower U.S. statutory rates. If you model up our tax expense, what you do is recommend you take Comparable Earnings , remove Canadian rate regulated businesses and Canadian gas pipes, which accounts for taxes on a flow-through basis, and remove equity AFUDC, and apply a mid-teens tax rate to come up with income tax expense. In terms of the split between current and deferred taxes, we are under 50% current tax rate now. That should migrate to above 50% here in the coming years as our tax shelters move around. The rails on that are about 40%-60%. Gravitating to slightly higher current tax, but again, within that 40%-60% barrier there. That will fluctuate around with bill programs and tax planning activities. Turning to our capital program.
In an era where growth is difficult to find and arguably frowned upon at some points in time, I am not sure whether to tout this or apologize for this, but we have CAD 36 billion of highly attractive growth opportunities, as outlined here. We have spent about CAD 12.5 billion to date on funding these. This roster has grown significantly over the past year as we have added Coastal GasLink, Bruce Unit 6, the NGTL 21 and 22 expansion programs, and we have also included three years of maintenance capital on this chart now. The dramatic change YoY. We expect about CAD 10 billion of these projects to come into service here in the coming months, so this roster should actually shrink.
The characteristics, similar to past years, it is a very diverse set of projects here. They are virtually all contracted or regulated. We describe them as small to mid-size with fairly normal permitting processes, with probably the exception of Coastal GasLink on here, and a proven ability to replenish this portfolio. In terms of commercial underpinning on the chart on the far right here, about 60% of the EBITDA from this growth portfolio would be subject to FERC or NEB jurisdiction, so FERC and NEB pipes. About 38% is contracted for at least 20 years, in some cases, substantially longer, as in the case of Bruce, and only about 2% is aside from that, and that is really non-recoverable maintenance capital that is included on that chart.
I would just note that even under the FERC and NEB portions of this pie chart here, the Columbia Gas growth projects generally are backed by 15-20-year contracts. And NGTL's contracts range from, I think, 7- 107 years. We actually did see a 107-year contract bid in to some of our capacity this year. In terms of the CapEx profile through 2021, it is outlined on this chart here. It is coming down to more normalized levels. We have seen a fairly elevated CapEx program the past couple of years. I think it was CAD 9.5 billion in 2017, and it will come in about CAD 10.5 billion this year. In total, over these three years, it is CAD 18 billion. Capacity capital is CAD 12.4 billion of that. Maintenance is CAD 5.1 billion.
We have about CAD 500 million of capitalized interest in here at a rate we would describe as in the low fives, and minor development costs on major projects, which are more of a rounding error here. Two things to note in here. Coastal GasLink, as I mentioned, we have used 25% ownership as an illustration for Coastal. That translates to about CAD 1.4 billion of Coastal GasLink CapEx over this time frame in these charts. Maintenance capital is running at about CAD 1.7 billion per annum over this period. That is about 1.7% of gross PP&E.
We highlight once again, about 85% of that maintenance CapEx is recoverable, and either through tolls or our ability to earn a return on and of that capital through our rate bases. It is elevated at the current time, given the usage of our assets. We have seen some class changes, particularly in the U.S. gas pipes.
We've seen some accelerated maintenance capital programs on ANR and NGTL, and some new regulations coming into force, such as the new methane rules here in Canada. We would expect after this period that maintenance capital should normalize in around the CAD 1.5 billion per annum area going forward post 2021. How are we going to pay for that? On the far left-hand side shows capital needs of about CAD 28 billion over this three-year period. CAD 10 billion would be dividends and distributions, and the CAD 18 billion of capital from the prior slide. Moving to the middle box here, funds from operations should be in the CAD 21 billion area. We would note that is above the CapEx number on the far left-hand bar chart there. We have CAD 200 million-ish in here for the January 2019 dividend reinvestment plan.
That dividend was declared on October 31, the DRIP will actually run into the first quarter of 2019 with certainty. That leaves a capital markets requirement of about CAD 6.8 billion in the far right-hand bar. That will be comprised of about CAD 2.5 billion of incremental senior debt, and that is keeping in line with our target metrics of high fours debt-to-EBITDA and minimum 15% FFO to debt. We have CAD 1.3 billion in here for hybrids. That's $1 billion U.S., CAD 1.3 Canadian, to maintain that at about 15% of our capital structure. We have about CAD 3 billion in the purple, which would comprise of other. What's not included in that is any further ATM, no LP drop-downs, and no discrete equity. That other chart or that other bar would be comprised of two principal things. DRIP, potentially beyond Q1.
