Well, thanks very much and good morning everyone and welcome to TransCanada's 2018 Investor Day. I'm David Marietta, 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. It will be followed by Tracy Robinson, Sam Chapman, Karl Johansen and Paul Miller that will provide you with an each of them will provide you with an update on our natural gas pipelines, liquids pipelines and energy businesses. And 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.
Apologize, there seems to be a bit of a delay in the 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 TransCanada with Canadian Securities Regulators and with the U. S.
Securities and Exchange Commission. Finally, a couple of comments on non GAAP measures. We will reference 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 U.
S. 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, and 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. And 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 a result, 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 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 $85,000,000,000 into high quality, low risk pipeline and power generation assets. And today, our $94,000,000,000 portfolio generates about $8,000,000,000 of EBITDA with 95% of that EBITDA coming from rate regulated assets or long term contracted businesses. More importantly, I think at the same over that same period, we built more than just a group of assets.
As you'll see throughout the day, we built this 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 $36,000,000,000 of commercially secured projects that are all expected to enter service between now 2023.
In addition to that $36,000,000,000 of secured projects, we're advancing over $20,000,000,000 of projects under development. And 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.
And based on our positive outlook for the future, strong coverage ratios, we expect grow the dividend at an annual rate of 8% to 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 or internally generate 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 served us well for about 20 years.
In fact, about 20 years ago in this room, I presented a slide that looks 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 think of 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 return since 2000.
The next three slides, I'll highlight where we've invested that and the resulting growth that's come from it. From this slide, over the past 18 years, as I said, we've invested about $85,000,000,000 in the high quality, low risk pipeline and power assets. Through that investment, we have transformed this company from a Canadian regulated But as But 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 2,008, 2010 and finally the Columbia Pipeline and Columbia Pipeline Partners in 2016 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. And while we 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 $1 per share in $2,000 to nearly $4 per share today and cash flow per share has increased from approximately $2.50 per share to more than $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 $0.80 to $2.76 per day and 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 $16,000,000,000 to our common share holders over that period of time. We have maintained a strong coverage ratios while doing that with our current dividend representing about 75% comparable earnings on a 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 $10 in 2000 to approximately $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 7 75% over that period. In contrast, the TSX and S and P 500 generated returns of less than 200% in the same period. And 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 $100,000,000,000 We have our own interest in about 91,000 kilometers or 56,000 miles of natural gas pipelines that moved 25% or 1 quarter of North American's demand from the continent's 2 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 653,000,000,000 cubic feet a day of capacity. In liquids, our Keystone pipeline system delivers approximately 600,000 barrels a day or about 20% of Western Canadian's 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 Megawatts of electricity enough to power 6,000,000 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 1st 9 months of the year, comparable earnings per share were $2.82 per share, an increase of 24%. Comparable EBITDA was $6,100,000,000 a 12% increase over last year.
Comparable funds generated from operations was $4,600,000,000 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 by $0.69 per share. That equates to $2.76 per share on an annual basis and represents a 10.4 percent increase over our dividend in 2017. But 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 continue to advance $36,000,000,000 of commercially secured projects, which includes $12,000,000,000 of new projects that have been added to that backlog since the beginning of this year. We also placed approximately $2,500,000,000 of new assets into service including the Columbia Leach XPress system. And by early next year, we expect another $10,000,000,000 of those assets to enter service.
We also advanced over $20,000,000,000 of projects under development, including the Keystone XL System and the Bruce Power Life Extension Program. Turning to our funding, we raised over $8,100,000,000 across the capital spectrum on very compelling terms. In addition to that, we completed the sale of our Cartier Wind assets and we reimbursed a significant portion of our development costs on the Coastal GasLink project resulting in another $1,000,000,000 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 6 key priorities. And again, these are the same priorities that you would have 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. 2nd, we'll improve the profitability of our existing assets by maximizing the revenues and reducing the costs in each of our businesses. 3rd, we'll remain focused on executing our $36,000,000,000 capital program on time, on budget.
And 4th, we'll continue to advance our more than $20,000,000,000 projects that we have under development in a careful and cost effective way. 5th, we'll continue to cultivate a portfolio of low risk organic growth projects that emanate from our existing footprint across North America. And 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 support a sustainable and growing dividend. Well, obviously, we're proud of the history of delivering significant returns to our shareholders. But what we know in the days ahead that our long term success depends on our ability to balance profitability, which is safety and social responsibility.
Above all else, safety is our very top priority. We have a 65 year track record of reliable operations, but 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 0 incidents. That is why we're spending about $1,500,000,000 a year on pipeline integrity and facility maintenance and 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 enabled 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. And 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 $36,000,000,000 of commercially secured projects that will expand and extend our footprint across North America. Our growth program includes a series of projects and jurisdictions where we see relatively normal force permitting and construction hurdles. That includes $31,000,000,000 of natural gas pipeline expansions in Canada, the United States and Mexico, dollars 4,000,000,000 of power projects including the Napanee project here in Ontario as well as the Bruce Power Life Extension Program and about $1,000,000,000 of liquids and other projects.
To date, we've invested about $13,000,000,000 into that program with the remainder to be spent over the next 5 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 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 $5,900,000,000 in 2015 to approximately $10,000,000,000 in 2021. That equates to a compound average annual growth rate of about 9%.
And 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% to 10% through 2021. And 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 $36,000,000,000 portfolio of commercially secured projects, we continue to advance about $20,000,000,000 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, Johansen, I'll provide you an update on all of those projects later this morning. But 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 1,000,000,000 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 a day by 2,030.
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 2 continent's 2 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. And 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. And with the potential for gas fired additions, we see replacements in Alberta, Ontario and Mexico.
And this we are well positioned to capture those kinds of opportunities along our asset footprint. At the same time, we have expertise participate in new forms of generation, have you seen this done in the past, in wind and solar, as well as the attractive nuclear refurbishments at Bruce Power. So 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 ships 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 kilometer pipeline network that moves about 12 Bcf a day 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 kilometer 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 a pipeline 11,000 mile pipeline network that sits on top of the Appalachian Basin. And as you know, that's the continent's largest source of natural gas supply.
On our broader U. S. Gas pipeline network also includes Columbia, Gulf system, the ANR system, the GLP GT 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. And 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 barrels per day of Canadian exports to U. S, Midwest and Gulf Coast refining markets. In Energy, Bruce Power provides a platform, it's the world's largest nuclear facility, generates about 6,400 megawatts 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 over $50,000,000,000 of organic growth opportunities and an Envio 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. 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, Carl, 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 Francois, 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 United States 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 the 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 Carl. They'll provide you an overview of our North American Natural Gas Pipeline business and where that's headed. I'll turn it back to them. Sorry.
Thanks Russ. So as Russ indicated, Tracy Robinson, Stan Chapman and Karl Johansen 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. 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 will 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 Carl, who will speak more specifically about the U. S.
Our business in the U. S. And Mexico. So first, the fundamentals. To put our natural gas pipeline network in a perspective, our assets are positioned on top of 2 of the most prolific basins in North America, the WCSB and the Appalachian Basin.
We have more than 90,000 kilometers 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 BC, and some 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. So 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 2,007. 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 Adventist 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. So there's more gas here that can be consumed in North America.
This means that all of that supply must compete for share in each of the markets. And 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 demand, our consumption in North America. And this consumption is growing.
In 2018, demand on this continent will average about 100 Bcf a day. As we look forward, we see growth driven largely from the industrial sector and from power generation. And in this growth in these areas will be driven to the tune of about 20 Bcf of incremental demand by 2,035. And 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 2,035. So that's growth of about 40% in demand over the next 15 to 20 years.
And it provides our industry with the opportunity to develop a network that can handle an incremental 40 Bcf per day over this time period. Now the basins in North America can clearly respond to this and 2 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. So 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.
And we have 3 systems within the Canadian network with the NGTL system, which sits on top of the WCSB in Alberta and British Columbia, and it effectively serves the breadth of that basin through a network of more than 1100 receipt points, more than 12.3 Bcf a day 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 knit or you can deliver into a sizable local market through about 300 delivery points. And that local market right now averages about 5.5 Bcf a day and it peaks at over 7 Bcf a day 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 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 7 now nearly almost 8 Bcf a day and provides that important link between the basin and our Eastern markets. And we have what will be our 3rd 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 5 joint venture partners took a positive FID on their LNG terminal in Kitimat.
And 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 per day of gas to that facility, and we will be again construction of this pipeline in
January of next year.
Our team has made some leveraging this Canadian network and our connectivity to the U. S. Network to the benefit of both the basin and the markets it serves. And we've done that in three ways. So we've increased the utilization of our existing pipe system to facilitate supply that wants to get to market.
And 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 2019. We have been through a process with the NEB for tools on the mainline between 2018 2020.
We are awaiting a 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 $9,100,000,000 expansion of the NGTL system, a $200,000,000 of expansion work in the Main Line in the East and the $6,200,000,000 build for the Canadian rather for the Coastal Gasoline project. So it's been a very good year. We've been working in the same direction for a number of years now and 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 were up by more than 22% from about 10 Bcf to 12.3 on average. On the mainline, the impact has been even more dramatic now. On the Western mainline, this was an asset that we thought would fall below a Bcf a day at one point in time. But since 2013, flows in the Western Mainline have increased by more than 50% and more importantly, the firm contracts on that system have more than doubled. So 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. And the challenge for the industry and for us is to get that gas out of the Montney and into market.
