Good morning. Welcome to TransCanada's 2017 Investor Day. I'm David Moneta, Vice President of Investor Relations at TransCanada. This is clearly an exciting time in the history of our company. We intend to use this morning to provide you with an update on the many initiatives that are underway today that we expect will create significant shareholder value. We also hope to provide some insight into the trends that'll help shape both the pipelines and the energy businesses in the years ahead. We'll begin today with Russ Girling, our President and Chief Executive Officer. Russ is going to provide you with some comments on the progress we've made over the last number of years, some of our key priorities, as well as our promising outlook for the future.
He'll be followed by Karl Johannson, Stan Chapman, Dean Patry, who will provide you with an overview of our natural gas pipelines, liquids pipelines, and energy businesses. Dean is stepping in for Paul Miller this morning, who unfortunately couldn't be with us due to a family emergency. Finally, Don Marchand, our Chief Financial Officer, will close this morning by providing you with a finance update. Copies of their presentations are included in your handout. For those of you listening via webcast this morning, a copy of the presentation material is available on our website. It can be found in the investor section under the heading Events. For those of you in the audience this morning, we will provide you with an opportunity to ask questions throughout the morning. I would ask that you limit yourself to one question and a follow-up.
That should give others the opportunity to ask questions as well. With that, just before we do begin, I'd 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, just a couple of brief comments on non-GAAP measures. We will make reference to comparable earnings before interest taxes, depreciation, and amortization or comparable EBITDA, comparable earnings, comparable funds generated from operations, and comparable distributable cash flow. These measures are intended to provide you with some additional information on our operating performance, liquidity, and ability to fund our capital program.
However, as you know, they do not have any standardized meaning under US GAAP and therefore may not be comparable to similar measures used by other entities. With that, I'll turn the podium over to Russ Girling for his opening comments.
Thanks, David. Can everybody hear okay out there? No problems? Good. Good morning, everyone, and thank you very much for joining us today. Very much appreciate, obviously, the ongoing support of our company and your ongoing interest in our company. It's hard to believe it's been 18 months since we closed the Columbia transaction. It was a $13 billion U.S. transaction. It was transformational for our company. It represented an opportunity, you've heard us say many times before, to further diversify our regulated natural gas pipeline and storage businesses, and gave us an incumbency position in the Appalachian region, which, as you know, is one of the world's fastest-growing and lowest-cost natural gas production basins.
Looking back on the year, I can tell you that I'm very pleased with the progress of the integration of Columbia into our company, but as well, the numerous other initiatives that we advanced during the year in all three of our core businesses in all three of our core geographies. Today, our high-quality portfolio of assets is performing very well. Our long-term strategy, financial discipline, I think, has positioned us for unprecedented growth going forward. Over the next four hours or so, myself and the management team look forward to sharing with you some of the significant progress that we have made over the last few years, but as well, some of the challenges we faced, and I think most importantly, the promising outlook that we have for the future. This next slide here highlights the key themes for the day.
In 2000, we set out to be North America's leading energy infrastructure company, and we've largely stuck to that plan, and our strategy, I believe, has generated significant shareholder value. Over the past 17 or so years, we've invested about CAD 75 billion in high-quality, low-risk pipeline and power generation assets. Today, our CAD 86 billion portfolio of assets produces about CAD 7 billion of EBITDA, with over 95% of that EBITDA coming from regulated businesses or businesses that are underpinned by long-term contracts. I think more importantly for me, over that same period of time, we've built more than just a group of assets. What we have created is franchises that provide us with significant platforms for growth. We have five of those today. They include our Canadian, U.S., and Mexican natural gas businesses, our liquids pipeline business, and our energy business.
Each of those businesses, I can tell you, are performing very well in 2017, and the result comparable EBITDA, funds generated from operations and earnings per share as a company is expected to reach record levels this year. Although the environment in which we operate, as you know, has become increasingly complex, what I can tell you as a company, we are prepared for those challenges that lie ahead, and we continue to be a leader in setting new standards for safety, reliability, and environmental stewardship. At the same time, we continue to focus on identifying efficiencies across all of our businesses. This will result in lower costs to both us and our customers. We've maintained a financial discipline and our capital allocation process with a focus on generating superior risk-adjusted returns for our shareholders. You've heard me say this numerous times.
Simply put, our strategy is to grow earnings, cash flow, and dividends per share by investing in high quality, low risk energy infrastructure assets across North America. As we look forward, we've got about CAD 24 billion of near-term growth projects that are largely expected to enter service between now and 2020. We're also advancing another CAD 20 billion of medium to longer term projects. As demonstrated by our new project announcements earlier this year on NGTL, the Canadian Mainline, and the Columbia systems, we expect our existing businesses will generate significant organic growth opportunities in the years ahead. Finally, we do understand the value that our shareholders place on a stable and growing dividend.
Based on our positive outlook for the future, and strong dividend coverage ratios, today we are reaffirming that we expect to grow our dividend annually at the upper end of the 8%-10% range through 2020. As highlighted in our news release this morning, we are also extending the 8%-10% range out to 2021. In summary, what you'll hear today is we believe we have a compelling investment proposition given the stability of our underlying businesses, our tangible outlook for growth, and the financial strength, and flexibility that we continue to have. My plan here over the next 20 minutes or so is to delve a little bit deeper into each one of these themes, starting with the evolution of our business.
As I said, over the past 17 or so years, we've invested about CAD 75 billion into high quality and low risk pipeline and power assets. Through that investment, we have added some 45,000 km or 28,000 miles, to our natural gas transmission business in Canada, the U.S., and Mexico. We've developed 4,800 km, or about 3,000 miles of our liquids pipeline business, and we've expanded our power generation portfolio by about 4,500 MW. In the process, as I said, we have transformed this company into a leading North American energy infrastructure company. This next slide shows the results from those investments. As you can see on the chart, it's resulted in significant growth in cash flow and dividends per share over the 17-year period.
As we've highlighted on this slide, we've increased our common dividend in each of the last 17 years from about CAD 0.80 per share in 2000 to the current level of about CAD 2.50 today. That represents a compound average growth rate of about 7% and equates to a payment of about CAD 14 billion in common dividends to our shareholders over that period. While we've maintained strong dividend coverage ratios, with our current dividend representing about 80% of comparable earnings and just about 40% of internally generated cash flow, that leaves us in a strong financial position to continue to invest in our core businesses going forward. Strong financial position and dividend growth has in turn resulted in significant increase in our share price from about CAD 10 per share in 2000 to about CAD 63 today.
As a result, if you just do the simple math, we've delivered a 14% average annual total shareholder return since the year 2000. As we move into this year, you can see that our strong financial performance has continued as we moved into 2017. For the first nine months of the year, comparable EBITDA was about CAD 5.5 billion, up 50% over last year. Comparable funds generated from operations were about CAD 4.2 billion in the first nine months of the year, up about 12% from last year, and comparable earnings per share at CAD 2.27 increased about 12% since last year. Those strong results clearly support our board of directors' decision earlier this year to increase the quarterly common dividend to CAD 0.625, which equates to that CAD 2.50 per share on an annual basis, and as we've noted, represents a 10.6% increase over 2016.
In addition to the financial performance in 2017, as I said, we've made significant progress on a number of other fronts that position us for continued success in the future. First of all, as I said in the beginning, we completed the integration of Columbia, and we're on track to realize the full CAD 250 million of synergies that we promised at the time we acquired that company. During the year, we also acquired Columbia Pipeline Partners for $1.2 billion, giving us 100% ownership of the Columbia core assets and simplifying our corporate structure. We also completed the sale of our U.S. Northeast power assets and repaid the full Columbia bridge loan facility. We also continue to advance our CAD 24 billion near-term capital program. By the end of this year, we expect to place more than CAD 5 billion of those assets into service.
At the same time, we continue to replenish our portfolio of growth assets by adding about CAD 3 billion of Canadian and U.S. natural gas pipelines expansions. We continue to advance our over CAD 20 billion of what we call medium to longer term projects, which includes the Keystone XL Pipeline, the Coastal GasLink pipeline, and the Bruce Power life extension program. On a bit of a disappointing note in that medium to longer term portfolio, the Pacific NorthWest LNG group informed us that they would not proceed with their LNG project, and the Prince Rupert pipeline. In October, after careful review of changed circumstances, we informed the National Energy Board that we would no longer be moving forward with our Energy East project.
On a more positive note, as we move back to our natural gas business, we implemented a new long-term fixed price service on our Canadian Mainline this year, which will see us move 1.4 billion cubic feet a day from Empress to Dawn under that 10-year agreement. The new request for service on the NGTL and Canadian Mainline system support our belief that the Western Canadian Shale plays are among the lowest cost sources of supply in North America, and they will continue to play an important role in North America's gas demand going forward. Turning to our funding program, we raised a substantial amount of money this year across the capital spectrum on very compelling terms. That included more than CAD 6 billion of long-term debt and hybrid securities in both Canada and the United States.
In addition, we completed the drop-down to TC PipeLines for about $765 million U.S., and we generated another CAD 1.1 billion of proceeds through the recovery of our development costs on the Prince Rupert Gas Transmission project and the sale of our Ontario solar facilities. As a result of all of those initiatives, our overall financial positions remains very strong. We are supported by an A-grade credit, and we remain well-positioned to fund the balance of our capital program. In summary, it has been a very busy year, but I can tell you that I am very pleased with the results and our progress throughout the year. As you see from this chart, TransCanada today is an enterprise that has an enterprise value of over CAD 100 billion.
Today, we own or have interest in some 91,000 kilometers or 56,000 miles of natural gas pipelines that move about one-quarter of all of North America's demand for natural gas from the continent's two largest and most cost-competitive natural gas production regions to the premium markets across North America. Today, we are also the largest provider of natural gas storage in North America, with 653 Bcf of capacity. In the liquids business, our Keystone Oil pipeline now delivers about 555,000 barrels per day, or about 20% of Western Canada's crude oil exports to the premium markets in the U.S. Midwest and the U.S. Gulf Coast. In energy, we own interest in 11 power plants that are capable of producing some 6,100 megawatts of electricity, which is enough power to service about 6 million homes.