We will look to turn off DRIP as soon as possible, but it has been a necessity here for three main reasons. One, we've had new projects added to our CapEx. We are investing more in our balance sheet to push debt-to-EBITDA through 5% and down into the high fours. Three, we have experienced some cost overruns, which, despite some of the regulatory delays and whether we've encountered that is still on us, so we are having to fund that. It is, again, not a permanent feature of our funding programs. Portfolio management, however, will become a more commonplace portion of our funding. We will continue to evaluate all share count growth against incremental portfolio management activities. We have identified about CAD 500 million of contracted EBITDA as assets that comprise that as potential viable portfolio management candidates.
I would just note at any reasonable multiple, that would dwarf the purple box on here. As usual, there'll be no pre-announcement of these processes, and you should not take silence as an activity in the background right now. Should Keystone XL proceed, as I mentioned on the third quarter earnings call, we will pursue an all-of-the-above strategy to fund Keystone XL. Portfolio management will play an important role in that. We don't see a lot of senior debt capacity through KXL construction incremental to what's already in the plan here, given where we want to be with credit metrics. KXL would bring some hybrid capacity as the balance sheet grows. About 15% of any balance sheet growth, we would look to fund with hybrids. Some permutation of equity will no doubt be required, whether it be DRIP, ATM, or discrete will be a game time decision.
We will also consider JV partners for KXL. We have not landed specifically what percentage or what structure we would look at, but we are absolutely open-minded on that front as well. We will engage all of our rating agencies in our contemplations as we craft a finance plan for KXL. As always, we value their views, and what comes back from that will inform our decision on how to proceed going forward. On this chart is our maturity profile over the next three years. This is on top of the funding needs on the prior slide. In here is about $4.8 billion U.S. of maturities and another CAD 850 million of Canadian dollar-denominated maturities. On a CAD equivalent, it's just over CAD 7 billion over this timeframe, which is fairly normal course for us. I would note that we would consider our upcoming U.S.
CAD 1.15 billion January maturities largely being pre-funded right now, with cash on hand. We would see our needs over this timeframe from a refinance perspective in the CAD 5.6 billion area. The average coupon of this maturing debt is 4.9%. I think fairly consistent with where current market levels are at. When you look at the CAD 2.5 billion of incremental debt and the CAD 5.5 billion-CAD 5.6 billion of refinance debt here, probably over half of that will be designated as rate base with flow through to primarily the NGTL system as that rate base grows. Liquidity is strong. We have CAD 10+ billion of committed credit facilities. We always have shelves in place which expedite access to market, and we have very well-supported commercial paper programs on both sides of the border, and we're funding at LIBOR plus 20 basis points.
I think this was initially in Russ's slides. Just need a little more granularity on this. This is our EBITDA build from 2015 through 2021 as we progress CAD 36 billion of projects through to completion here. You can see the growth from CAD 5.9 billion to CAD 10 billion in 2021. That represents a 9% CAGR. Again, you can see the diversity by business. Again, I stress 95% of this is contracted or regulated. I'd also note that excluded from this is CAD 650 million of EBITDA that we've effectively sold through our U.S. Northeast merchant power assets, Ontario solars, and Cartier Wind.
That has disappeared from 2015 through to 20-- It was in the 2015 numbers, but is not included, obviously, in the 2021 numbers. EBITDA through the first nine months of this year is CAD 6.1 billion, which actually is higher than full year 2015, despite those asset sales.
As a data point, we tend to convert EBITDA to cash in about the 70%-75% range. If you're looking at cash conversion of EBITDA, it's in that range. I'd also just highlight a caution to just blindly taking EBITDA as a valuation metric because there are some unique vagaries with respect to our Canadian regulated pipe business. If we end up paying more tax or higher financial charges in our Canadian flow-through reg pipes, our EBITDA can actually go up, but it's probably not the right reason for EBITDA to go up. As you're looking at EBITDA, just something to bear in mind that Canadian flow-through accounting is a bit unique. We reaffirm 8%-10% dividend growth through 2021. As Russ mentioned earlier, this is underpinned by earnings and cash flow consistent with the way we've operated for the past 20 years.
Payout metrics are in line with historical measures, probably 80%-90% of earnings, Comparable Earnings , which equates to about 40% of cash flow. In terms of DCF cover, we've changed our definition this year. Not changed it, we've just gone to one definition where we exclude only non-recoverable maintenance capital, and it is 2+ times over this entire timeframe in terms of DCF coverage. This chart depicts the long life, high quality, and low variability of our cash flow streams. It's a depiction of what we've effectively, in our view, locked in out to 2025. What's assumed in here as we complete our CAD 36 billion capital program, plus incur maintenance capital over this timeframe. It includes normal course recontracting of our U.S. gas pipes, but does not include any growth wedge that would come from financial capacity over this timeframe.