Market is critical. So we're working on collecting more receipts into the NGTL system, more supply. And importantly, we're connecting that supply to an additional 3.2 Bcf of market access over the next few years. So by 2022, if you look at the intra basin market, we're going to increase our delivery capability within Alberta by 1.3 Bcf a day. 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 supply.
So that market right now is about 5.5 Bcf a day on average. So the addition of the 1.3 will take it to north of 6.5, 6.8 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 a day.
And we'll add another 600,000,000 cubic feet a day to our Westpath capabilities for delivery to GTN. It's going to take the Westpath capability of 3 Bcf a day, 2.8 of which will go down to GTN and
the other
200 we connect with other pipelines in Southeast formed a basis for a $9,100,000,000 capital program on the NGTL system. So this is a very significant investment in this basin and one that will increase our average investment base by about $6,000,000,000 by 2021 to reach a level over $15,000,000,000 And 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. So we'll be building a $6,200,000,000 Coastal GasLink pipeline to provide gas to that facility.
CGL will provide the 1st direct access through the LNG Canada facility to world markets for WPSB gas, and we are very proud and very excited to be part of that project. The coastal gas point is a 6 70 kilometers of 48 inches pipe that will provide initially 2.1 Bcf a day of the basin's gas to the LNG facility and that pipe is expandable to 5 Bcf a day with the addition of some compression. We are in possession of all the permits that we require to build CGL and we have the support of the communities and the First Nations along the right of way. In fact, you heard Russ talk about, we have agreements with all 20 of the elected First Nations along that pipe path and we'll begin construction in January. So you have the 2.1 in incremental delivery capacity out of the basin for CGL and 3.2 in incremental market access from the NGTL system.
That's 5.3 Bcf of incremental delivery capability from this basin by 2020 to 2023. So that's a very strong support for the increase in production that we want to see out of the WCSB. And finally, we have the mainline. The Mainline is that path to get the WCSB volumes into the Eastern markets. Now the Western Mainline has become in this market a strategic asset.
Pipe in the ground with capacity is very valuable. So we're working to make the Western Main Line an effective conduit to the markets in the East, the 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 5 years and 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 the producers had stepped out to take mainline transportation, and that deal has served them very well. We've recently closed an open season for another LTFP. This one is a pull from the Eastern markets. It's an LTFP from Empress to North Bay Junction. It has matching contracts from North Bay Junction into the Eastern Triangle and in some cases through the Triangle to connect downstream with our U.
S. Pipes. We've had a very strong response on this open season, more than 500 1,000,000 cubic feet a day. We're just finalizing these contracts now. And 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 and 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. Now this is in addition to the $200,000,000 expansion we have underway right now to facilitate a growth in volumes down to the PNGTS pipe in the Northeast.
Important feature of this open season, we have for 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 WSB 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.
So we do expect the demand to increase in the East. We have growth expected in Northeast U. S. We know that maritime meets some more volumes as their offshore supply diminishes. And there are a number of dialogues underway in the potential for LNG exports off Canada's East Coast.
So this demand makes that Eastern 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. So you see the 2 of those offset each other. Overall, a very good story.
So let's sum up the capital program on the Canadian pipes. We have $200,000,000 underway on the mainline in Eastern Canada to be completed by 2023. We have that $9,100,000,000 expansion of the NGTL system to be fully in service by 2022. The Coastal GasLink $6,200,000,000 project will be complete and in service by 2023. Our maintenance capital is settling in at about $600,000,000 a year.
And 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. So that's a total of 17,300,000,000 in secured capital expansion and maintenance capital. Now 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.
So as a result, the appropriate final financial metric for this business is net income. Now net income is tied pretty closely to investment base and to our capital program. So that program is going to drive a CAGR investment base of about 8% between 2015 2021 to more than $19,000,000,000 Net income will go by that same pace from about $500,000,000 in 2015 to more than $800,000,000 by 2021. So 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 $1,000,000,000 a year in depreciation out of the Canadian pipe system.
So as we look forward, our priorities are clear. We will execute on what is a very substantial capital program. And 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.
And with 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. So let me finish where I started. The Canadian network is situated on top of a very important base and 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 basins, to our shippers and to our bottom line, our financial results. Very proud of the team and the work that they've done and the work they have coming up. And with that, I'm going to hand the podium over to Stan Chapman and our U. S.
Business.
Thank you, Tracy, and 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 3 things.
1, is that demand for our assets remains strong. 2, that our revenues are underpinned by long term take or pay contracts. And 3, that future growth opportunities are supported by sound market fundamentals. Now 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 in our portfolio of 13 FERC regulated pipelines, which spans across 31,000 miles 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 5.35 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, and we do that by linking 2 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. Furthermore, 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 net to catch growing WCSB production, which is expected to grow annually by about 4% and reach 23 Bcf a day by 2017. While the hyper growth 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 a day 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 a day by 2027. Additionally, exports to Mexico are expected to increase by 5% per year and 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 and I'm pleased to report that we're on track to do just that. Just over $2,000,000,000 of capital was placed in service during the Q1 of the year when our Leach Express and Cameron Access projects went live. During the month of October, we very quietly placed another $650,000,000 of capital in service, which was predominantly linked to our modernization program and the west path of our WD Express project. Subject to FERC authorization, in the next few days we'll close out our WD Express project by placing the East Path in service, which is another $700,000,000 capital investment. And lastly, we expect to be in a position to flow gas on our $3,000,000,000 Mountaineer Express and our $600,000,000 Gulf XPress projects at year end or shortly thereafter.
As an aside, the pictures on the slide are construction photos of our Mountaineer Express and WB Express 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 $7,000,000,000 of capital investments that will be placed in service and will start generating cash flow for the company. 2018 also marked the successful closeout of the initial 5 year $1,500,000,000 Modernization 1 program on the Columbia Gas system and we immediately began work on the 3 year 1 point $1,000,000 Modernization 2 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 Hardie Storage customers, which are currently pending FERC approval and we will continue to make our 501 gs 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 and we are on track to achieve record EBITDA levels. Earlier this year, we set a new peak day send out record with over 30 Bcf sent out across all of our pipelines and 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'll highlight in further detail in a few slides. As production growth continues and new projects come online, we're beginning to see changes in flow patterns across our system.
Most notably, now that our Leach XPress and Rain XPress projects are in service, the turnaround of the Columbia Gulf system has largely been completed as we are routinely flowing over 1 Bcf a day south towards the Gulf Coast. Given that most of our historical growth projects were supply push in nature, we're 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 and we're 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 and 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. Now as I mentioned previously, the fastest growing source of demand in the U.
S. Is tied to LNG exports and you'll 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 Express project. And lastly, our PNGTS and Canadian mainline systems provide key connectivity to serve any East Coast Canadian LNG terminals that may develop. So 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.
Now I mentioned earlier that we are largely winding down and placing in service our historical growth project portfolio, but I wanted to quantify the impact of that for you and put it in perspective. $7,100,000,000 of the $7,400,000,000 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 7.4 multiple of CapEx to EBITDA. But furthermore, you could think of this portfolio as generating over $1,000,000,000 in incremental EBITDA and generating an after tax unlevered return in the upper 10% range. Given the complexities of building new projects today's environment brought on by legal and regulatory challenges and compounded further by an extremely tight labor market and the wettest weather the past 124 years across our construction footprint, I'm really proud of our team's accomplishments.
In addition, our 3 year $1,100,000,000 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 $2,000,000,000 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 $600,000,000 per year. So in the aggregate, you can see that this represents about $10,500,000,000 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 $2,000,000,000 represents the 1st full year of the Columbia acquisition. Year over year EBITDA between 2017 2018 shows the impact predominantly of our Leach XPress and RAIN XPress projects being placed in service as EBITDA for the 1st 9 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 9 years on our 2 flagship pipelines, A and R and Columbia Gas, respectively, as well as the $1,000,000,000 in new EBITDA generated by our growth projects that I previously highlighted. So 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 Carl and I will continue to challenge our collective marketing teams to take advantage of cross border synergies.
Also in 2019, we will finalize our customer negotiations and settlements related to U. S. Tax reform. We will begin conversations with our Columbia Gas customers related to a modernization 3 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. And 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 2nd project listed here in, 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 $400,000,000 capital project is a further expansion of our Columbia Gulf system to serve a credible Gulf Coast LNG export facility and is underpinned by long term take or pay contracts. So 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. So thank you for your attention. I'll turn the podium over to Carl and I'll be around to answer any questions you have afterwards.