Over half of that capacity is comprised of emissionless power, including our nuclear investments and our wind investments. The remainder in that portfolio consists of high-efficiency natural gas power generation facilities. As we think about our competitive advantage going forward, we think that our Excuse me. Can you just hand me that glass of water there?
Sure.
Sorry about that. It is the far one.
Yeah. It's no problem.
Thanks. Excuse me. Sorry about that. As we think about our competitive position, we believe the large, diversified portfolio of high-quality, long-life assets provides us with a very enviable position from which to continue to grow this company. I think our real advantage is in our 7,100 people across Canada, the U.S., and Mexico. What I can tell you is they are experts in operating large-scale infrastructure and developing creative solutions to meet our customers' needs, while at the same time, I think from your perspective, putting in place commercial arrangements that strike the right risk-reward balance for our shareholder group. Finally, our financial strength and flexibility, I think, is another significant competitive advantage. As you've heard me say many times before, the largest cost of doing business, of building this large-scale energy infrastructure, is the cost of money.
Our A-grade credit, strong internally generated cash flow gives us access to significant pools of capital at lower costs than most of our peers. It also provides us with the ability and flexibility to act at all points in the cycle when opportunities arise. Turning to the future, we remain focused on six key priorities. These are things that you've seen before. The first and the most important is to ensure that our assets continue to operate safely and reliably every day. Second, we will continue to improve the profitability of our existing businesses by focusing on maximizing the revenues and reducing the cost and efficiencies in each of our businesses. Third, we'll continue to focus on executing the CAD 24 billion program, bringing it in on time and on budget.
Fourth, we'll continue to advance that CAD 20 billion of medium to longer term projects that are in development, as you've seen us do, in a careful and cost-effective manner. Fifth, we will cultivate a portfolio of additional low-risk, organic growth opportunities from our existing footprints in our existing geographies. Finally, we'll allocate our capital in a disciplined manner that allows us to maintain a strong balance sheet, fund our growth, and support a stable and growing dividend for many years to come. While we're proud of the history of delivering significant shareholder returns, we know that our long-term success depends upon our ability to balance profitability with safety and social and environmental responsibility. Above all else, safety, I can tell you, is the top priority of this company. We have a 65-year track record of safe and reliable operations, but we recognize the need to continually improve.
We have had a few incidents over the last couple of years. Thankfully, they have not had an effect on the public, nor have they had any lasting environmental impacts. When incidents occur, we're focused on ensuring that we have world-class capability to respond, to protect the public and the environment, and to restore those facilities to service as quickly as possible, I think you saw an example of that over the last couple of weeks. While pipelines aren't perfect, we continue to believe that they are by far the safest and most efficient method of moving both natural gas and crude oil to markets that need them. TransCanada's safety record is among the best in the world, but we recognize that that is not good enough.
No incident, in our view, is acceptable, we won't be satisfied until we've achieved our goal of zero incidents. That's why we invest about CAD 1.5 billion a year in integrity and maintenance capital, we continue to be industry leaders in both research and development. We have a long-term track record of collaborating with various stakeholders in communities in which we work. We treat landowners with respect and fairness, that enables us to be partners with those people over a long period of time. As we look to develop new projects, our approach remains the same as it's always been, is to understand stakeholder issues, engaging with local officials and landowners, identify how best their concerns can be incorporated into our plans.
In summary, while our customers are always looking for the best-priced services, they are becoming more selective in how they choose a partner, they're choosing partners whose values around safety, environmental stewardship, respect for others is aligned with theirs. We believe that our world-class practices in operations, project execution capabilities, a strong track record of working collaboratively with stakeholders, a strong financial positions means that we are well-positioned to be their partner of choice. I think, as you can see from this chart, evidence of that selection of us as a preferred partner, we have CAD 24 billion of projects that we are advancing today that will expand and extend our footprint across North America. Our CAD 24 billion growth program includes a series of projects in jurisdictions where we have relatively what we would call normal course permitting, construction risks that we think are infinitely manageable.
That includes about CAD 22 billion of natural gas pipelines expansions in Canada, the U.S., and Mexico. It includes about CAD 1 billion of projects related to regional liquids development in Alberta, it includes CAD 2 billion of power projects, including the Napanee gas-fired power plant here in Ontario, in Kingston, as well as the initial work required for the Bruce Power plant under the long-term life extension agreement with the province of Ontario. To date on these projects, we've invested about CAD 10.5 billion, with the remainder to be spent over the next two years or so. Notably, each of the projects is underpinned by a long-term contract or a cost-of-service regulatory model, giving us strong visibility to sustainable growth in earnings and cash flow as they enter service between now and the end of the decade.
This slide highlights the significant growth in EBITDA that is expected to come from that near-term capital program. As you can see on this chart, and as was mentioned again in our press release this morning, comparable EBITDA is expected to grow from about CAD 5.9 billion in 2015 to approximately CAD 9.5 billion in 2020. That equates to a compound average growth rate in EBITDA of approximately 10%. Just as important as the magnitude, as I've said before, is the quality of that growth, with over 95% of our EBITDA expected to come from regulated or long-term contracted assets in the years ahead. Looking forward, I'm confident that we're well-positioned to continue to reinvest our growing internally generated cash flow in high-quality opportunities in our core businesses and our core geographies.
On this chart, you can see that today we are continuing to advance CAD 20 billion of medium to longer-term projects. They include the Keystone XL project, the Coastal GasLink project, and the Bruce Power life extension project. With respect to Keystone XL, we were very pleased to receive a presidential permit in March of this year. On the commercial front, we sought binding long-term shipping commitments from our customers during an open season that concluded in October. As I mentioned earlier, we received broad interest in that open season. Over the last few weeks, discussions with our customers have continued. We're very encouraged with the progress we've made, and we continue to expect to conclude sufficient binding shipping commitments to advance the project.
On the Nebraska front, on November 20th, Nebraska Public Service Commission issued its decision on the routing through Nebraska. As we've said, we continue to review that decision and its potential impacts on both the cost and schedule of the project. On the natural gas front, our Coastal GasLink project is also fully permitted. The LNG Canada's liquefaction facilities are also permitted. What we're doing is we're waiting for a final investment decision from the project sponsors to move that project forward. Finally, in our medium to long-term project portfolio, we continue at Bruce in anticipation of the major component replacement program that is expected to begin in 2020 and continue through 2023. The CAD 5.3 billion investment, that represents our share of the expected refurbishment costs in CAD 2014 dollars.
That CAD 5.3 billion investment will extend the operating life of Bruce Power through to 2064, with all the power generated sold to the province of Ontario under a long-term contract. Achieving any one of those initiatives would create significant incremental value for our shareholders and position us for continued growth going forward. In addition, looking forward, we expect global demand for energy will continue to rise. This growth will require billions of CAD in investment, and we are well-positioned to capture a sizable share of that opportunity. As you can see from this slide, North American natural gas demand is expected to grow by about 30 billion cubic feet a day between now and 2030. Much of that will be driven by industrial demand, natural gas-fired generation, and LNG exports.
Our extensive natural gas pipeline network, as you can see by the footprint, is well-positioned to meet that demand by connecting growing supply from the Western Canadian Sedimentary Basin and the Appalachian Basin, which we've said we believe are the continent's two largest and lowest-cost supply sources that we can connect to those premium markets. Turning to our liquids business, where North American crude oil supply is also expected to grow in both Canada and the U.S. In Western Canada, the production of heavy oil continues to grow, and the need for new transportation capacity remains high. We and our shippers continue to believe that the U.S. Gulf Coast is the largest and most attractive market for growing volumes of Canadian heavy oil.
We also believe that the Keystone Pipeline is the safest, most efficient, and most environmentally sound way to move that crude oil from Western Canada to the Gulf Coast. Finally, on the power front, as you can see from this chart, new generation facilities will be needed to meet growing demand in North America, but also to replace aging infrastructure and facilitate a shift to a new energy mix. We know that renewables will play a role. However, given the abundant supply of competitively priced natural gas, it is very likely that gas-fired generation will also play a key role in meeting that demand. Today, we are a leader in the development of state-of-the-art natural gas-fired generation with facilities such as Halton Hills, the Portlands Energy Centre here in Ontario, as well as the Napanee facility we have under construction currently.
With the potential for gas-fired generation capacity additions or replacements in Alberta, Ontario, and the Northeastern U.S. and Mexico, I think we are well-positioned across our footprint to capture additional contracted power opportunities as that market grows. At the same time, as we've shown, we have the expertise to participate in other forms of generation, which includes wind, solar, and in our case, nuclear refurbishments at Bruce Power. In summary, we believe the long-term fundamentals will continue to generate tremendous opportunities to connect growing natural gas and crude oil supplies to market and to replace aging infrastructure as North America shifts to a less carbon-intensive energy mix. The scope and scale of our existing footprint, along with our technical expertise, our financial strength, and our approach to responsible development are real competitive advantages.
As a result, we are highly confident that we will continue to add to our sizable portfolio of commercially secured projects in the years ahead. As I mentioned earlier, our existing assets, along with our CAD 24 billion near-term capital program, is expected to produce approximately CAD 9.5 billion of EBITDA in 2020, which equates to about a 10% compound average growth rate through that period. Given the predictability and longevity of these cash flows, we would expect to generate similar levels of EBITDA in 2021 without any further investment in projects between now and then.
As I pointed out, with numerous organic growth opportunities expected to emanate from our vast North American footprint, CAD 20 billion of larger scale projects that we have in development and significant financial capacity to fund future growth, we believe our long-term outlook for EBITDA will continue to rise as we add to our backlog of commercially secured projects. Based on that confidence in our business plans, today, we are reaffirming, as was mentioned earlier, that we expect to grow our common share dividend at an average annual rate at the upper end of the 8%-10% range through 2020, and we expect that dividend growth to grow by an additional 8%-10% in 2021. Our dividend growth outlook is supported by growth in earnings and cash flow and strong coverage ratios, leaving us with the financial flexibility to prudently fund our capital programs.