Highly predictable, quite diversified, and 95% contracted regulated through the piece here. The challenge is to sensibly deploy this capital into new projects. We would certainly like to convert the gray uncontracted piece at the top of the chart there, which is largely market-linked volumetric risk into long-term 20-year contracts on KXL, if we're so fortunate as to do that. The other challenge is to make this look hard for compensation purposes. To wrap things up, bit of a convoluted picture here, but this is a time-tested business model. Working top to bottom here, we feel we have best-in-class, left-hand side of the balance sheet, and a very long-term, well-capitalized business on the right-hand side of the balance sheet.
That drives long-term EBITDA cash flow earnings, which 95% is contracted, regulated, and provides us with a fairly substantive and predictable pool of capital, which we can allocate in our traditional fashion of paying a growing and sustainable dividend and reinvest in our core businesses. As Russ mentioned, we've found CAD 85 billion of stuff to do since 2000. We have line of sight to CAD 50 billion of opportunities right now, and we have five platforms that are very well positioned for growth going forward. If we run out of intelligent things to do, we will look to accelerate the return of capital to the shareholders, either through increasing payouts or shrinking the balance sheet, and we would do that in a proportional fashion to maintain our targeted credit metrics.
We are poised to return to our living within our means doctrine here, as well as deliver, in our view, a third consecutive decade of double-digit TSR. Before I turn it over to Russ to wrap things up and lie on the couch and talk about share valuation, I would be happy to welcome your questions.
Jeremy.
Jeremy, JPMorgan. Just wanted to talk about the leverage a bit more, you talked about upper fours kind of being the right level for TC Energy as far as what you're targeting. I'm wondering if you could expand a bit more as why you think that's the right level versus something more, versus less, and how the agencies think about that and how you guys stack up versus peers. Maybe your risk profile would be helpful to go see what goes in that thinking.
Yeah. We have nuanced that from targeting five times to high fours. I think we are certainly conscious of the market's views on leverage, both the debt and the equity side, and that's something we could certainly drive to. We think there is value for all stakeholders in going to that spot. In terms of the rating agencies, they all calculate their metrics differently, but I think, certainly as we drive that ratio down, there's a comfort level there. This is not dictum by them, but we think this branches up with that on all fronts. Yeah, it's something we consciously decided we want to invest into our balance sheet and bring those levels down to the high fours. In terms of the right level, I think you have to look at the left-hand side of the balance sheet again.
We do believe we are different when you look at just the quality of the asset base, the longevity, the predictability. We do see others in our sector looking at 4.5, 4.25, four times in some cases. I think you do have to differentiate between the asset bases. From a TC Energy self-assessment perspective, we think this is the right place to be.
Kind of a similar type of question with the range for dividend growth being 8%-10% as a target now. What makes that, I guess, the right level? You talked about certain payout ratios that you're looking to target, but I guess, how do you think about that over kind of multi-year time periods, longer time horizons and just kind of-
The balance as far as maybe what the market preference is, how they might change over time.
Yeah. It will move in lockstep with earnings and cash flow growth. We do see 8%- 10% as something that is affordable, achievable, and within those payout metrics over the intervening period here through 2021. Beyond that, we'll see how it plays out. We're not making any commitments. It will depend on earnings and cash flow growth post 2021, and there's a lot of moving parts in our opportunity set right now. We'll assess that as we get closer and closer to then, but you should not see us stray from those long-term payout metrics or this commitment to tying dividend growth to EPS and cash flow growth.
Thanks.
Thanks, Jeremy. Go ahead, Rob.
Hi, Rob Catellier from CIBC Capital Markets. I have a question on the ATM, and then I'll have a quick follow-up. It seems with the Q3 messaging and here again today, there's a renewed emphasis on managing the share count growth and all things related to capital discipline. I'm wondering under what circumstances that might change. You partially answered the question already, but what I'm thinking about is there more than just price in terms of how this ranks in your financial options? Has the experience with the ATM over the last year caused you to reconsider the agency issues and the share count growth and things of that nature? Is it as simple as the other options are just more attractive, such as the portfolio management?