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 that. With that, if I put a picture up here first, I just wanted to get people a feel for some of the work we're doing on it in Mexico. This is the staging area for 1 of the onshoreoffshore interconnects for the Sur de Texas pipeline. If you recall, Sur de Texas pipeline is about an 800 kilometer 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. And this is the staging area for those compression facilities. We have 2 pipes coming, 1 coming in and 1 coming out, so to speak. And so the compression facilities, and this is a manmade island that we've put into to put we have drilled a microtunnel, 2.5 kilometer microtunnel here to get underneath the mangroves, get underneath the beaches, which was a turtle hatchery and to get underneath the coral reef.
So we built a 2.5 kilometer microtunnel about 10 feet in diameter, to move these 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 2 pipelines put together. We're going to push 2 pipelines through the market tunnel at the same time. And there'll be 7 of these strings that we ultimately weld up and we push through to interconnect it.
So it just gives you an idea of some of the scope and the scale of what we're doing. This is 42 inches pipe, about 1 inch, 1.5 inches thick in that area, and it's quite a job drilling a 2.5 kilometer tunnel underneath the ocean seabed in order to make it work. I wanted to start just to talk a little bit about Mexico supply and demand. This is the establishment of supply and demand in Mexico is still more, what I'd say, art than science. You have to understand natural gas isn't a very the natural market for natural gas isn't a very it 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 the LP products. They don't use natural gas. Traditionally, natural gas has not been that reliable of a fuel for the industrials. And therein lies the key to kind of some of our growth strategies, which I'll talk about in a few minutes.
So this is we're talking about a market that's going to be, we believe, in the next 10 years or so, about 10.7 Bcf a day. We believe there's some upside to that because we haven't baked in all the industrial opportunities yet. But this is going to be a good demand not only for our pipeline system but also for North American gas going from the United States into Mexico. I think everybody is 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 United States and Mexico and, frankly, Canada as we start moving, I guess, in Canada, the U.
S. And the U. S. And Mexico. You saw those graphs earlier from Russ' and Tracy's talks about our systems.
And really, with the completion of the certain Texas pipeline, which I'll show you in a moment, we can literally move a unit of gas right from Northern Alberta, Northeast BC all the way down to Mexico City now. So we're getting very, very close to being a completely integrated market here. What are our accomplishments over this last year? Well, we are advancing our last few projects 3 projects here in Texas, Tuxpan Tula and Village Re, but a little less than USD 3,000,000,000 in projects. So they are all advancing.
The completion of Cerda Texas 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 comm seas, which we actually, quite frankly, haven't had seen comm seas for the last couple of weeks. So we are waiting for the seas to come down a little bit.
But then once we get that interconnection done, we will be going right to commissioning. So I'm expecting we'll be calling for gas in December sometime. So we'll be we're looking forward to that. That will be the last kind of tricky part of this particular project. The top of Bamba was in full in service this year.
If you recall, we had some issues with some aboriginal concerns of our pipeline running, so we rooted around that community. We got it in service this year, so the top of Bambo now is flowing gas and it completed in service. And I would say for other projects, the Tuxpan to Tula, Village Array, they're both operating under force majeure events that have been recognized by the CFE or customer. And 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. And the Villa Dray pipeline is progressing well. We have run into 90 archaeological sites on that route. I can assure you the 1st archaeological site is pretty exciting.
We could see some pretty new stuff. The 90th is not so much. We've discovered a lot of new settlements and new foundations and whatnot. But the good news is it doesn't stop us from construction. We just have the government has to go through the process to map out the archaeological site, and then they let us go around it.
So 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. So and I would say for this Surgeon Texas, the same thing on the force majeure event. We are as of November 1, we
are getting
paid our full capacity payment for them even though we won't be in service till late December or in January. So what is our position? This is the map that I'd like to show. We have 4 pipelines operating right now. We have 3 under construction.
When you take a look at it, 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 some, what I consider, very solid platforms, very almost franchise like businesses, both on the West Coast of Mexico and down in the central part of Mexico. And then these are areas that we kind of targeted where 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 on or have control of. So we decided to concentrate where the population were, and this is where the population and the industry are. When you take a look at the central part of Mexico, approximately 60% of the population and GDP are from there. And the western side is a very, very highly industrialized part of the country.
So 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. And I think they're well positioned to not only follow the growth in the Mexico economy and the industry, but actually to plow some new ground on natural gas in Mexico.
The industry here, as I said, did not generally use gas. I think our marketing over next little oil is going to be set up to try and get them to convert. From the fuel oils and LP products used 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 of our targets are for it. And these are all these are going to be all bread and butter for us.
Once 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 the fuel wells. But there's going to be a compelling economic story for them. And once we get them, we'll have them for a very, very long time.
And I'd like to remind everybody that even though the CFE has backstopped all these pipelines, all 7 pipelines are backstopped at CFE. We get a good return by the CFE contracts itself. Every time we convert one of these industrials to natural gas and uses our system, we get to keep all that revenue fully for ourselves. So it is a there's a big, big incentive for us to market hard for this industrials and get this gas based on our system. Comparable the EBITDA for our business.
Well, I think the graph kind of says we're going to go from very small 100,000,000 dollars plus back in 2015. We're going to have a 20% CAGR on a 2021, about USD 550,000,000 kind of business. That's just with these projects right now coming in service. And that's without we haven't put any enhancements through the marketing to industrials. And I would say this is not the end of the growth in Mexico.
As you can see, there is some still some gaps in that map. The CFP has slowed things down right now on the new project for a couple of reasons. I want to get everything with land issues that they've had with the aboriginal consultations, even the power plants have been a little bit delayed. So they have slowed it down. We'll let the infrastructure catch up.
Once the infrastructure catch up, we fully expect more projects to come along in Mexico. So we will be seeing I firmly believe we will be seeing things like the Mazaland, the Guadalajara line come one day. And then there'll be other instances where they're going to fill in their grid. So yes, we've seen a very good solid position and 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 see we're going to hopefully continue to grow through our marketing and industrial activities at the same time. What is our key areas for the future? Well, obviously, we have to execute our capital program. We have to figure out with Tuxpan Tula, it's nice that we're getting paid, but we have to figure out how to get around this. We're an aboriginal group.
Either the government's got to finish or 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 again, we want to get some more systems. Flex Band Chula, we will finish that. That's just an just archaeological sites. And of course, Sur de Texas, we're doing our last complicated tie in right now.
So I would say that we have good organic growth opportunities in the business. And we also have some step outs that we can still do outside of the industrial First one is storage 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.
Obviously, as you tell from the maps that both of what I'll talk about in energy and Stan's business, We are one of the largest storage players in North America. And quite frankly, electric transmission. There 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 government. And I would say the government is starting to understand our concerns over the contracts. So you never know. If we can give those contracts to look more like gas transmission like contracts, you'll see us putting in the power transmission business as well. So having said that, I think that so that will conclude the Mexico.
And I think I will open the panel up right now for questions.
Thanks, Karl. So as I mentioned, we're through the prepared remarks on natural gas pipelines. For the benefit of people in the room as well as people on the webcast, we'll take questions now. Chuck, Stephanie and Duane 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 and A.
Go ahead, Jeremy. Jeremy Smith, JPMorgan. Stan, an interesting slide on the LNG that you guys have able to touch there. I'm just wondering how much more gas can you spend to those different endpoints if it does if the LNG continues to expand, particularly in the Gulf Coast, seems like there's a lot of potential expansion there. Yes, great question, Jeremy.
And we'll start with Louisiana XPress, the project that I mentioned at the end. We're going to add 3 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. So in the aggregate, think of that one project alone as adding 850,000 a day of new capacity to LNG export terminal.
So similarly, we have expandability on the Southeast edge station on the AR system. And then when you go over to the West Coast, we could economically expand our GTN system probably to tune of about 0.5 Bcf a day. So in the aggregate across our footprint, it's not inconceivable to think that there is somewhere north of Bcf a day of additional supply that can get these LNG export facilities. That's helpful. Thanks.
And thinking about the system for the REITs, especially New England seems to be particularly constrained and it seems to prefer Russian LNG versus North American gas right now. But how much more could you possibly put into that market
as well given the acute need? Yes.
Tricky part of the world to build in, particularly in New England. One of the good things with respect to the portable natural gas transmission system is we still have about 250,000 a day of what I would call compression expendability. So capacity that we can add to the marketplace without putting new pipe in the ground. And that was a key factor in getting our last project up and down with respect to the porting facility. So somewhere around the quarter would be, I think, could be done economically and with a minimal environmental impact.
Thanks, Jeremy. Ben, go ahead. Sure. Go ahead, Ben.
Perfect. Ben Pham, BMO Capital Markets.
Painted a pretty robust picture
of demand growth in North America, gas wise, high cash flow quality, HFA contracts, regulated exposure. Can you maybe comment on the counterparties side assessment of investment grade versus non investment grade? It seems like no one's talking about it today. 3 years ago, everyone was talking about it. So maybe comment on that and how you think about also the return differences between U.
S. And Canada when you think of the counterparties?
So I can start with respect to the U. S. Business. If you 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 in Leach Express, Rain Express, Mountaineer Express and Gulf Express 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. But our contracts, in thing is that we believe that the molecules are there. The molecules are in the ground to be produced and 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. Now the unique thing about the Canadian system, it's a regulated system. So if we have issues with some of our producers, the exposure is held by the collective in the Canadian system. Now 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, those 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, and 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, but it's the nature of the Canadian regulated infrastructure. You get that regulated risk for a regulated exposure, a return.