Success in advancing other growth initiatives over the forecast period will allow us to prudently extend our dividend growth outlook beyond 2021. Before I conclude and pass it over to my colleagues for their presentations today, I would like to offer a few comments about our executive team. As I said earlier, while we have great assets, they do not produce results on their own, and they require significant human ingenuity and expertise. While I am obviously very biased, I have been at this for almost 35 years in this business, and I believe that we have assembled the best talent in the industry, and that starts with our executive team. Many of the faces on this slide are familiar to a lot of you here today. Karl, Stan, Paul. Paul will not be here today.
Dean Patry will be filling in for him, and Don will provide you with updates from their respective areas. As well, we have Christine and François with us today, along, as you met last night, a number of our senior vice presidents. I would encourage you to continue through the breaks today. Seek them out, ask your questions. That is why they are here, is to let you get to know them. As well, they are supported by 7,100 other folks. As you think about a CAD 100 billion-plus company with only 7,100 people, each of those people have a lot of responsibility for certain parts of our company. They are in Canada, the U.S., and Mexico. They are experts in their fields, and they work tirelessly to safely build and operate the blue-chip portfolio of long-term energy infrastructure assets that we now hold.
It is their efforts that will drive the success of this company going forward. That concludes my initial remarks today. I will turn the podium over to Karl. He is going to update you on Canada and Mexico natural gas pipelines, and later, he will provide an update on energy. In terms of questions, I will be available later in the morning. We are not going to take any right now, but as folks get through their presentations, I will join them on the podium here and be able to answer questions with them throughout the morning. Again, thank you for joining us today. Karl, the podium is yours.
Well, good morning, everybody. I think I'll get right into it. I'd like to start with a slide because I think it remains a pretty good picture of the natural gas business, both the Canadian, Mexican, and what Stan will talk about a little later, the U.S. I guess I want to make a point here that we've been very successful in building franchises in this business. When I talk about a franchise, I'm not talking about something a regulator has given us or a government has bestowed upon us. I'm talking about a business that we've built up in certain regions that actually is a predominant business in that region. What franchises give us are a couple of things. Number one, we've built up critical masses in these regions that we are a lower cost producer.
When people come to us, we actually have competitive advantages because we do actually have the infrastructure there. Second thing it gives us is recognition, incumbency in the area. When people come to do LNG, for example, on the West Coast, they want to be part of NGTL because that's got the breadth and the supply on it. Thirdly, I think the building of franchises like this just gives us a scale so that we can be successful. When you take a look at our gas business, for example, I see three pretty large franchises there. Number one is NGTL. 75% of the basin production goes through NGTL. Right now, we're moving a little over 12 Bcf a day. We haven't seen those volumes on NGTL in over 10 years. It's a huge amount of natural gas that comes on that system.
When people want to move gas, if you want to be a big player in that WCSB region, you have to be on NGTL. Second one is the Appalachian Basin, which Stan will talk more about. Just take a look at the map on that. If you're going to be a material producer in the Appalachian Basin, you're going to touch the TransCanada system and the Appalachian Basin one way or another, depending upon whether you're going to market or if you just want to get your supply on the system. The third would be, this one that we talk less about, is our Eastern Triangle on our main line. When you take a look at that Eastern Triangle, it still has about 70% of the market share for a market in that area.
Obviously, there's no supply originating in on that area, it's a market area, it is very difficult to get around. If you want to build by it, you're building literally through very large cities. We have one franchise in the making, which would be Mexico. If you take a look at Mexico, we have a few holes to fill, when you take a look at our map there, other than a couple holes, we've got a pretty good franchise started there in the Mexico City and the central Mexico area. Outside of the franchises, I think this also gives us a good feed into market areas.
When you look at NGTL, you can go on the Pacific Northwest, you can get to California, you can get to your northern border to Chicago, you can get to the main line and then down Great Lakes into the Midwest U.S. You can get down the main line into the Eastern Canada and the main line into the U.S. Northeast. Significant breadth of different market areas. When you look at the U.S., you can get into all those areas in the U.S., California, the Pacific Northwest. You can get into the Gulf Coast and you can get into the U.S. Northeast, and of course, the big market areas in the Appalachian and central U.S. area as well. I want to touch a little bit on the reserves. The reason that we think our natural gas business is second to none.
If you look at our gas business map transposed onto the gas resource in North America, this is quite striking that the two basins that anchor our gas business are really the largest and most prolific basins in North America. It's actually amazing at 1,000 Tcf. Just think six, seven short years ago, we used to think there was about 150 Tcf left in WCSB, and now there's over 1,000 and counting, quite frankly. This represents between the Appalachian, WCSB, and North American demands, there's probably 100 years of reserves and counting still. This is going to be a big anchor to our system. You can see some of the other basins there, but really, when you take a look at the reserve estimate, the natural gas is going to be anchored out of those two, the Appalachian and WCSB.
It is really up to us to make sure that we keep the interconnectivity with the markets to make sure that those basins are allowed to produce those reserves, and that's really going to be the theme of mine and Stan's discussion, quite frankly. Moving on to what do we do with all this gas now that we've found it and developed it and made it technically possible to produce. I think Russ touched on this a little bit when he talked, but thought I'd give a little bit more broader look at it, kind of a 10, 12 year view. We're seeing a lot of this right now. Where is the gas going to go? Well, we all know in this room, everybody covers the upstream sector as well.
We all know that the prices are moderate for natural gas, a lot lower than they used to be. That is causing a demand response. We see it every day in our pipeline. You take a look at the industrial sector, we see it every day in our pipeline, especially chemicals, fertilizers, and industrial still coming back to us asking for capacity to either reestablish themselves in North America or to start anew. The natural gas cycle, business cycle, and the price cycle is working. It is bringing back market into the United States. People that left to produce overseas are coming back, and it is creating new businesses on our system to consume gas. You can see that this is TransCanada's forecast right here, but every forecast I look at is pretty much similar. Electric generation.
Not only is coal being phased out by regulations in Canada, for example, and replaced with gas and renewables, but gas is also winning the gas on coal competition North America-wise. It's at a price point now where it is starting to beat out coal. So we're going to see gas continuing to penetrate the electrical generation space. You can see that in this graph. I think that's a long-term trend. Renewables aside, renewables will always catch a piece of that market, and we'll talk a little bit about that during my energy discussion, but gas will always be there for a piece of it. Of course, LNG exports. This graph's a little bit misleading. This is average annual, but there's more LNG exports even today than even shows up on this graph.
If you take a look at today's LNG exports, it's greater than it even shows up here. In LNG exports, I think, obviously, we're looking at West Coast, British Columbia, and the Gulf Coast, and Stan will talk a little bit about his plans on the Gulf Coast. Regional demand growth over the next decade. We wanted to put up a chart on what we think the actual growth is going to look like, and I think this graph is a little telling. If you take a look at our traditional markets, that being the WCSB, the NIT market, the Eastern Canada, Midwest, U.S. Northeast, they're all growing still. They all have some growth involved in them, but that growth, quite frankly, isn't that significant. Take a look where the significant growth is.
Aside from Mexico, which is really an electric and an interconnectivity play for on gas, when you take a look at the growth in North America, it's really centered around LNG. The West Coast of Canada and BC, West Coast, Oregon, Gulf Coast, the Southeast, it's really a big LNG place. If you take a look at our infrastructure on this map, you'll see that not only have we got a good anchor with the basins that I showed earlier, you can see that we actually have pretty good anchor with lead-ins into market areas. This is really key for our strategy going forward, is to make sure that we can get our gas into market areas through our systems. We don't want to be an intermediate carrier.
We want to be able to get gases on our system right into markets, Stan will talk a little bit about his plans on the Gulf Coast. I can tell you, Russ brought it up on the West Coast BC. We're still fully engaged, I'll talk about that in a minute on West Coast BC. We're still fully engaged on moving gas there. Quite frankly, we're still fully engaged on even getting to these, our traditional markets, but I think the big increase in markets is going to be where the LNG is. Just to give you an idea what our system can do today, we can move, we have made proposals to customers. We're not moving these paths right now, but we have made proposals to customers.
We can move gas from Northeast BC up in the Montney area, all the way into the Gulf Coast using predominantly our own system. We can put a tariff together for that, and I think we can make it competitive. We have seen some WCSB gas moved into the Gulf Coast LNG market already, not through our systems, but I think we can compete with any other system out there. If our producers want to do that, we can provide that for them. We are hopeful that WCSB can find its own market off the West Coast, if it can't, we can actually still access LNG for our customers, for our producers. For that matter, we can actually move a Northeast BC unit of natural gas into Mexico City once we get Sur de Texas fully built out, which will be about a year from now.
We can offer our suppliers flexibility depending upon where they want to go. They can stay to local markets, or they can go off to far-flung markets. We can price both of them. Going on to natural gas now, natural gas business. Really, our work is simple right now when we look at what we're doing in natural gas. It is connecting, getting our systems, getting them built out to accept this high new gas production that we have, and then finding external markets for it, getting connectivity to those external markets for it. When you take a look at what's going on in NGTL right now, it's all about getting the gas out of the system into markets. In NGTL, we have placed CAD 2.3 billion into service this year, or we will have placed CAD 2.3 billion by the end of the year.
That's 30-odd projects that we brought in this year at NGTL. We actually beat our estimate a little bit. We didn't expect to get all 30 projects in this year. You can tell just by the gas where we've now hit new peaks in production on it. There are less constraints in the system right now, I would point out that it is winter in Alberta. It may not look like it here, but it is winter in Alberta. We do have higher demand rates in Alberta, that is alleviating some of the problems we had with oversupply. We also secured an additional CAD 2 billion worth of projects out of the NGTL system over the last year. This is interconnect 3 billion cubic feet a day of new gas supply and delivery requests.
About 2.3 billion cubic feet a day of that is new receipt supply, new supply onto our system. That'll be coming in the 2019 and 2020, a little bit into 2021 range. 700 million day of new delivery service on their system. That's getting the gas off our system into markets. About equally split between going to GTN, going down the West Coast, and going into the oil sands. We are starting to see a bit of an imbalance right now where we're getting more receipts than delivery contracts. I suspect with the price signal going out to our customer base, that we will see that moderate and reverse itself over time. I think you can expect as time goes on, we'll see more delivery contracts being requested and less receipt to take that balance off.