I wouldn't describe it as a newfound focus on share count growth and per-share metrics. It's always been there. I think we're just being a little more explicit. We've always thought this way. Why the ATM? As you look back, we had CAD 57 billion of stuff to fund, and it was just one of the tools that we had, one of the arrows in the quiver that we had through that period. Every share we issue has to be serviced in perpetuity. We're conscious of that. It's just not this management team. We will pass that share down to the next management team and the next management team having to service that down the road. It's not an empire-building, let's just make EBITDA as big a number as we can. Everything is done on a per-share basis here.
In terms of how we would assess reinstituting the ATM. When your capital program gets so big, the marginal cost of capital versus the marginal return can shrink to a point where it potentially even goes negative. We are conscious of that. Depends on your opportunity set and what's in that opportunity set. Frankly, we'd like to use share issuances really for transformational events if we could going forward. Portfolio management, we will run the numbers continuously here, try to triangulate between the credit metrics that we want and per-share economics, and not wanting to grow share count. We have been doing that for some time. It was driving the decision to sell the solars, to sell Cartier Wind, and a bunch of other processes that are at different stages of maturation right now. We've actually seen some things disappear.
Right now, the LP drop-down market isn't available to us. We're not sure if that'll ever come back. What I'd also just like to highlight is we never want to be boxed into one means of capital raising, specifically with subordinated capital. We like to have all of these to look at. The prices and the cost of that capital changes continuously here. Sometimes the hybrid market is better than portfolio management and vice versa, but a long-winded way of just saying that we will go to where the cheapest source of capital is at any given point in time.
The second question is just a clarification on portfolio management. You've identified Coastal GasLink as a candidate as well as Keystone XL, if that should reach FID. How about the base Keystone project or Keystone Pipeline, specifically in the circumstance where Keystone XL doesn't make FID? Would you joint venture or sell a piece of Keystone even without Keystone XL making it to FID?
We look at all of our assets all of the time. We do like to own 100% of everything if we could, with some exceptions. Yeah, it is a core asset. I'm sure it would fetch an incredible price on the market right now, but there's a lot of value associated with it, including optionality as we bring KXL forward here. I would say selling a piece of Keystone in and of itself is not something that's on the table at this point in time.
Thanks, Rob.
Sorry, go ahead, Pat.
Might be a related question, Don, here, but just back to the game-time decision on funding KXL. Just wondering, given the attractive build multiple of 6x versus, as you mentioned, CAD 500 million of long-term contracted EBITDA that you could potentially recycle into that project, why bringing in a JV partner or selling down the ownership interest makes sense.
Again, we'll look at per-share economics here and any quantum of equity that might be required. Again, it is early days on this. We need to define what the opportunity would be at this point. KXL is still not there, and we need to see what the conditions are and what they look like, and what we would actually have to sell to somebody at that point in time. That is not yet fully defined. What we're just pointing out here is it is not necessarily just pure equity to backfill this thing, and we're not necessarily going to move our credit metrics to an uncomfortable point to do this thing with debt and the like. We haven't got a firm process running in the background here. Again, we're defining what this looks like.
As we get closer and closer to decision, and we do talk to the rating agencies, we do look at the capital markets and where your share price is and what the appetite for that is and weigh all these things. What we're saying is we're absolutely open-minded on potentially bringing in joint venture partners for this project. Can they help you get it built? We're not sure. We're just not at that point yet of absolutely defining who the potential participants might be and what the structure would be.
Thanks, Don. Sorry, go ahead, Rob.
Okay. Don, just looking at the CAD 10 billion of EBITDA in 2021, is that net of asset sales and the segments that make up the CAD 10 billion, or are those also net of expected asset sales?
It is gross of asset sales that have not been completed or announced at this point. That number could fluctuate. The CAD 500 miliion we'd be looking at would detract from that. That number's probably a little over CAD 10 billion right now. It's CAD 10 billion area. Again, anything we sell in terms of with EBITDA associated with it would come off that.
Just within the funding waterfall, the CAD 3 billion bucket of portfolio management DRIP and hybrids. If you went completely with asset sales, how much would that number need to flex up, just given you're giving away FFO and EBITDA at the same time?
Depends what you get for it. Probably the way to look at asset sales would be, they would all carry debt capacity with them. Anything you get above 5x debt to EBITDA would essentially constitute equity in our eyes, and then we factor in cash taxes as well as any drag that would come from that.
That's great. Thank you.
Thanks, Robert. Go ahead.
Dennis Coleman with BofA. Don, if I can ask, a little further out, you seem to indicate return of capital to shareholders. Jeremy asked about the distribution, but are you indicating that share repurchases could be part of that mix at some point?