I think just to conclude on the Mexico side, the CFE, we're still comfortable with CFE and the government of Mexico risk. So it is maybe when we put new customers on the system, and you saw the mass on the industrial, we'll start getting down on credit quality at that time. But 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. But for the most part, the CFE is still a good credit for us.
Thanks. Rob?
Good morning. Rob Catellier from CIBC Capital Markets. You've mentioned LNG a few times in the presentation. So I'm curious to know how far down the value chain TransCon is willing to go in terms of putting the investment dollars to work and under what circumstances. So I'm referring to what type of contracting you might need there.
And 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 contract portfolios, again, you could think of these as having contract terms of 15 years to 20 years in duration. You can 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 to 7x EBITDA multiple going forward. There seems to be lots of synergies between the LNG export terminals and what we do. And if you look again at the that are going to export multiple DCS a day of gas on a routine basis matches up nicely with all the supply that we've been adding to with our projects over the past 2 or 3 years. But it really is
a pretty symbiotic relationship. So then with that answer, are you suggesting you would be interested in taking an ownership interest in LNG? So 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 long 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 often as equal. Thank you.
This question is 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 interest and what that might mean in terms of regulatory approval?
Thanks, Travis. So I think we are trying to do some of that now in advance of 2020 with our we have 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 Main Line up meaningfully. There still is a certain amount of cross subsidization that goes on back and forth between the Eastern Triangle and the Western Main Line. So as we separate those, 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 Main Line and how we can think about the Western Main Line 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 and the basin a little easier, a little more cost effectively.
Actually, Tracey, are you kind of intimating that maybe you're going to take another run at NGTL Western Main Line Integration or physically or synthetically?
So I think what we're interested is creating cost competitive access to market, right? And 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 service, Robert, that you're talking about. And so 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. So yes, that's one of the options.
Great. Thank you. Thanks, Rambo, 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? So 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 quarter expansions. In the aggregate, we've added somewhere around 6 Bcf a day of capacity and we're only building about 300 to 3 50 miles of greenfield build. So 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. We hear a lot of talk about the Permian and why don't we have a project out in the Permian. And 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 5, 7, 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. And you're likely to be dealing with counterparties that, for the most part, are not known names. So while it's a bit of a white space on a map perhaps, given the fact that we have a $36,000,000,000 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 sake of filling it
in.
Linda Ezergail of TD Securities. I wanted to expand on Robert 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 GMP business. Have you evolved your thinking in terms of do you maintain your interest there?
Do you increase it? Or do you exit?
Yes. Again, I'd just go back to our the comment about our risk I don't see us getting into the production side of thing and we're in 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. Now 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. So still that's when we have a $36,000,000,000 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.
Okay. And just as a follow-up question, 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 opportunity slide?
Yes. So it's a little bit tricky because in some cases, like the Northern Border System, we have a joint venture partner. So I'll give you an 8.8 number. I'm not going to break that ownership share. But in the aggregate, that could be up a $1,000,000,000 to $2,000,000,000 capital investment.
And again, think of those projects being built at a 7, 5 to 7 EBITDA multiple going book. Not all those may hit, but we're certainly going to pursue all them, and we do expect to compete for and win more of our fair share. Puneet Sadeesh, Wells Fargo. This is for the U. S.
Gas Pipe Business. I guess a high level question. I mean, 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? I mean, recognizing you're building at a 7x multiple, but could future projects be done at a 6x? So one of our New York customers actually tried that with the New York State Commission.
And unfortunately, it was turned down. And the notion was for us to come in and develop a project in that part of the world, we're not going to put tens or 100 of 1,000,000 of dollars of development capital at risk. And that's a big challenge. It's a big challenge for anybody to step up and do that. In this particular case, unfortunately, the New York PUC said no, that they're not going to allow the ratepayers ultimately to bear that cost.
So in the meantime, what you're seeing is parts of New England and parts of California paying the higher synergy costs anywhere in the United States. We're getting clear price signals that new infrastructure is needed, but we have regulatory paradigms that say otherwise. Got it. And just one other quick question, just on the potential Northern Border Pipeline expansion. Can you just discuss the, I guess, the logic behind that, how big that would be?
Couple of 100,000 a day in terms of capacity with a couple of different capacity options out. To use a golf analogy, this is a long putt, but we make 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. And so again, you look at the value of the NGLs and 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 Kenny, 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 United States. Now far, we may have a different paradigm in Mexico in the context of given all the slowing production that we're seeing, again Marcellus ramps up from 30 Bcf a day to 44 Bcf over the next 10 years, That spread between summer and winter pricing just isn't there to justify new storage build. So there's so much flowing gas and it's almost virtual storage, 3 65 days a year. So in terms of building new storage facilities, I just don't see that from the arbitrage value. However, on pipes like A and R in Colombia, storage is an integral part of providing service to our LDC customers.
So it's used for liability purposes more so than an arbitrage purpose. Thanks, Matt.
Tom? Tom? Tom Abrams, Morgan Stanley. I'm looking at the Panhandle region and wondering if all the success you're having 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 and Marcellus growing at 6% to 8 percent per year. Maybe Permian hits 12, 13 Bs 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.
But again, when you have growth of about 14% per year, we're growing that pie and there seems to be enough of molecules and enough of demand, particularly driven by LNG exports for everything.
Do you need connectivity though or 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 7 midpoint compressors or thereabouts and turned it into a 3 Bcf a day system that flows north to south. So So once you get to about 40, 44 Bcf, you're probably in relative demand between all the pipes that could be reversed above and beyond that. Yes, you may need a new greenfield line that goes down to the Gulf Coast to serve all the Gulf Coast export facilities. Thanks, Tom.
No other questions and we're running a little ahead of time, which is good. We will break now then for about 30 minutes. So maybe if I could ask the folks return at 10 o'clock and we'll pick up at that point. Again, people are available through the break, so feel free to approach any member of TransCanada with any other questions you may have. Sorry, folks.
Maybe if you wouldn't mind, sorry to interrupt the what I'm sure is good conversation, but 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 Ford. And this is Mark. Yes. Okay.
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 is going to provide you with an overview of that business.
That will be followed by Karl Johansen, who will cover energy a little bit later this morning. And then again, Don Marchand will wind things up with a finance update. So with that, 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.
And 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. And consistent throughout this approach is we target quality, sustainable performance. And this is achieved by securing long term take or pay contracts. This is achieved by securing long term take or pay contracts, and we always strive to maximize our contract volume.
But in many cases, however, we're required to set aside capacity for spot or uncommitted shippers. And because of this, we cite 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 3 primary sources: long term contracted volume, spot volume and activity through our marketing affiliate. So looking first at the contracted volume, our base EBITDA has led very little variability because of these contracts. Keystone is about 94% contracted and the remaining 6% is set aside for the spot shippers.
Market Link is about 80% contracted. Grand Rapids has recovery through a 25 year cost of service model. Northern Courier return of and on capital is fully recovered over the 25 year contract term. And White Spruce pipeline recovery of and on capital is recovered over the course of the contract term. So when we take a look at spot revenue opportunities, the southern end of our system has open capacity and Market Link has benefited from the increase in U.
S. Production, largely driven by light tight oil out of Permian and the Williston Basin. And today, we see a shortage in pipeline capacity in that Cushing to the U. S. Gulf corridor and this is causing the Brent TI spread to move out, and that wider spread encourages spot volumes onto market linked pipelines.
I anticipate this scenario to persist throughout the remainder of 2018 and throughout 2019. So we're responding aggressively to the shortage of pipeline capacity in this corridor by increasing the capacity on Market Link. Market Link has historically run between about 400,000 to 500,000 barrels per day. And when we saw and foresaw this demand for additional pipeline capacity, we started increasing our throughput capabilities on Market Link in late 2017. And this program continued through 2018 and will continue into 2019.
And we're doing this through scheduling efficiencies and the use of Greg reducing agent all at very little cost. And the result of this program is we've been able to increase our throughput capabilities in market linked to the mid-six 100,000 barrel per day range. And I would anticipate in 2019, we'll be able to increase our throughput into the mid-seven 100,000 barrel per day range. Now we have other opportunities to increase this throughput further that does require modest capital, but can be done on a fairly short time frame. So we're monitoring market developments.
We're monitoring the fundamentals, and we'll make the call on additional increases in due course. Now 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. So 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. So our pipelines are located in areas of growth with strong sustainable market fundamentals. And we're seeing this result in our primary pipelines, Keystone and Market Link, which are running full.
The high WCS TI differential attracts spot onto Keystone. The wide Brent TI differential attracts spot onto market length. And our marketing affiliate benefits from these high differentials as well. With committed pipeline capacity, marketing can move product between pricing points and seize this value from these differentials. This multi faceted approach to creating value has served us well and has created strong results.