If you look at our balance contracts on the NGTL system right now, they're actually quite balanced, but you have to understand, they each have different load factors. A receipt contract has a different load factor than an LDC contract, for example. Even though our contracts are balanced, you will see supply-demand imbalances crop up depending upon the load factors of the different contracts. We have been very successful in other parts of our system this year as well. The LTFP was approved by the NEB and was implemented for November 1st. That was quite successful approval. I think it cleared a lot of the surplus that has been nagging us on the mainline for years.
What it has done is it's taken 1.4 billion cubic feet a day, really taking it out of the market, and now the rest of our capacity is that much more valuable, that much more sought after once we got that in. I think that the LTFP was a very meaningful thing for the mainline. We've also expanded through this year. We've expanded the Eastern Triangle, and we're continuing to work on Mexico. To talk a little bit about NGTL. It's our largest system. 12 Bcf, I talked about moving through it, a little bit more than that. CAD 8 billion right now in rate base. As you can see from the diagram there, the system is continuing to change.
We've gone from a system where it used to be very Gas was distributed through the entire system, through the entire NGTL system, to really 85%. It's actually a little bit higher than that now. Last I calculated, it was closer to 90% of it's coming out of that Montney, Duvernay deep basin part of the system. It still requires some catch-up on it. When you see a mass change like that in your system, everything changes on your system. The compression, the way compression works, the amount of capacity you have in your system, everything changes, and that's what we've been really busy trying to sort out the last couple of years. Everybody's probably aware of the struggles that some of our producers have had, some of our shippers have had on the system with service cuts, with maintenance.
One thing I will say is that we've had a bit of the perfect storm. As we've been reconfiguring our system to take care of this new gas right here, we have seen supply go up substantially. With that supply going up, we have seen more supply in our system than local demand. We've seen a number of issues on our system, we've had some cuts, we've had some maintenance that people are feeling now because the system's so full, we've seen oversupply in our market. We do see lots of publicity over what's causing the cuts and what's causing the volatility. I can tell you this, that there is more supply than demand on the system right now. If you are trying to track local market on this system in net, you're going to have some issues with volatility.
Right now it's okay because winter's here. Demand is up in our system. Come spring, you will find that the volatility will return. The real trick on this system right now is to get export capacities and go find markets that aren't in such surplus right now. The maintenance cuts, they're few and far between. The capacity cuts are very few. We're talking the cuts that are episodic. They're small. They're generally under 300 million a day. They're not causing the volatility that you're seeing right now. The volatility is being caused by more local supply on net than local demand. Rest assured, we're doing everything we can to make sure this problem is alleviated. Even the cuts we have today, which are down about a third from last year, are too much.
You'll see with the 30 projects we put on this year, they'll go down even more, and next year, our projects will reduce it even more. Current rate base is CAD 8 billion on NGTL. With just today's construction program, we are working up to about 12 Bcf a day. We're expecting some more, quite frankly. We still have over 1 Bcf a day in the queue of new receipt service requests. We are expecting to hold an open season shortly for some demand services, for delivery services requests. There'll be some more coming out of this as we continue to work to de-constrain it and to get more connectivity to outside. If you do think about it, the price signal is working.
If you think about a couple of years ago, we had a situation where people were using IT, not FT, and then there was no more IT. The producers, after some pain and some soul-searching, started contracting for FT. Now we're seeing the same type of effort right now, where people were used to selling their product in net, and now that net is oversupplied, we're starting to see them want to get out of net and buy delivery service. The Mainline has seen some changes over the past few years as well. We're still on track to split the Mainline in two, the Western system and the Eastern triangle, in 2020. That's still on track. In the meantime, we're going through a rate review in 2018 here, to reset the rates.
I am very happy and proud actually, to say that this is going to be the first time since my tenure here that we're going to actually reduce the rates on the Mainline. It's been a long road. I've seen lots of rate increases during my tenure on the Mainline as we sorted out the issues. The volumes are stabilized. Things like the LTFP brought stability to this Mainline. I think for the first period of time I'm not going to go over what the exact cuts are. It depends what route you are. It'll be the first time since I've been here that we've actually seen the rates go down on the Mainline. That's something we're quite proud of, that we've been able to bring the Mainline to the point where we stabilized and started lowering the tolls.
The contracting on this system is about 8 billion cubic feet a day, a little bit higher than that. 3.8 of it is coming on the Western system, long haul, and the rest of it will be very short-haul contracts. Significant billing determinants still on the system. As you can see, significant gas is moving on the system. I would like to say that the Mainline's in good shape today. The LTFP has worked. It has cleared our surpluses, and I think that has actually made the rest of the capacity on the Mainline more valuable to our customers now that there's not this big overhang. What's the future capacity that we're going to look at?
We have to find routes out everywhere, and I'll let Stan talk a little bit about what he's planning for as some of the U.S. pipelines that take away WCSB. If you think of the WCSB and the NGTL and the Mainline's headwaters to some of the U.S. pipelines, Stan will talk about that. Really, we're working with everything we can. If our producers want to take more gas east, we will do another LTFP, and we will bring back some of the capacity on the Mainline to go east. Right now, the Mainline is full at about 3.8 Bcf a day. There's volumes coming on and off, and there's actually a little bit more there, so it's not completely full, but it's a very good level at 3.8.
If our shippers want to ship more, we can bring some of the latent capacity on the Mainline back into services. It shouldn't be that difficult. When we took it out of service, it was just a matter of maintenance, and we can do the maintenance and bring it back on service. If our customers want to go east, we can bring back some of that capacity, and we can do another LTFP. We are working with our LNG customers to do whatever we can do to make that LNG more viable. We certainly will do it because that's going to be very important for the WCSB. Other concepts we're looking on is aggregator roles. If we need to aggregate volumes to take to the West Coast for LNG, we will do that.
If we need to aggregate volumes to sign contracts on the NGTL, we'll do that as well. I don't want to start up another Western Gas Marketing or another aggregator pool, but if I have to, and it's in the best interest of TransCanada, we will. I think Russ talked about Coastal GasLink. Again, we're waiting for an FID. We continue to be fully engaged with our sponsor company here on getting this over the goal line, and we have been told they'll make a decision in 2018 at some point, we look forward to that. I think it remains an important project for the WCSB. It's very sad that we lost the Petronas project. We did submit all of our bill for all of our cost on that project, and we did get that paid. I think Canada's lost a very stand-up company.
They're great to work with, and we will miss them being a big customer of ours. What is the near-term growth projects? I think we've talked about most of these. It's all LNG, or NGTL base and some Canadian Mainline. As I said, I think there's some more in the hopper as we continue to deconstrain the system and as we go to get more connectivity outside of the system. Stay tuned for that. In maintenance capital, I'd like to spend a couple of minutes on. Maintenance capital on our systems, regulated systems, are as good as growth capital. We immediately, in Canada, we start earning return of and on investment on them. As your system gets full, as it gets higher load factor, as it grows, you need more maintenance capital, and that's exactly what we're seeing on this system.
We're seeing about CAD 600 million a year on both of them. That's been consistent even before the 2017 start here, and we're expecting it'll stay about the same or maybe even get a little higher as we do more maintenance, more integrity as our flows continue to max out these systems. I think you'll see the maintenance capital will continue to be out there. Both systems are actually fairly old, they do require, to keep that capacity going, they do require some maintenance. We consider maintenance capital to be a good thing in this particular business because we do get to roll it in the rate base, and we do get to earn our return on and of capital on that. Just to show you the natural gas net income outlook. I put up net income as well as EBITDA.
EBITDA is tough in putting natural gas because of the way the regulatory compact works. In EBITDA, there's lots of stuff that's flow through. Taxes are flow through. There's lots of flows through. It's probably not as good an indicator. We tend to use EBITDA everywhere else in the company, but I threw up the net income outlook too, because that's really going to show you the relationship between the capital that we're putting in and the increased net income coming out of the business. Mexico. We talked a little bit about it. We right now have four projects that are actually earning revenue, we've got three that are under construction. We got the Tula and Villa de Reyes both a little over half a billion dollars each USD, they'll move 900 million a day.
These are really pipelines that take it from the Gulf Coast into the Mexico City heartland. We have Sur de Texas, which is the offshore going from Brownsville down and connecting into both of these facilities. The construction is going well. On Tula, we have run into some indigenous issues where there was a bit of a delay on certain portions of it. For the most part, we're going to get most segments of these pipelines probably in service before the end of next year. There might be some that are going to have to wait because of consultations. We should be able to get at least partial usage of these systems before the end of next year. The Sur de Texas, which is kind of the more technically complex, where we're putting 42-inch pipe on the ocean floor. It's going really well.
We're laying about 3 km of pipe a day. We're probably over about 300 km right now have already been laid, and we're starting all the tie-ins on the onshore pieces of it. We own 60% of that. IEnova is our partner in that particular one, and it's slated for late next year in service as well. What are we going to do with Mexico after we finish this construction? Well, I put this graph out here because I believe we've got this fairly good infrastructure there. Now we have to go fill it up. Now we've got to do marketing department. We've got to go interconnect this with industrials. As we've talked about before, they don't use a lot of gas in the industrial segment in Mexico.
Natural gas delivery has never been a very good business for Pemex, so Pemex hasn't concentrated on it, and the industrials have gone to fuel oil and propanes and butanes. This gives you an idea of where we're going to be working on the next little while. We're going to be filling up our pipelines. Our pipelines have got great bases now with our CFE contracts. But every dollar we can earn from feeding an industrial, we get to keep. It's going to be smaller business, but very profitable for us. And this one gives you an idea of what Mexico's going to look at come a couple of years after we get the last three projects in service.