It's really if we run out of stuff to do that's not adding shareholder value. We actually did buy back some stock at the end of 2015, early 2016. It was $300 million at a price of $43 a share. Columbia came along. We don't think we're going to run into that for the foreseeable future here. It's more philosophical. If we can't add value by investing in new projects, then we would look at share repurchases.
Okay.
I'd love to be buying you back today.
Thanks. Just another little detail on the asset sales. Sounds like maybe you are working on some things. The timing is obviously what's in play. Is that something you could announce soon or in the first quarter? If you did, is announcing it enough to sort of let you maybe use some short-term borrowings for the agencies to fund it until you close it?
Yeah. I can't really comment on the specific assets or where we are in the processes, because until we get to the finish line, you're never entirely sure, but there is activity in the background here. I think we're a ways away from creating any significant debt capacity. We do have that CAD 3 billion purple bar on the 2019-2021 capital requirements. Until we claw through that, there would be any significant additional senior debt capacity arising from that.
Thanks, Dennis. Any other questions for Don? If not
I think we're there.
Thanks, Don.
Thanks.
Sorry, Russ just rejoined us here. I think Russ would be obviously open to take any last questions you may have for him. Then, Russ, just maybe offer a couple of minutes of closing remarks. To that end, if there are questions for Russ, happy to take them at this point. Seeing or hearing no questions, I guess we'll turn it over to you, Russ.
That's great news. The team took all the hard ones, I get to do the cleanup here. I guess to start with, thanks again for everybody taking the time here today to join us, listen to our story. A couple of closing things here that I'd like to highlight just before we leave. As highlighted earlier today, over the past 18 years, we have invested about CAD 85 billion, I think successfully, into our five core businesses and our three core geographies. As a result, we have transformed this company from a Canadian natural gas pipeline company into a leading North American energy infrastructure company with multiple platforms for growth.
When you look at this chart, you can see the stark contrast between 2000 and today. As I said, today, in terms of key takeaways from what we've heard is our large portfolio of high-quality energy infrastructure assets are generating financial results underpinned by strong fundamentals. In each one of our groups here today, you saw, in each one of our geographies, in each one of our businesses, solid fundamentals that are driving our current financial performance, as well as giving us significant opportunities for continued growth. Significantly, I think as Don showed you, I showed you, and the team showed you their EBITDA. As you look out into the next decade, 95% of that is expected to come from contracted assets or rate-regulated businesses, which allows us to show you a chart like the one that Don showed you out to 2025, a predictable cash flow.
We could run that chart out to 2030, it wouldn't look much different than the 2025 chart that Don showed you. Looking forward, we will continue to advance our CAD 36 billion capital program. As I said, that is commercially secured, that will extend and expand our footprint into new areas and give us new platforms for growth. As they enter service, we expect Comparable EBITDA to grow to approximately CAD 10 billion in 2021, which is a 35% increase from Comparable EBITDA of CAD 7.4 billion in 2017. At the same time, as you heard again today, we will continue to methodically advance more than CAD 20 billion of projects that we have under development. That includes Keystone XL and the Bruce Power life extensions, as well as numerous other organic opportunities that are expected to emanate from that footprint operating across North America.
Based on the confidence that we have in our base business plans, we expect to grow the common share dividend an average annual rate of 8%-10% through 2021. Notably, as we've said, that is no deviation from our history. Our dividend outlook is supported by expected growth in earnings and cash flow on a per-share basis, in line with our historically strong coverage ratios. With approximately CAD 10 billion of projects expected to enter service by early 2019, we are well-positioned to fund the remainder of our capital program in a manner that is consistent with achieving the credited metrics that support our strong credit ratings that we enjoy today. We're on track again to return to our self-funded model that has been a cornerstone of our approach to capital allocation and has produced double-digit average annual total shareholder returns since 2000.
In closing, I would say, given our recent record performance that we're experiencing right now, our outlook for future for growth in all of our businesses and all our geographies, I think we represent pretty good value trading today, as Don said, at approximately 14 times 2018 consensus earnings and a dividend yield of 5.3%. That is at a level that we haven't seen for about a decade. Again, our focus is on continuing to do what we do, which is not worry about our share price too terribly much in the short run, but to deliver growth in earnings, cash flow, and dividends for our shareholder in a sustainable way. We believe that is what will drive long-term shareholder value. That concludes our remarks today. Be happy if you had any other final questions.
If not, we do have a lunch here, which hopefully you'll join us and seek out our management team and ask any questions that happen to be on your mind.
Great. Thanks very much, folks. As Russ has mentioned, lunch will just be next door here, and we'll start momentarily.