So we continue to enjoy strong performance from the contracted Keystone system. We brought 2 new intra Alberta pipelines, contracted intra Alberta pipelines into service in late 2017 and they are now contributing 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 to the which is always dangerous because it means I have to then backtrack to the Keystone XL status slide. And I think the status of Keystone XL is top of mind given the court decision we received last weekend from the District Court. Now this judgment was received sooner than anticipated and gives us insights into the suggested deficiencies and the remedies. So 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 continue to 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 Engineer 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. And 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. And 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 combined this volume will provide a return to TransCanada on total capital invested since 2,009 consistent with projects of a similar nature. Now it's important to remember our commercial model in XL has not changed materially. All historical costs plus AFUDC since 2,009 are captured for total 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. So 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. And the first step will be to move those contracts, which currently flow on the system down to Cushing and the U.
S. Gulf Coast onto the Keystone XL leg. And what this does, this frees up space on the legacy system. And with that freed up space, we have a means today to contract up that space with new long term 20 year contracts. So what you'll end up is 2 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 Patoka. And you will have an integrated system with about 1,400,000 barrels per day of long haul capacity from Alberta, which will be underpinned with approximately 1,200,000 barrels per day of long term contracts, the majority of which will be new 20 year
contracts.
We're pursuing many growth opportunities one slide behind, sorry about that. We are pursuing many growth opportunities besides Keystone XL, but Keystone XL will accelerate some of them. And 3 of note are within our intra Alberta system And each of these projects are fully approved by the regulator. So Grand Rapids Phase 2 is a fully permitted pipeline. It's a looping of 460 kilometers of 36 inches 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 $900,000,000 investment, which will connect those market hubs of Edmonton and Port Saskatchewan down to Hardisty. And the Keystone Hardisty terminal is a fully permitted $300,000,000 2,600,000 barrel facility, which will provide long and short term contract storage as well as batch accumulation facilities for our shippers. We are progressing 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 bales 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 resource production from their Horizon facilities into the Grand Rapids system. In Cushing, Oklahoma, we were in the final stages of commissioning an additional 1,000,000 barrels of storage, and we have started the development of additional storage at our Houston tank terminal. So 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.
And 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. And it's a similar story south of the border.
There is increasing production of U. S. Crude oil driven largely by light tight oil under the Permian and Williston Basins. And the U. S.
Demand for light oil is largely satisfied, so much of this product is finding its way to export markets.
And 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.
So 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 light balance to maximize returns. Our highly contracted pipelines provide quality, stable cash flow. Our assets are cited around strong market fundamentals, which provides upside opportunities from spot barrels and our marketing affiliate Caesars 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. Rob Hope, Scotiabank. Not surprisingly, the first question is on Crete Semicel, but I'll leave the regulatory stuff to someone else.
Just taking a look at the 6 times EBITDA build multiple, can you give us some additional color on 2 parts, I guess, one would be the incremental capital to go there. And then secondly, whether or not there'd be any knock on effects on EBITDA related to Market Link and Keystone 1 and if that 6 times 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 the project of this nature.
We do have some of the activity in from contractors, etcetera. But with some of the outstanding court cases, where 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. So no visibility yet, but we'll provide that in due course. In regard to sort of 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 Kirschine. So that will be captured in that incremental capital. So really, the primary build is pipeline build about 1800 kilometers 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. And then 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 be 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. And 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. But as far as timing around the pipeline, the need for Keystone XL has never been greater. When you're looking at $40 to $50 differentials on WCS versus TI, 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. Sorry, other go ahead, Pat. Just to follow-up on that thought there, Paul. So 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 time frame?
Thanks, Pat. We do have a cost sharing mechanism with the producers, and thank you for that. I forgot to mention it. Our capital cost in our commercial model, our capital cost variances are shared equally with the shippers. And we have today, development a formula for development cost risk sharing with the shippers for the next phase of activity.
Sorry, go ahead, Puneet. Yes, 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 show the various emerging basins, whether it's Niobrara, whether it's Williston, whether it's Permian, we are well situated around those basins.
And 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. But we have folks on the ground taking a look at the opportunities. And they're very good opportunities. They're strong fundamentals.
They're growing basins. And 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. Any other questions for Paul?
I realize your plate is 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. But 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. Our refined product is in our scope.
It is something that we think about. It's something that we look for. And again, we will develop those opportunities consistent with our risk preferences, seeking out the long term opportunities. We view our liquids to be the our area of focus. We're not going to get into upstream production.
We're not going to get into downstream refining and processing. But 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 Johansen again. Karl is going to provide you with an update on our energy business.
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 both 1995 to 1996. And in those days, we had a couple of very small plants interconnecting, taking heat off of our mainline system.
And it's been quite an interesting ride with this business. It's been since that time, we have actually built it to be one of Canada's largest privately owned power companies. And notwithstanding the fact that we've recycled some capital over the last couple of years, it is still at about 6,600 Megawatts, 1 of the top one of the largest privately owned power companies in Canada. So 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 fifty-fifty nuclear and natural gas, which is, I think, pretty good carbon footprint for this business.
There we have some of the obviously, I'll talk a little bit about our nuclear position and Bruce in a minute here. But our gas fleet is one of the most modern efficient gas fleets in Canada and in North America, as a matter of fact. And it is we run the spectrum from peaking plants to several cogen plants in Alberta and Quebec and, of course, efficient combined cycle plants in Ontario. So 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 one of the pillars of this company.
And that's and it is an important part when you match it with our natural gas business and the rest of what we're doing is an important part of those businesses. Just to take a look what underlines what we have in the Power business. And 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, we 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 19 to 2,064, which is which will be kind of the end of what what our current agreement is with the nuclear refurbishments we're doing.
So a very, very, very solid long term contracted portfolio. This is, I think, quite frankly, what makes us 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 to opportunities where some people maybe value the cash flows more than we do, which is why you've seen some of the circulation of the capital over the last couple of years. But this is a very, very highly contracted portfolio. And quite frankly, the 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 kind of what Naphony and with the refurbishment of Bruce and them. But we still are generating solid results. We're still seeing good growth in this business even though we have cycled some capital, though. Our construction programs are progressing.
The Dampani power plant, almost 1,000 Megawatt 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 90 2% to 95% constructive on that plan now, about 60%, 65% commissioned.
So you will see in the first quarter here, we will finally bring that online. And that again, it's a Mitsubishi five zero one gs machine. It's a 2 on 1. It will produce about 1,000 megawatts, just a little less than 1,000 megawatts of capacity, and it will be
a good
flagship for the business as soon as we get that up and running in the Q1 here. We're advancing Bruce Power life extension program. Beginning at 6, 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, and I'll update that. And closed the sale of Cartier Wind this year for $630,000,000 which will help our capital our funding program and our capital program and close 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.
I'm going to talk about we're left with 2 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. But I think as thermal power goes, as thermal power generation goes and nuclear power goes to Ontario, these are 2 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. But 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. And I think this speaks volumes as to the health and the future of the assets that we have.
Now most of our assets, as you see from the earlier slide, are contracted for very long periods of time, but you can just see the supply deficit coming in Ontario. And many people may not realize that this deficit is on the horizon because of the overbuild we've had in renewables and so is on the horizon because of the overbuild they've had in renewables and so forth. They've I think it's masked underlying thermal deficit in this market. This deficit is coming from a couple of things. Number 1 is we're going to lose a nuclear a nuclear plant shortly with the Pickering plant.
Number 2 is we're going to lose parts of the other nuclear plants. Bruce is going to start having starting 2,000. Bruce is going to start having units out, and Darlington has units out right now. So when you take a look at what's going on in the nuclear space, the refurbishment program, both OPG and ourselves, is adding to the staff asset. 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.
So 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 end 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. Navdy Generations facility, I think I talked a little bit about that before. Again, when it does get commissioned fully in the Q1 of this coming year, we will be 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, and 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.
So 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. And total capital cost of $1,600,000,000 And again, we'll have a very long dated contract from the ISO behind that. Bruce Power. I'm interested in a couple of minutes on Bruce Power. I think this is not only kind of our biggest asset right now, but it's also the one that I think we're in the power space, we got a long term commitment on.
This plant right now is 6,400 Megawatts. It's about 30% of Ontario's needs for electricity comes from this one plant. It is our ownership is slightly less than 50%. We're with the owners here. And of course, the remaining percentage goes with the labor unions.
And we have recently, over the last couple of years, completed a contract to refurbish Units 3 through 8. If you remember, Units 12 were refurbished a few years ago. They're up and running now. We have finished that job, and they will be they're able to start their life cycle again. 3 through 8 need refurbishment in order to carry on.
So with that contracting came a contract for that capacity through to 2,06 4. 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, 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 into life cost.
The investments through the life extension through Units 3336, our percentage of it is about $8,000,000,000 $2,200,000,000 is for the 1st unit to go into refurbishment, that's Unit 6. And that will be $2,200,000,000 until 2023, which will be the end of that refurbishment. So it is a good sizable investment that will happen over the next 12 years, 12, 13 years. As we put it, we'll do 1 unit at a time. And it is a 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. So we're in good shape on our licensing. I always get asked questions. What is different with this refurbishment than 12? For many of you in the room, you probably watch me and other people up on this podium talking about the stresses we have on 2.