We're going to see about midway between CAD 500 million and CAD 600 million in EBITDA a year on it, and this will come about with the completion of our existing CAD 2.5 billion construction project. You'll still see quite good growth on that. The future of this is not over when we finish this growth. There will be more power-related business, and as I said, there's going to be more other interconnections as people start transitioning off fuel oil and LPGs and onto natural gas. What is the key area of focus for the business? Well, advance our near-term projects. Number one, we're not going to stop until we get these projects finished, till we get NGTL built out, and we get our customers' gas flowing better. We're going to maximize the value of our franchises.
We have a lot of work to do, both in Canada and Mexico, to make sure that we optimize these systems and make sure that the systems are operating good, not only physically but financially. We have two rate settlements that we're working on right now, one on NGTL and one on the Mainline. Mainline will go to a hearing. We just won't be able to get a full settlement on. I will say we do have people that are supporting what we're going to be filing. So it is just a rate hearing. There's no real depreciation studies or anything like that coming to this hearing. It'll just be a reset of the rates. On NGTL, we remain in negotiations with customers on potential settlement there.
Driving competitive growth initiatives, the capacity investments across our network, the WCSB growing, these are all things that we're spending a lot of time on. This is the time right now. The business right now, the growth is here today, and we intend to get more than our fair share of it. We are going to be spending day and night figuring out how we can evacuate more gas out of the WCSB and into other regions, and hopefully, you'll hear some good news about that shortly, because we do recognize that in order to get that gas and trap that gas, we're going to have to find a new home for it outside of NIT Advance long-term opportunities. Coastal GasLink, it's a bit of the sleeper I've heard it called.
Shell has certainly relayed to us as a partnership that they're still excited about that project, and I see every day them working on it, and that's something that we want to play our role in it, and we want to make sure that everything we can do to make that proceed is being done. With that, maybe I could open up for a few questions.
Sure. That's great. As we take questions, we've got a couple of mics that'll move around the room quickly, one so that everybody in the room can hear it as well as those on the webcast. If you could just raise your hand, we'll get one to you quickly. Again, just a reminder, one question and a follow-up. We will try to distribute things so that numerous people have an opportunity to ask questions. Go ahead.
Yet we still don't have a project in Canada that's reached FID on Canada's West Coast. My question to you is, what has to happen for a project of significance to reach the FID stage in Canada? What makes you confident those projects can overcome those challenges?
It's a good question. What has happened, I guess, is the question and then what can be done about it. It's hard to say. You have to talk to Petronas to find out really exactly what happened in their project to go. I can tell you, Petronas had a lot of difficulties just with the permitting process and what they had to do to change their plant in order to make it conform to what the regulatory process was asking it to do. The market changed as they were through this long journey of permitting. I think the last major project today, there's a bunch of smaller projects still on the West Coast that are still motoring along. The last major project, LNG Canada, doesn't have those same problems. It's already fully permitted. The pipeline's already fully permitted.
It's really an economic problem, economic issue for them, and it's an allocation of capital for them. I do think that my understanding is 2023-ish is the next window for LNG, and I think that people on the West Coast understand that, and I think you'll see some action as people start trying to now move their projects towards that kind of 2023, 2024 timeframe. I think that says there's no secret as to why I think that 2018 is what the LNG Canada says their new FID date. I think you need to come out with FID in this particular time in order to hit that type of window. I think right now for a project like LNG Canada, it's hitting the proper window and capital allocation on their part. I don't think the external factors bear down on that as much anymore.
Certainly, they're trying to get that they've gone and rebid their capital, rebid the project. They're asking us to sharpen our pencil. Certainly, they're doing all the right things there. I do think it's a matter of their own capital allocation and trying to meet that window. How do they best meet that window? Is it better to do West Coast LNG, or is it better to do Gulf Coast? These are types of decisions they're making.
Sure. Go ahead. Andrew?
Andrew Kuske, Credit Suisse. Karl, when you think about just the Canadian Mainline and reactivating portions of it that haven't been used for years, if you're successful in really reactivating parts of it and you manage to draw more shipper interest, how far do you think tolls can go down?
I haven't looked at that, to be honest. What I would probably do on that is in order to reactivate it, there's going to be some capital involved. It shouldn't be the equivalent of a brand-new build. What we're doing is we're putting maintenance in, essentially, expedited maintenance to get it going again. What I probably would do is I'd probably do another LTFP. I'd probably do another fixed price deal to sell that for a period of time, probably 15 years, is kind of what we're thinking. I'm not sure. What would that do to the overall tolling methodology? I think it's speculative to say right now, but I will say that it should be good for the system.
I would not do it unless it didn't mean that the system would get revenue that it wouldn't otherwise get, which means directionally the tolls will decrease with it. It's just speculative right now to try and give you a number. We would not proceed with it unless it added to the revenue of the Canadian Mainline and would moderate everybody else's toll. Every time you do a load-attraction rate , you really have an obligation to make sure that that rate has something in it for other shippers on the system as well. We would make sure that would be the case, directionally down.
Go ahead. Faisel, sorry.
Thanks, guys. Faisel Khan with Citigroup. If I look at all the capital you're spending on NGTL and the Canadian Mainline, and I look at the incremental EBITDA net income, it seems fairly low. Can you just help us bridge the gap on what sort of financial metrics you're looking at in terms of what kind of return you're going to earn on this capital that you're putting to work over the next few years?
Well, I guess I can tell you a couple things. There's a couple reasons for that. Number one is we still have a 3.19% composite depreciation rate. Although I'm investing CAD 2 billion a year in the system and pulling out half a billion dollars a year in depreciation when you take a look at it. You'll have to take a look at the NIT capital we have in there. On the NIT capital we do earn, and we are in some of the negotiations, but I'm pretty steadfast on this number, but we do earn on 40% equity thicknesses, 10.1% equity return on 40% thickness. Those are numbers you're seeing in their NIT capital, and with those types of returns, and when we've done those, we've assumed that return carries on.
I do think when you add up the numbers, you have to think about how much depreciation we're taking out every year as well. If we have a CAD 5 billion program over five years, for example, we've taken two and a half billion, or not quite two and a half billion, but CAD 2 billion plus of depreciation over that period of time as well.
Rob Hope, Scotiabank. You mentioned earlier about an upcoming open season for delivery on the NGTL system, and I would imagine that would be part and parcel potentially with an LTFP. Do we have a timing of when we could get incremental capacity out of the basin and at what cost?
Well, for the delivery capacity for the NGTL, we haven't really finished our engineering on that, but I doubt it'll be much before 2020, 2021. I think that seems to be the regulatory schedule we're on right now. As you know, it's not construction that's the issue. The time thing is regulatory permits. Capital costs I don't have yet. I'd be speculating if I were to give you capital on it right now. To give you an idea of the size, we would probably go out looking for maybe 1 billion cubic feet a day of natural gas to get a delivery contract with. Give you an idea of that.
Jeremy Tonet, J.P. Morgan. I think in Western Canada, you noted the potential to be an aggregator or marketer. Just wondering if you could expand a bit more there, given the challenges we're seeing in AECO pricing. What more would you want to see before you took that step to try to push more volumes out?
Well, I think, I've been advocating this to my shippers for quite a while now, that they have to start looking outside of the net. I think they got to do it now. I think right now what we found is that even though the contracts are mass, they've got such different load factors, especially in the off seasons, that you're not going to get away from the volatility. It's easy to blame the volatility on maintenance or on cuts, but the volatility is coming because there's more supply going after a limited market. In the last year, we have sold about 1 billion cubic feet a day of more delivery capacity of people wanting to get out of our system, either through the West going down GTN or out East on the Mainline. I still think we need more.
I think people have to now start thinking about their portfolio differently than they used to. No longer can you just dump it in the net and expect it's going to be a premium market. I think right now you're going to think about producing in the net and what portion's going to leave and what portion's going to stay. That's something that we've worked with our customers. Unfortunately, I think the price signal is speaking to them a little louder than we have over the last couple of years. The price signal is telling them right now that they should be paying attention to this, I'm expecting that to work with them over the next couple of years and move it out. I think any incremental that comes along, we'll have to find some delivery service for.
Yeah. Pat Kenny, National Bank. A related question on NGTL, just with the rate base going up 50% or so over the next few years. Just a few weeks ago, we saw the second-largest natural gas producer in Canada say that it doesn't make sense to grow their natural gas volumes at CAD 2.50 AECO or less. Just how do you think about managing the upward pressure on the tariff as the rate base grows by 50% and could potentially exacerbate the problem for producers?
A couple points I'll make of that. Number one is they're really speaking to, they're not going to produce into the net market because they think the net market's saturated. If we can find more capacity out, they might change their mind depending upon what market that capacity goes to. The second thing is, we have such good contractual underpinning of this. We're actually seeing our tolls fall. Our interim tolls right now on NGTL for next year that we've already filed have shown, depending upon where you are, a decrease. An overall average decrease, but depending on where you are, because we have floors and ceilings, locally, you might have seen some increases in some parts of the system, but overall, on average, it's been a fall.
I don't think yet, because we've seen supply back up the expansions, I don't think we've seen it actually add to the tariffs. It's actually gone the other way. I don't think that's the immediate issue with producers. I think the immediate issue with producers is I have nowhere to produce into other net, and I'm not happy with how net is responding to the oversupply.
Just time for one more.
Tom Abrams from Morgan Stanley. I was wondering if you could talk about Mexico a little bit, elaborate on the permitting process down there, you've mentioned indigenous issues. Is it sites? Is it water crossings? Is there a consultation process that includes vetoes? Are there regional governments that are also making jurisdictional issues along with the feds down there? Just elaborate a little bit perhaps on the background.
Mexico, there's no free ride anywhere, unfortunately. Mexico, you go in, it's just as hard to get a permit in Mexico as it is right now in Canada and the U.S. Indigenous consultation is done by the government of Mexico, so we're kind of a bystander. We have good force majeure clauses. If they don't get it to us by the time we get relief from our contract and different provisions. It not necessarily delays us, but doesn't necessarily cause us penalties or anything. It doesn't increase our cost per se to do it, but it can delay us. Our ultimate mitigation to that is doing a reroute around the community if we don't believe the government can be successful in their consultations. The consultation, is it consensus? What is consensus? That's something that's debated every day in Mexico, just like it's debated in Canada.