It was over budget. It was late. It was quite a difficult refurbishment. I believe this refurbishment is very much different. I want to spend just a second just talking about it.
First of all, Units 12 were shut down for many years, in one case over 20 years. So when we went into actually refurbish it, it was there was a lot of unknowns in those plants. Every time we open something up, we would find something new. We weren't ready for it. Units 3 through 8 are completely there.
And 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 brought them down. Every year, we're opening various parts of it up to take a look at it. So I would say, 1st of all, it's 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 in 12. 1 and 2 are actually we're actually new nuclear plants by the time we're done. These ones will be very, very significant maintenance.
I would say our governance is fixed. We did take some learnings out of 1 and 2. We and we incorporated in the contract that we have with ISO. 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. So such that the learnings that we get in OPG, who's ahead of us in the refurb, are learnings that we can use in ours. So we have taken both the learnings from 1 and 2 and the learnings that OPG is going through right now into ours.
So we have more governance in place. Processes, systems, 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. And 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 will have every part of the site before we go on. This is some of the learnings that we learned from, again, from 102. I talked about unit condition assessments. We know these very well. The project cost and execution schedule are well developed.
I would add the way we price this is that we go on with the 1st year, which is Unit 6. Now that will probably be the most expensive unit because we have to develop all the tools and processes for this one. Each one should get cheaper. But we've given ourselves the ability to each unit. We can reprice if we find things that we didn't know.
We can reprice. We have a threshold with the ISOs. I said if we come under that threshold, and it's a 2014 adjusted for inflation threshold, that there's an automatic goal. If we come in over that threshold, it doesn't mean the project doesn't proceed. Just the ISO has to sit back and make an assessment as to the economics of that process.
So we have a good ability to reprice if we do find something that we didn't expect. Cost duration estimates finalized 15 months prior. So every unit will be repriced. And you'll see in a second here that there's minimal overlap. We will this is the schedule.
There is some overlap, but it always comes at kind of the end of the prior unit. So we're not going to get in a situation where we get ourselves overwhelmed on the program. So it is 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. And I would add that OPG is doing a pretty good job over on their site, too.
So every indication we got from being our OPG site is that this plan is working. As I said, we have submitted Unit 6 MCR to proceed as planned. There's really 2 parts to the refurbishment. 1 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.
So 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 completeness of determination. And we will be proceeding and throwing the eBreaker 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 our 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. So you'll see a bit of a pop in April because we start getting paid.
Our unit's revenue goes from the kind of $68 to mid-70s starting April 1. And 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 in this market with the coal coming off, and 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, these coal plants and switch them from coal to gas. So we are we have a pretty decent even with the coal PPAs going down, we have a pretty decent position in this market. It is turning to a a market with a capacity market, which we are quite comfortable with.
We spend a lot of time in U. S. Northeast, And we are working with them on the domestic market. We'll see how that works. But I still think that there is a good market to be had here, and I still like our position.
And who knows? If the market turns out good, the fast working turns out good, we might 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. We're holding on to that right now just because with 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 stories needed for our customers.
Can you remember a little bit? Once you adjust this for the sale of our assets, it's still pretty good. This is a $1,000,000,000 EBITDA business. And when I talk about 6,600 Megawatts and the largest private owned in Canada, still there's not actually that many private owned power businesses in Canada that put off $1,000,000,000 EBITDA a year. So it is even though we cycle some capacity and even though we might cycle some in the future, it's still very, very significant business, not only for TransCanada but for the when you compare to get some of our peers in Canada.
And what are our key focus for areas? Well, obviously, I want to finish snafening. I think that's very important to get that commission, to get that in. It's a needed resource. You can 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 existing fleet. We're right now, we're getting ready to throw a 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. So we're working with Bruce on that life extension program. And 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. We're still looking at some expansions to some of our existing plants and some expansions in the renewal space. So there is some growth, and there's still some focus on that. But I will admit, they're very, very 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.
And 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. So having said that, I think I'll turn it over to questions now. Thanks,
Sorry, Ben or Dwayne. Go ahead,
Ben. Ben Pham, BMO. Carl, curious since 2015, any changes on the Bruce side CapEx in service dates
on the roofers? No, no. Well, we're I think we're in pretty good shape. Our all of our insurance base today are still sticking. CapEx, I put up $2,200,000 Our original submission in the contract was $2,014 kind of, and then you have to kind of either you have to take today's dollars back to 2014 today.
So if you actually look through our contracts, you will see different numbers and you'd wonder how they would match. But I can tell you that the number we have today that we submitted, the full amount, which is the MCR of that $2,200,000,000 The MCR part is about $1,300,000,000 Now the rest is asset management. That is well under the threshold. So we're in good shape on both budget and schedule right now.
Okay. If I may ask the second question. Bruce strategically, overall portfolio, maybe a 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 mean, I understand the thought of reducing that through Unit 12, but I haven't seen any new plant globally that's been on time, on budget, at least from what I've seen so far. And you can effectively redeploy that capital, buy an Excel, pay down debt? And so maybe just update on that when you think about overall Bruce investment?
Yes. So it's a good question. And let me answer a couple. Let me recon a couple of parts, Bruce, that I like, that we like as a company. Number 2, the return is commensurate with what we're doing.
It's low double digits. The way we structured our payment, it's such that we don't actually go without revenue for the facility even when it's down. And 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. And 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 getting paid on. So there's a few differences right now in this than I would say with a traditional construction program that actually makes it very it fits in our book very well vis a vis other projects that I would have. 2nd part, I'd say, on the technical expectation, I agree. This is we went into a size 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're trying to bring that into service.
But we went into this with eyes wide open on that, understanding that we had to do it differently. And we have done this differently by actually getting more time in our contracts to do the engineering so that we didn't we're not in any way time stressed on this particular projects. By having only 1 unit at a time being priced and being able to update that price in the next unit, by having escapes, it's us or the ISO kind of after Unit 3, after we've done the 3rd unit, either us or the ISO can opt out of this if we don't if it's not working for us. I think we've mitigated all the concerns that we have. And 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.
And only time will tell, but 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. And I do think that we have determined a process now that will be successful. So when you look at it, when you stack it up, we have, I think it is a it's certainly right there with some of the best investors they have on a return basis. I think the risk in this is totally manageable.
And I do think there's a good reason for being for Bruce. The nuclear industry is very important to Ontario. And Ontario is going to center the nuclear industry in Canada. I think Ontario supports even the new government in Ontario supports the nuclear business. The old government support the 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. And I think the nuclear megawatts in Ontario play an important part of their stack. So we're quite comfortable that this is actually this is where we want to be, and there's good reason for being here.
Robert, sorry. Maybe if I can continue on Bruce, just to confirm Carl that those low double digit that's unlevered after tax? Yes, absolutely. And 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 or better than most of your projects even
Yes. I don't have the exact number, but I think it was high single digits, probably in the 8% to 9% range. And it was although the there's some scars with the actual construction and doing 1 on 2, we did have a good commercial agreement, which helped share those costs as that we came out with that. We started at a higher, much higher rate of return, but it still came out. And it's 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. So 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 1 year state of the market 3 years forward?
So I would say the stairs where it is today probably no. They don't have a long enough duration to the best market. But 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. So yes, 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 will really be outside of the capacity market. So we'll still look at them even though there's a poor yes, what I would call, poor duration of the capacity market. If we can do a third party deal, then we still work on that. So we got some work to do in that market regardless of the capacity market.
But I do believe the capacity market, the important part is getting one in into Alberta. I've been an advocate of capacity market. And I'd tell you, many years, I was alone in this advocacy, but I've been an advocacy of capacity market in Alberta for many years. And 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. And as long as we have a government in place that allows it to work, I think that will start pushing that duration up.
And 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. But certainly, where it is right now is probably not where it is. When it gets around 7 to 10 years, we probably start getting our interest.
And certainly, we'll still be looking for customers even behind that for longer durations.
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.
Good morning. As Russ was reminiscing about going back 15, 20 years ago, it occurred to me the last time we were trading through 14x earnings, Carbon was legal, marijuana wasn't and I think the Spice Girls were in their inaugural tour. So 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 $10,000,000,000 of assets into service here. That will help underpin dividend growth here through 'twenty one, get our credit metrics to a point where we're into the high 4s 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. And with $36,000,000,000 on the roster right now, projects are ready to continue this growth trajectory into the future. As I work through presentation here, a couple of key assumptions.
Canadian dollars, unless otherwise noted, using a currency of $1.30 to convert U. S. Into Canadian. Depreciation on average over 40 years, so about 2.5 percent of gross PP and E. And in terms of Coastal GasLink, we expect to be bringing in joint venture partners and have our ownership interest in the 25% to 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 percent. So with that, as I usually start out with the financial tenants here, they get refined from time to time, but seem to go in and out of vogue, but 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 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, 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. And A credit is an important component of that.
We do value an A grade 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 Where we do finance at the asset level is really in 4 spots.