What is the end goal of consultation? Just to give you an example, right now on Topolobampo, we had the Rarámuri group that didn't want the pipeline going through there, we finally gave up waiting, we routed around them. That's how we got around that particular issue. On Tula with this one, we will only wait so long. We do see progress, by the way, which is why we haven't moved to a reroute. We have seen progress, but it does delay the project, at least a section of it. When you take a look at Tula, you've got section in the City of Mexico that actually can be used, so we get that in service. You've got section around the coast that can be used, it's the middle part that actually we have the consultations.
We'll actually be able to put parts of it in service anyways and earn tariffs on that as well.
Okay. Sorry, just before we finish up. Go ahead, Robert.
Great. Thank you. Karl, just continuing on Mexico, now that you've got construction projects to pretty much connect up the entire link, can you talk about the potential upside from filling up those pipes? How has your thoughts on that upside changed over the course of, call it, the last year? Specifically, how much did that factor into the decision to keep 100% in Mexico?
Yeah. I don't know if that factored in the decision to keep 100% in Mexico. I think other things factored into our ability. When we took a look at it, our ability to actually continue to finance this internally, the discounts we were conceivably going to take because it wasn't all built out. These are the types of things that I think went more into the decision not to sell a piece of Mexico than the upside on the merchant. I do have to admit, when we were selling it, I was not happy that nobody was giving that any credit because I do think it's Is it material? I can't put a number on it for you, but I think it's going to be substantial. Because every CAD we get, we get to keep. Is it going to be like getting another huge investment? Probably not.
This is all on the margin sort of stuff. I think we could have. As time goes by and we connect more and more people, it can be actually a pretty good base for the business. I'm not going to sit here and speculate on how much money we can pull out of it, but I do note that nobody uses gas, and that over time, we will find a way to make sure that gas is a preferred fuel. Over time, we'll find a way to make sure gas gets in that process heat there. I can't give you a number right now because I don't have it, and if I did, it would be speculative anyways. I have a marketing group kind of doing some analytics for me, telling me what they can do. They're looking for funding.
I'm not going to go share that with other people just yet until we see some proof in it.
Great. Thanks very much. Thanks, Carl. I think, again, as we've highlighted before, management's around all morning. Feel free to catch up with them over the break or at lunch. With that, we'll turn the podium over to Stan Chapman. Stan is President of our U.S. natural gas pipeline business. He's going to provide you with a 20-minute overview, if you will, of what's going on in the U.S. He'd be prepared to take your questions as well.
Thank you, Dave. Good morning, everyone. I appreciate the opportunity to share with you our story as to what's going on in the U.S. I think that you'll find that it's a good story. It's a growth story. My hope is that after I finish my remarks over the next 20 minutes or so, you'll share the enthusiasm that I have, not only for the good work that the team has done to date, but for all the opportunities that are still ahead of us. Since this is the first time that we're together in an Investor Day post the Columbia acquisition, I thought it would make sense to take a step back and look at how the U.S. Pipeline group has evolved into a broad national network.
We now operate an interstate pipeline transmission portfolio that extends over 31,000 miles, making us one of the larger transmission providers in the United States. We operate around 550 Bcf of natural gas storage capacity, making us the largest storage provider. We have roughly 3,000 employees that are dispersed across assets that span across 36 states. We touch about one in every five molecules of gas that's delivered across the United States. Our assets are strategically connected to two of the best and lowest-cost supply basins in North America. If you look at the map in the Northeast, you see the direct access that the Columbia Gas system has over the Marcellus and the Utica. I'd ask you to think about our pipeline systems like GTN and Northern Border and Great Lakes as conduits for WCSB supplies to get to demand centers.
Demand centers that include not only LDC markets, but LNG offtake opportunities, industrial growth opportunities, and pipeline interconnects. I also should note that while we operate all of these assets, some of them are owned in whole or in part by TransCanada PipeLines, LP, the MLP. 2017 was a pretty busy year for the U.S. Pipeline group. Good news, the Columbia Pipeline Group integration is now behind us. If you recall, with respect to synergy capture, we had a target of CAD 250 million of synergies, CAD 100 million of which was finance synergies that were undertaken earlier in the year. We had a target of taking out about CAD 150 million of costs from the business unit, and I'm pleased to report that we are on track to meet or exceed that target.
We are starting to see the benefits of years of negotiations and hard work in that our growth projects are starting to go in service and starting to cash flow. Our Rayne XPress and our Gibraltar projects were placed into service earlier this month, and in very early January, we're going to place our Leach XPress project in service as well. The team has been very focused, driving favorable results on rate case settlements, most notably on the Great Lakes Gas Transmission system and the Northern Border Pipeline system, both of which are going to provide a source of long-term stable revenues going forward. Long-term revenues in the context of a comeback provision on Great Lakes is not required for five years, so summer of 2022, give or take. On the Northern Border system, a comeback is not required until six years, which would be very early in 2024.
We are about to finish at the end of this year, phase 1 of Columbia Gas modernization program, which in the aggregate was a CAD 1.5 billion investment opportunity for us, we're immediately going to roll into phase 2 of the modernization program, which will span from 2018 through 2020. That in of itself will be a CAD 1.1 billion investment opportunity, and for the first time will also include some of our storage assets. I'll get into details on our growth program in a couple of slides, but suffice it to say, we did increase our backlog of projects to $8.5 billion USD. We completed two drop-downs with respect to our LP. As you'll see here in a second, we're going to have strong EBITDA generation out of the U.S. pipes for 2017 and forward. When you look at things from a big picture, our job is relatively simple.
It's to find the fastest-growing and lowest cost supply points and to find a way to get that supply to some of the fastest-growing demand centers. Karl's already walked you through a little bit of a macro review, so I don't want to be redundant there. I would note that when he talked about supply, he talked about it in the context of reserves. I'm going to talk about it in the context of production. Takeaway is we are producing more gas in the United States today than we ever have. Matter of fact, headline article on Gas Daily today says that over the weekend, we hit a new high, 76.8 Bcf a day of gas production in the United States. When you look at the Marcellus and Utica component of that, it was around 27 Bcf produced over this weekend.
What that tells me is that we are on track to end the year 2017 producing somewhere around 25 Bcf a day out of Marcellus, Utica, the Appalachian region proper, and it's not stopping there. It's almost mind-boggling to think about it, but over the next 10 years through 2027, that production is likely to increase to 40 Bcf a day. You could think of all the changes that have occurred from 2010 or so until today, and we're really only about the halfway point in this game. Much more production growth to come out of the basin. Similarly, on the demand side, most of the demand growth or predominant amount of the demand growth is in the Gulf Coast, driven primarily by LNG exports, but also fueled by power generation growth, industrial growth, and other market needs.
What makes me excited when I look at this map is the two lines that you see that connect the dots, so to speak, that connect the fastest-growing supply points out of the Marcellus to those demand centers in the Gulf Coast. Most importantly to the west, that's the ANR Southeast Mainline, and then to the right is the Columbia Gulf system. Think of those as two of our flagship assets, and I thought it would make sense to do a little bit of a deeper dive, particularly around the Columbia assets, since some of you all may not be familiar with them. If you look in the northeast quadrant of this map, that is Columbia Gas, a reticulated system. You could also hear references to that as TICO from time to time.
The leg that extends in a southwesterly direction down to the Gulf Coast is the Columbia Gulf system. Keep in mind, these systems were designed decades ago to aggregate supplies on and offshore Louisiana and move them in a northeast direction to market. We are spending CAD billions right now to physically turn those systems around to be able to flow that gas from southwest Pennsylvania to markets south in Louisiana. Think of it as a pipeline system that has 96% of its revenues coming from take or pay type contracts, long-term type contracts. Weighted average contract on the Columbia system is around nine years. You'll hear references quite frequently to TICO Pool. TICO Pool is a logical point. It's a point of liquidity on the system. On a paper basis, there's about 5 Bcf of gas that trades on a day.
Physical liquidity out of the pool, physical flows out of the pool are about 1.5 Bcf a day. You'll see that a majority of the CAD 8.5 billion backlog that we have is tied up on the Columbia assets, either on the Columbia Gas or the Columbia Gulf system. I'll go into details on each of those here in a little bit. The other flagship pipeline that we have in our portfolio is the ANR system. Again, a large interstate pipeline network. Similar to the Columbia system, most of its revenues come from long-term firm contracts, take or pay type contracts to the tune of about 93% of its revenues. You could think of an average contract term of about 10.9 years, so just under 11 years. Significant provider of storage services, predominantly in the Michigan area.
Big success for us in 2016 was the culmination of the ANR rate case. All things equal generated an uptick in EBITDA of about CAD 82 million, and had its own unique modernization program in a way. A program that provided for additional maintenance capital expenditures to the tune of CAD 837 million to be spent over a 3-year period. It also provided for recovery of those dollars effective day 1 in August 2016 when the rates for the rate case settlement went into effect. We've also been the beneficiary of some Marcellus and Utica growth on the ANR system, recently riding over 2 Bcf a day of contracts, predominantly on the Southeast Mainline. You could think of that as receipts coming into us either at our REC Center connect at Fairfield or at our WestREC interconnect, which is at the Defiance area.
Roughly 1.1 Bcf a day of that is flowing south into markets in the Gulf Coast, and about a 0.9 Bcf is flowing north across the tie line over to Midwest markets. You can see ANR also provides key interconnects to Karl's system in Canada via the Great Lakes system as well. With respect to growth opportunities, predominantly on the Columbia system, you see our backlog here has grown to about CAD 8.5 billion. I thought I'd take a few seconds and just walk you through a couple of these. Our Rayne XPress and Gibraltar Express projects, roughly CAD 700 million of capital, were placed into service earlier this year. Our Modernization I proceedings, as I mentioned, will culminate here on December 31st with a CAD 1.5 billion cumulative investment. Leach XPress is our first big project that will go into service in very early January 2018.