1 is at FERC regulated pipes, which is a necessity for rate making purposes. And then we pointed to 3 other areas where we have or we'll consider essentially asset level or project financing. 1 is Bruce because of its unique nature. West Coast LNG projects, we'll pursue that for Coastal GasLink. And 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 7 to 8 times. And it's valued at a higher metrics once it's completed. That's a good value proposition as far as we're concerned and we do buy things and the tendency there is to do it when there is strain in the marketplace.
I thought it'd be useful to do a quick look back on the where we've been through since the transformational Columbia acquisition, which is about 2.5 years ago. Since that time, Columbia is fully integrated. We have captured the synergies we set out to capture. Merchant assets were sold. We added significant more data capital to our balance sheet.
And over the coming months here as we bring $10,000,000,000 of assets into service, we will be derisking the capital program, the execution risk of that, that we took on at that time. We maintained a simple structure. We bought in Columbia Pipeline Partners and we retained 100% in Mexico, which is something we contemplated selling down. The base business today, Colombia and TransCanada combined is generating record results. I think that underscores the value of pipe on 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. But having that pipe in the ground in the right places is very beneficial to us. And 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 0.1s here and no impact on financial flexibility. FERC actions were impactful to RLP, although less so than initially envisioned, but not material to Big Trans Canada. We've added $18,000,000,000 of projects to our roster, and I'll go through that here in a few minutes. And 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 $16,200,000,000 $2,800,000,000 was in the form of paid out in dividends and distributions, particularly in our pipe LP, about $10,500,000,000 of CapEx and about $2,900,000,000 of debt maturities. The funding is on the right hand side here. Funds from operations is coming at around a record $6,400,000,000 this year. We raised $6,100,000,000 of long term debt.
Average term was 22 years, average coupon of 4.6%. We have used cash and CP to fund about $700,000,000 of our needs this year. We have the dividend reinvestment program running. It will generate about $900,000,000 in 2018, seeing about a 35% participation rate there. We issued $1,100,000,000 of common equity under our ATM program.
We do view that as complete at this time. And the average price that was issued at was $56.13 We sold Cartier Wind for proceeds of $630,000,000 and we will receive $400,000,000 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 $57,000,000,000 of capital needs since the beginning of 2016. This should qualify as some award for humanitarian relief to the banking sector, but probably the right trade in 2016 would have been to go along Lucite features. Dollars 57,000,000,000 is shown on the left hand side here.
Dollars 8,000,000,000 was in the form of dividends and distributions, dollars 26,000,000,000 was capital program, dollars 8,000,000,000 was debt maturities and we spent $15,000,000,000 acquiring assets and companies, dollars 10,300,000,000 on CPG, US900 million dollars 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 is $17,000,000,000 We issued $15,000,000,000 of long term debt, average of 17 years at a coupon of 3.98%. So we did take the opportunity through the cyclical low here of interest rates to term out. And that's, in our view, a fairly attractive coupon for the term we achieved here.
About $6,500,000,000 was in hybrids and preferred shares. We issued $5,000,000,000 of hybrid securities, which we received 50 percent equity credit for at a $5.28 pretax coupon there. That is at about prefs and hybrids are at 15% of our capital structure. So we have maxed out our issuance over the years to maintain that at 15%. $2,000,000,000 was DRIP, dollars 1,300,000,000 was ATM and just stress that the DRIP and ATM in the context of $57,000,000,000 of requirements was more fine tuning to make sure that our we were achieving targeted credit metrics and the like here.
Neither is a permanent feature of our funding program. DRIP has only run periodically. We had it on in 2,007 when we acquired ANR and turned it off in 2011 and then reinstituted that when Columbia was acquired. And the ATM only ran from the Q4 of last year until it was shut off August of this year. We did issue $8,000,000,000 of equity in 2016 in 2 tranches, 1 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.
And there's a $7,000,000,000 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 CGO to the amount of about $1,000,000,000 included in that figure.
So 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 4s, and we will achieve that in 2019 as $10,000,000,000 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 time frame. 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 review our asset base as never having been stronger, more diversified, more predictable and longer duration. And 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. Again, the key word here is diversity. I think what this also highlights is our ability to rotate capital as opportunities cycle from 1 business, 1 geography to the next.
We're not really beholden to one specific business line or one specific geography. And we 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. So I think you see that through where we are today, where we've had a significant build out in Mexico. It shouldn't taper off for a while, but we are seeing significant opportunity in Canadian Gas and about to embark on a Bruce refurbishment program.
So it gives us comfort that there are many places to put capital at any point in time. And 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 contract spot movements on the Market Link portion of Keystone South Cushing, Oklahoma. And 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 U. S. 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 U. S. Dollars. So I'll spend a couple of minutes here on 3
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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 and interest rates. So we've taken more of a normalized view as we look at sanctioning projects. And 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 U. S.
Dollars. As I mentioned, about 60% of our EBITDA is U. S. Dollar denominated. We have $25,000,000,000 of U.
S. Dollar denominated debt and hybrids as a natural hedge to that. That leaves us longer residual $2,000,000,000 after tax that we then actively manage on a rolling 12 month basis. So today, we would be hedging up on November 13, 2019 and tomorrow, November 14, 2019 as well. So we'd 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 $0.10 move in the Canadian U. S. Dollar to impact earnings by $0.01 Beyond that, it is fairly more dramatic. A $0.10 move in the currency would be a $0.20 impact on EPS as given our long position in U. S.
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 take recommend you take comparable earnings, remove Canadian rate regulated our Canadian rate regulated businesses in 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 just under we're under 50% current tax rate now. That should migrate to above 50% here in the coming years as our tax shelters move around.
But the rails on that are about 40% to 60%. So gravitating to slightly higher current tax, but again within that 40% to 60 percent barrier there. And that will fluctuate around with build programs and tax planning activities. Turning to our capital program. I think we found an even smaller font than last year.
We're starting to push the envelope on this. So in an era where growth is difficult to find and arguably frowned upon at some points in time, I'm sure whether to take this or apologize for this, but we have $36,000,000,000 of highly attractive growth opportunities as outlined here. We've spent about $12,500,000,000 to date on funding these. This roster has grown significantly over the past year as we've added Coastal GasLink, Bruce Unit 6, the NGTL-twenty one and twenty two expansion programs. And we've also included 3 years of maintenance capital on this chart now.
So hence, the dramatic change year over year. Again, we expect about $10,000,000,000 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's a very diverse set of projects here. They're virtually all contracted or regulated.
We describe them as smalltomidsize 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, the chart on the far right here. About 60% of the EBITDA from this growth portfolio would be subject to FERC or NEB jurisdictions, 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's really nonrecoverable maintenance capital that's included on that chart. I just note that even under the FERC and NEB portions of this pie chart here, The Columbia Gas growth projects generally are back by 15 to 20 year contracts.
And NGTL's contracts range from, I think, 7 to 107 years. We actually did see 107 year contract bid in to some of our capacity this year. In terms of the CapEx profile through 2021, it's outlined in this chart here. It is coming down to more normalized levels. We have seen a fairly elevated CapEx program in the past couple of years.
I think it was $9,500,000,000 in 2017, and it will come in about $10,500,000,000 this year. In total over these 3 years, it is $18,000,000,000 capacity capital is $12,400,000 of that maintenance is 5.1 dollars We have about $500,000,000 of capitalized interest in here at a rate we would describe it as in the low 5s 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 use 25 percent ownership as an illustration for Coastal. That translates to about $1,400,000,000 of Coastal Gas Wind CapEx over this time frame in these charts.
Maintenance capital is running at about CAD 1,700,000,000 per annum over this period. That's about 1.7 percent of gross PP and E. Highlight once again about 85% of that CapEx, maintenance CapEx is recoverable and either through tolls or we have ability to earn a return on and of that capital through our rate basis. It is elevated at the current time given the usage of our assets. We've 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 $1,500,000,000 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 $28,000,000,000 over this 3 year period. Dollars 10,000,000,000 would be dividends and distributions and about $18,000,000,000 of capital from the prior slide. Moving to the middle box here, funds from operations should be in the $21,000,000,000 area. We would note that is above the CapEx number on the far left hand bar chart there.
And we have $200,000,000 ish in here for the January 2019 dividend reinvestment plan. That dividend was declared on October 31. So the DRIP will actually run into the Q1 of 2019 with certainty. That leaves a capital markets requirement of about $6,800,000,000 in the far right hand bar, and that will be comprised of about $2,500,000,000 of incremental senior debt, and that is keeping in line with our target metrics of high force debt to EBITDA and minimum 15% FFO to debt. We have $1,300,000,000 in here for hybrids, that's $1,000,000,000 US1.3 billion dollars to maintain that at about 15% of our capital structure.
And then we have about CAD3 1,000,000,000 in the purple, which would comprise of other. What's not in that what's not included in that is any further ATM, no LP drop downs and no discrete equity. So that other chart or that other bar would be comprised of 2 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 3 main reasons: when 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 4s. And thirdly, we have experienced some cost overruns, which despite some of the regulatory delays and whether we've encountered that, 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 $500,000,000 of contracted EBITDA as assets that comprise that as potential viable portfolio management candidates.