You can think of that project as operating 5 spreads overall. 4 of those 5 spreads are going to be ready to be placed in service here in the next couple of days. There's 1 spread, which is spread 1, which we refer to as our mountain spread, that during late October experienced a lot of rainy weather, and we had 1 or 2 major pipeline slips, and that's what set us back a little bit. We weren't able to recover from those pipeline slips and get the project in as early as we'd like. Very early January in-service date. We actually have FERC staff coming out to do a site visit here next week to do some of the preliminary in-service sign-offs.
We expect them to have a punch list of items for us that we'll take care of over the Christmas holidays and then get this in the ground with all due haste. Cameron Access project is 1 of our LNG projects, where we're building a new lateral over to the Cameron terminal. We'll have that ready to go in service sometime during the first quarter 2018, although the terminal itself is going to be delayed into much later in 2018. Very excited that we recently received our WB XPress order. As a matter of fact, we filed just before U.S. Thanksgiving last Wednesday to accept the order, and we expect any day now to get our final notice to proceed from the FERC, and that will allow us to physically start construction.
As things sit right now, we plan on holding our November 2018 in-service date on the Western path. There may be a month or two slippage on the eastern in-service date, but that will not be material. Big project that we're waiting for a FERC order next is our Mountaineer XPress and our Gulf XPress project. Mountaineer XPress, CAD 2.6 billion. Gulf XPress, CAD 0.6 billion. A significant project for us. I'd like to have our FERC certificate yesterday, to be honest with you. What we're hearing from those that are in the know is have an expectation of receiving an order by year's end. I think that there's a potential for that to slip into early January.
All things equal, as long as we get the certificate and start construction in mid-January at least, we think we can hold our in-service dates with respect to Mountaineer XPress as well. Modernization II, a great opportunity for us to spend CAD 1.1 billion on integrity and reliability across our system and to recover the cost associated with that capital almost immediately. All the capital that we put in the ground as of October of a given year, we earn recovery on that starting the following February, so very short delay there. Buckeye XPress is our latest project out of the Appalachian Basin, which I'm going to talk about in more detail in a second. A lot of singles. A lot of singles that at the end of the day add up to critical mass to the tune of around CAD 400 million worth of other projects.
When you think about it in the context of rate base, rate base across all of our assets today is somewhere just north of CAD 10 billion. A little over CAD 1 billion of that is held by the LP. You could think of us as effectively doubling our rate base. CAD 9 billion worth of non- LP assets today, CAD 8.5 billion more of assets going in the ground by this time next year, getting us to a total rate base of around CAD 18 billion, CAD 19 billion. That's pretty exciting growth.
I thought I would take a step back real quick and talk a little bit about maintenance capital because we have seen an increase in maintenance capital across our systems. You could think of us as spending around CAD 600 million in maintenance CapEx this year and then staying in that general zip code for the next several years.
You could think about maintenance capital falling into one of two categories. First is associated with reliability work that needs to be done to support higher flows across our system. That is a good thing because it indicates a demand for our assets. That is predominantly what the ANR maintenance capital work is for. I referenced earlier the additional two Bcf a day of contracts that we sold across the Southeast Mainline. The CAD 837 million that we'll be spending from 2016 to 2018 is to support those flows. I want to reemphasize the point that we are recovering the cost of that CapEx in our rates already, prior to even spending all of the dollars. The second bucket of maintenance capital is tied to predominantly the Columbia system and associated with regulatory requirements due to class changes associated with pipeline encroachments.
You could quite simply think of pipeline encroachments as population centers, housing areas, and the like, coming closer and closer to the pipeline, which all things equal means we either need to take a D rate and reduce capacity, which doesn't make sense because in most cases, we have excess demand for that capacity, or do certain work to upright the system, which could include cutouts and replacing the pipes. That will be a program that will be undertaken for the next three years or so. When you look at the EBITDA growth out of the U.S. business in particular, it's pretty darn impressive, I think. Let me just walk you through the evolution. Go back to 2015, prior to the Columbia acquisition, and TransCanada's U.S. pipelines at that point in time earned around $700 million of EBITDA.
2016, the Columbia acquisition went live on July 1 of 2016, we only had a half year of earnings. If you were to annualize Columbia for a full year of 2016, EBITDA for the U.S. pipes would have been about $1.5 billion. Almost a doubling in and of itself with the Columbia acquisition from 2015. This year, in 2017, we'll earn just north of $1.8 billion in EBITDA. What's exciting is once we cash flow and get the balance of these projects in service, that in and of itself is an extra at $900 million of EBITDA. 2019, 2020 run rates, just with the projects that are underway today, is going to generate just under $3 billion of EBITDA. Those are U.S. dollars. Again, just tremendous growth when you look at it.
2015, $700 million growing to almost $3 billion by the end of 2020. The question then becomes, what's next, right? We're not going to stop on our laurels just yet, and we think that there is a whole host of opportunities out there. First and foremost on our mind is to make sure that we are getting these projects built in service and cash flowed with all due efficiency. That has to be our priority number 1. Secondly, though, we think that there's opportunities to reap additional synergies across our pipeline assets. I thought I would take a time out here and just kind of walk you through some things that we've done historically and how they're table setters for future growth going forward. One opportunity that I think is somewhat unique is our Buckeye XPress project.
Buckeye XPress is a project that is leveraging synergies we have with our modernization program, such that under the modernization program, we have to do certain reliability and integrity work that all things equal would require us to pick up and replace a 20-inch piece of pipe with a like size of 20-inch piece of pipe. It doesn't make sense for us to do that. What we're going to do as part of the project is we're going to replace that 20-inch piece of pipe with a 36-inch piece of pipe. That's going to match up with the 36-inch piece of pipe on Leach XPress, and it's going to debottleneck our system and create a 36-inch high-pressure header all the way back effectively to Southwest Pennsylvania.
This gives us a first-mover advantage such that as that Marcellus and Utica production begins to grow from 25 to 30 to 35 to 40 Bcf, we're going to have the capacity in the ground ready to go with no regulatory risk at that point in time. Those are the kind of things that we think are going to uniquely differentiate us from our competitors. Secondly, you look at opportunities that we've had with our Portland Natural Gas Transmission System in the Northeast. We're able to leverage our relationships that we've had with several Northeast LDCs to not only get a project on the PN GTS system, but since the receipt point ultimately was back to Dawn, we're also able to leverage an expansion on the Mainline as well. Those are the type of activities that we need to continue to pursue going further.
We were able to win the PN GTS expansion when others couldn't, largely because ours was a compression-only expansion, right? We weren't putting pipe in the ground. We weren't doing additional looping. We were just adding additional compression. There's opportunities, relatively small opportunities, but opportunities to do more of the like going forward. We also think that there's more organic growth opportunities, whether it's in the form of an LTFP2-type deal that Karl has mentioned or possibly an expansion of the GTN system. Due to the debottlenecking that's been done on the Foothills and the NGTL system, our GTN system is sold out effective 2020.
Despite the fact that there's a lot of growth with respect to renewables, particularly in places like California, there are studies that think that there's going to be additional need for gas demand in the state of California, particularly for backup generation loads when solar and wind is down, right? We foresee the potential for an additional expansion of the GTN system, maybe as far south as all the way down to Malin. Longer-term opportunities will continue to present themselves as the Appalachian Basin continues to grow. I mentioned to you the Buckeye XPress project. What's unique about that is not only will we get additional capacity by upsizing the pipe from a 20-inch piece of pipe to a 36-inch piece of pipe, we then have the opportunity to drop additional compression on top of that and create even more capacity over time.
Again, a very efficient, very environmentally friendly way of expanding capacity there. We do see the need for over time, the need for additional export capacity out of the region, whether that becomes additional loop or taking care of pipeline efficiencies on the Southeast Mainline of the ANR system, doing something on the Columbia Gulf or the like. We think that our assets are uniquely positioned to handle that growth as well. We'll also continue to thoughtfully pursue opportunities outside the region, but making sure that we stay within our risk preferences. Risk preferences that generally prefer long-term take or pay type contracts with quality counterparts going forward. Again, a lot going on with respect to the opportunity set in the U.S. Tremendous growth opportunities, particularly on the supply push side.
Our goal is to make sure that we are taking advantage of our assets and connecting the fastest-growing supply basins we have to some of the strongest demand centers across the U.S. With that, I will pause and entertain any questions that you all may have.
Thanks. Stan, if you could just raise your hands and we'll get a mic to you.
Thanks. It's Ted Durbin with Goldman Sachs. Stan, we've historically thought of the returns on your U.S. growth projects as sort of a five to seven times EBITDA build multiple, even one with Columbia. Are you still holding onto those returns overall for the portfolio? How do you think about the risk of this delay with Mountaineer in Gulf, and pushing your contractors to meet your in-service date, versus potentially maybe hurting the returns on the project if costs go higher to hit the in-service date?
Yeah. Let me back up and just give you some perspective. We did see some cost increases on Mountaineer to the tune of CAD 600 million in and of itself. You could think of that as unprecedented demand for resources and equipment in the region. There are somewhere around 100 pipeline spreads that are going to be undertaken during 2018. There are projects like Rover and Nexus that all things equal, were planned to have been completed in 2017 that are going to leak over into 2018, again, creating this additional demand. That additional demand has somewhat diluted the workforce to the point of which productivity has been a little bit lacking from our historical standards. That was the main driver with respect to the cost increases predominantly on the Mountaineer XPress project.
Good news is we do have cost-sharing agreements with our customers where we share in that cost increase on a 50/50 basis up to a predefined cap. Yes, to answer your question, when you look at our entire portfolio of projects, the CAD 8.5 billion, we're still within the guidance that we've given previously that we're going to build these projects within 5 to 7 times EBITDA. Albeit we're closer to 7 post the cost overruns than we obviously were prior. With respect to the second part of your question and the confidence factor around Mountaineer XPress and pushing the contractors, we have incorporated lessons learned from Leach XPress, and the terrain is very similar on Mountaineer XPress. We'll be doing some things to reorganize our spreads. We'll be doing some things earlier to make sure that we're building this as efficiently as possible.