And I would just note at any reasonable multiple that would dwarf the purple box on here. As usual, there'll be no preannouncement of these processes, and you should not take silences as an activity in the background right now. Should Keystone XL proceed, as I mentioned on the Q3 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, so 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 3 years. This is on top of the funding needs on the prior slide. In here, it's about US4.8 billion dollars of maturities and another CAD850 1,000,000 of Canadian dollar denominated maturities. On a C dollar equivalent, just over CAD7 1,000,000,000 over this time frame, which is fairly normal course for us.
I would note that we would consider our upcoming US1.15 billion dollars January maturities largely being prefunded right now, so with cash on hand. So we would see our needs over this time frame from a refinance perspective in the 5 $600,000,000 area. The average coupon of this maturing debt is 4.9%. So I think fairly consistent with where current market levels are at. When you look at the $2,500,000,000 of incremental debt and the $5,500,000,000 $5,600,000,000 of refinanced debt here, Probably over half of that is will be designated as rate base with flow through to primarily the NGTL system as that rate base grows.
Liquidity is strong. We have $10,000,000,000 plus 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. So I think this was initially in Russ' slides, so I just need a little more granularity on this.
This is our EBITDA build from 2015 through 2021 as we progress $36,000,000,000 of projects through the completion here. You can see the growth from $5,900,000,000 to $10,000,000,000 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.
And I'd also note that excluded from this is $650,000,000 of EBITDA that we've effectively sold through our U. S. Northeast merchant Power assets, Ontario Solars and Part J Wind. So that has disappeared from 2015 through to 2020. It was in the 2015 numbers, but has not included obviously in the 2021 numbers.
EBITDA through the 1st 9 months of this year is 6,100,000,000 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% to 75% range. So 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 and 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.
So as you're looking at EBITDA, just something to bear in mind that Canadian flow through accounting is a bit unique. We reaffirm 8% to 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% to 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.
We've not changed it. We've just gone to one definition where we exclude only non recoverable maintenance capital and it is 2 plus times over this entire time frame in terms of DCF coverage. This chart depicts the long life, high quality and lower variability of our cash flow streams. The depiction of what we've effectively, in our view, locked in out to 2025. What's assumed in here as we complete our 36 $1,000,000,000 capital program plus incur maintenance capital over this time frame.
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 time frame. Again, 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 to do that. And the other challenge is to make this look hard for compensation purposes. So to wrap things up, bit of a convoluted picture here, but this is a time tested business model. And 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 to our in our traditional fashion of paying a growing and sustainable dividend and reinvest in our core businesses.
As Ross mentioned, we found 85 $1,000,000,000 of stuff to do since year 2000. We have line of sight to $50,000,000,000 of opportunities right now, and we have 5 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. So we are poised to return to our living within our means doctrine here as well as deliver, in our view, another 3rd consecutive decade of double digit TSR. So 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 Sinati from Morgan. Just wanted to talk about the leverage a bit more. And you talked about upper 4s kind of being the right level for TransCanada as far as what you're targeting. I'm wondering if you expand a bit more as to why you think that's the right level versus something more versus less and kind of how the agencies think about that and how you guys stack up versus peers, maybe your risk profile will be helpful to go see what goes in that thinking?
Yes. So we have nuanced that from targeting 5x to high 4s. And I think like we are certainly conscious of the market's views and leverage, both the debt and the equity side, and that's something we could certainly drive to. So we think there is value for all stakeholders in going to that spot. 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 victim by them, but we think this flanges up with that on all fronts. So yes, it's something we consciously decided we want to invest into our balance sheet and bring those levels down to that to the high 4s. 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.
So we do see others in our sector looking at 4.5x, 4.25x, 4x in some cases. But I think you do have to differentiate between the asset basis. This from a TransCanada self assessment perspective, we think this is the right place to be.
And then kind of a similar type
of question with the range for dividend growth being 8% to 10% as the 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 multiyear 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?
Yes. It will move in lockstep with earnings and cash flow growth. So we do see 8% to 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. So we'll assess that as we're closer and closer to them, 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.
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 renewed emphasis on managing the share count growth and all things related to capital discipline. So I'm wondering under what circumstances that might change. Partially you answered the question already, but what I'm thinking about is, is there more than just price in terms of how this ranks in your in sort of your financial options?
And 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? Or 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?
Well, as you look back, we had $57,000,000,000 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. So we're conscious of that. So 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. So 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 you start looking at when your capital program gets so big, the marginal cost of capital versus the marginal return can shrink to a point where or it potentially even go negative.
So we are conscious of that. It depends on your opportunity set, but and what's in that opportunity set. But frankly, we'd like to use share issuances really for transformation 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. And we have been doing that for some time.
It was driving the decision to sell the solars, to sell Carje 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 dropdown market isn't available to us. We're not sure if that will ever come back. So what I'd just like to highlight is we never want to be boxed into one means of capital raising, specifically the subordinated capital.
We like to have all of these to look at, and the prices and the cost of that capital changes continuously here. So sometimes the hybrid market is better than portfolio management and vice versa. But long winded way of just saying that we're we will go to where the cheapest source of capital is at any given point in time.
Okay. Then 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. So would you joint venture or sell a piece of Keystone even without Keystone XL making it to FID?
Yes. We look at all of our assets all the time. We do like to own 100% of everything if we could with some exceptions. And other than just it is a core asset. I'm sure it would fetch an incredible price in the market right now, but there's a lot of value associated with it, including optionality as we bring KXL forward here.
So 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.
Yes. It
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, dollars 500,000,000 of long term contracted EBITDA that you could potentially recycle into that project, Why bringing in that JV partner or selling down the ownership interest makes sense?
Well, it's again, we'll look at per share economics here and any quantum of equity that might be required. And 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. So we haven't got a firm process running in the background here. Again, we're defining what this looks like. But 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 seeing 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.
Sorry, go ahead, Rob. Don, just looking at the $10,000,000,000 of EBITDA in 2021, is that net of asset sales and the segments that make up the $10,000,000,000 are those also net of expected asset sale?
It is gross of asset sales that have not been completed or announced at this point. So that number could fluctuate. The $500,000,000 we'd be looking at would detract from that and that number is probably a little over $10,000,000,000 right now. So it's $10,000,000,000 area. But again, anything we sell in terms of with EBITDA associated with it would come off that.
And then just within the funding waterfall, the $3,000,000,000 bucket of portfolio management DRIP and hybrids, If you went completely without the sales, how much would that number need to flex out just given your given 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. So 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's great. Thank you. Thanks, Robin. Dennis Coleman, BofA. Don, if I can ask, it a little silly in the context of talking about the DRIP and ATM, but a little further out, you seem to indicate return of capital to shareholders.
And Jeremy asked about the distribution, but are you indicating that share repurchases could be part of that mix at some point?
It's really a pretty darn lot of stuff to do that's not adding value to not adding shareholder value. We actually did buy back some stock at the end of 2015, early 2016. It was $300,000,000 at a price of $43 a share, but then Columbia came along. So we don't think we're going to run into that for the foreseeable future here, but it's more philosophical. If we can't add value by investing in new projects, then we would look at share repurchases.
I'd love to be buying it back today.
Thanks. And then just another little detail on the asset sales. It sounds like maybe you are working on some things and the timing is obviously what's in play. Is that something you could announce soon or in
the Q1?
And if you did, is announcing it enough to sort of let you maybe use some borrowing short term borrowings for the agencies to fund it until you close it?
Yes. 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 $3,000,000,000 purple bar on the 2019 to 2021 capital requirements.
So until we claw through that, there wouldn't be any significant additional senior debt capacity
arising from that. Any other questions for Don? If not,
that is it.
Thanks, Don. Sorry, Russell will just rejoin us here. I think Russ would be obviously open to take any last questions you may have for him. And then, Osat just maybe offer a couple of minutes of closing remarks. So to that end, if there are questions for us, happy to take them at this point.
Seeing or hearing no questions, I guess we'll turn it over to you. That's great news. The team took all the hard ones. So I just 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 $85,000,000,000 I think successfully into our 5 core businesses in our 3 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. And when you look at this chart, you can see the stark contrast between 2,000 today. As I said, today, in terms of key takeaways from what we've heard is we are our large portfolio of high quality energy infrastructure assets are generating financial results underpinned by strong fundamentals.
And 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 in 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 up to 2025, a predictable cash flow. We could run that chart up to 2,030 and it wouldn't look much different than the 2025 chart that Don showed you. Looking forward, we'll continue to advance our $36,000,000,000 capital program. As I said, that's commercially secured and that will 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 $10,000,000,000 in 2021, which is a 35% increase from comparable EBITDA of $7,400,000,000 in 2017. At the same time, as you heard again today, we'll continue to methodically advance more than $20,000,000,000 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 at an average annual rate of 8% to 10% through 2021. Notably, and as we said, that's 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 $10,000,000,000 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's 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. So 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's at a level that we haven't seen for about a decade. And again, our focus is on continuing to do what we do, which is not worry about our share price due to much in the short run, but to deliver growth in earnings, cash flow and dividends for our shareholder in a sustainable way.
And we believe that is what will drive long term shareholder value. That concludes our remarks today. We'd be happy if you had any other final questions. But 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.