The key trigger is going to be getting that FERC certificate. If that FERC certificate leaks past the end of January into February, it's going to put a whole lot of pressure on that in-service date. Again, as things sit right now, if our timelines hold, we believe that we'll get the project in service towards the end of 2018. Too early to say worst case, but again, maybe there's a 30-day delay or 60-day delay, not unlike Leach XPress, but again, if we get that order now, we believe that we have a really good chance of getting it serviced on time.
Go ahead, Andrew.
Andrew Kuske, Credit Suisse. Stan, it's been a year and a half, roughly, since the close of the deal. If you could maybe give us some perspective of how you looked at projects under the Columbia umbrella, and now how you look at projects and growth opportunities under the TransCanada platform.
Sure. In a lot of respects, it's been similar in terms of the risk preferences are the same. Take or pay type contracts, long-term contracts. I think we're getting our arms around some of the producer credit risk that we have here. The real blessing has been having access to an A-rated balance sheet and a whole lot of cash. Right. Which was something that Columbia was challenged with from time to time. Our projects, our hurdle rates, our desire to build hasn't changed. We think that there is just a tremendously opportunistic subset out there, and we can continue to compete for and win our share of new projects and build these projects within this 5 to 7 times EBITDA range. The challenge has become navigating through the FERC process.
When I started in this business a couple of decades ago, it took 3 to 5 months to get through FERC. Today, it's taking 14, 16, 18 months to get through the FERC process. What we're hearing when we talk to the FERC staffers and the commissioners is they're telling us, "Don't be surprised if it's going to take a little longer." Because they know that there's a higher degree of likelihood that the orders are going to be challenged on rehearing, and they want to make sure that they could withstand that rehearing scrutiny. Again, I think it's more about just working the process. When you look at our projects, again, CAD 8.5 billion worth of projects, but only about 160 miles of greenfield builds. Most of our projects are in-quarter expansions.
They're in-quarter expansions in places like Ohio and West Virginia and Pennsylvania, not in New York and New Jersey. I don't think that there's been a significant sea change with respect to how we look at projects. I just think that we have a little bit bigger pocketbook to tell you the truth, which is great from my perspective.
Go ahead, Ben.
Hi, it's Ben Pham, BMO Capital Markets. Just wondering on organic growth, GTN expansions, Columbia, et cetera, what do you think it needs to take for you to see expansions of that? Is that more NGTL infrastructure capacity expanding, more mainline volumes, latent capacity increasing? What's the main triggering point for that?
There's a couple questions there. With respect to things like GTN and Great Lakes and a second LTFP type deal, I think you've answered the question with your question, which is continue debottlenecking upstream. Karl knows better than I, the WCSB is a basin that's constrained only by takeaway capacity. The more takeaway capacity we can create I think there's an opportunity to increase the flows out of the WCSB. With respect to the Appalachian, maybe a little bit of a different story. What we hear mostly from producers is, today they're living within their cash flow means with respect to producing. There's a thought process that says that there may be a slight overbuild of capacity for the short term.
When you look at the production growth growing from 25 Bcf to 40 Bcf, think of projects like our Mountaineer XPress project, Mountain Valley, ACP, and maybe Rover as subsuming or taking up the first five Bcf or six Bcf of that growth. There's likely to be a little bit of a quiet period, if you will, during 2018, 2019, once you get into 2020, 2021, 2022, the producers will tell you they're short capacity again. As LNG exports continue to take off, we think that that will send a price signal where prices rise, again, giving producers the economic means that they need to continue to drill. That's when I think you'll start seeing the additional takeaway projects both within the region and without an export from the region.
Sorry. Linda?
Thank you. I always like looking at maps and thinking about the long term. I do see some blanks. You're not showing your Mexican pipes there, and I realize you want to focus on your existing corridors because it's easier to build. Long term, how do you think about extending your reach into some of those blank spaces? What sort of competitive advantages, if any, might you have? Maybe you don't want to go into those regions if the reserves don't have the profile that you're looking for in terms of longevity. Can you comment on how you're thinking long term?
Yeah. You notice that void known as Texas, right? We don't have a lot of infrastructure in Texas today, but that is something that all things equal we'd like to change. Think about it from this perspective, and we'll start with the obvious. Permian. Permian is likely to double in size from six Bcf a day to 10 to 12 Bcf a day going forward over the next five to seven years. There seems to be room for at least two pipeline expansions out of the Permian, perhaps going east over to either Dulce or Katy. The first in the 2019-2020 timeframe, we think that there is probably one competitor pipeline that has a pretty good line on that, all things equal.
We think the second pipeline expansion out of the Permian is up for grabs, and there's probably four or five announced projects right now. Looking at that, we're quietly doing the same. I look at the Permian as an opportunity for us to perhaps link up with some of our Texas assets at the end of the day. It's a bit of a challenge in that there are high barriers to entry. What I mean by that is there are a lot of incumbents, intrastate pipelines, that can offer comprehensive solutions along the lines of NGL takeaway or processing opportunities. What that means to me at the end of the day is if we're going to compete, we may not compete lone wolf or by ourselves. We may need to look at a strategic partner, and a lot of those discussions are going on right now.
We'll see where they go.
Okay. Thank you. Just, if I may, as a follow-up. Your presentation is silent on your midstream gathering business, and I am assuming that's for a reason. Can you comment on now that you've been part of the TransCanada company, what are the merits of keeping it, growing it, selling it? Any thoughts?
I wouldn't read too much into it not being on the slide in terms of silence meaning anything, to be honest with you. It's more a time constraint and a materiality constraint. Our midstream business this year will kick off about CAD 85 million to CAD 90 million in EBITDA. Next year, it will grow to about CAD 110 million in EBITDA with the Gibraltar project. We'll continue to compete for and win our fair share of the projects. Again, the key is we're going to do it within our risk preferences. We're not going to take unnecessary volumetric risk. We're not going to take acreage dedications. We're going to look for long-term take-or-pay type contracts supported either by demand charges or MVCs with quality counterparts. That's true whether it's a gathering or a transmission type midstream project or a processing type project.
Go ahead, Jeremy. Then one more, and then we'll stop for a break here.
Jeremy Tonet at J.P. Morgan. I was just wondering if you could touch on the outlook for Bison a bit more, given the changing flows of gas since that was originally put into service.
Bison's a pipeline that is somewhat unique. It's 100% owned by the LP right now. There is not any significant flow on the system, but there are demand charges being paid through 2021. We'll look at opportunities to repurpose Bison to the extent that continuing it in gas flow doesn't make sense. Perhaps repurposing it with respect to a liquids line and getting additional capacity into some of the Salt Lake City refineries. More to come on that, but again, the good news is that we still have several years before we have to come to a final solution with respect to Bison.
Okay, one last quick question. Go ahead.
Yeah, thanks. I appreciate some of the color on the sort of, I guess, the revenue synergies of Buckeye XPress and Portland Xpress. Is there any way to quantify sort of what the potential revenue synergies are now that you've sort of had the business in place for the last 18 months? What could we see?
Yeah.
Over the long run? That's something that you guys talked about a bit. We did the transaction, but it hasn't really come up a lot since then.
Faisel, I don't have a specific number that I can give you, but I will tell you this with respect to some color commentary. There's not a lot of physical overlap between ANR and Columbia, right? The opportunity that most comes to my mind is the Crossroads Pipeline system. I do think that there's an opportunity there to use Crossroads Pipeline as a bridge to aggregate Marcellus and Utica volumes on the Columbia system, then perhaps move them over to ANR's Southeast Mainline, and that the Crossroads Pipeline system effectively acts as a loop of the tie line. Other than that, there are several points where the ANR and the Columbia Gulf systems cross each other, particularly in the supply area, where we don't have interconnects. To me, it makes sense to spend CAD 5 million, CAD 10 million or so to put interconnects in there to promote additional gas flows.
I don't know that there's going to be a significant chunk of synergies from the transaction itself. However, where there are opportunities is what I've laid out earlier, is working with the Canadian system in Karl Johannson and trying to make sure that we're maximizing expansions on the GTN or the Great Lakes system. Keep in mind, these are systems where five or six years ago, we were mothballing compression and turning off compression because we didn't have enough flow to run them. The synergies that I see are going to be more like a Buckeye XPress, where we're leveraging our existing footprint and projects or working with the Canadian system to maximize flows between the U.S. and the Canadian assets.
Great. Thanks, Stan Chapman. We'll, at this point, take a mid-morning break. We're only a couple of minutes over, which is the good news. We've got until 10:15 A.M. I'd ask for everybody to return at that point, we'll start back up again with Dean Patry and our Liquids Pipelines business.
Thanks, David. Good morning. Once again, Paul Miller sends his regrets for not being able to join us today, but I'm pleased for the opportunity to fill in on his behalf to talk about our Liquids Pipelines business unit. When we set out a little less than a decade ago to establish our Liquids Pipeline business unit, we did so by applying a set of core principles. Those principles very much remain in place today in terms of the way that we make our important near-term decisions and the way that we think about our long-term strategy. At 30,000 feet, the story is really quite simple, it's fundamentally centered on market fundamentals.
Our strategy at the highest level is all about connecting major sources of supply that have solid fundamentals behind them to key markets that also we find compelling from a market fundamentals point of view over the long term. When you look at the platform that we've assembled in this short time, that literally extends from the northern reaches of the WCSB all the way down into key refining markets in the U.S. Midwest, then on down to the U.S. Gulf Coast. We really do have a platform that has continued to generate a steady stream of opportunities, we fully anticipate that that will continue for the foreseeable future. Those opportunities relate to expanding, increasing connectivity, attaching to new supply as a fundamental shift, and strengthening our access to market.
We built the business on a commercial philosophy that is very tightly aligned to the overall TransCanada preferences relating to risk and return. That's fundamentally that major infrastructure, particularly of this kind of scale that we're talking about, is prudently committed to and developed with ample, solid, long-term commercial underpinning. Of course, we're always looking at new opportunities to venture further down the value chain or to expand from a geographic footprint point of view. We've got a fairly significant team that's constantly engaged in searching out those next opportunities, nothing strays from our primary priority of ensuring that any growth that we do pursue fits again tightly with TransCanada's overall profile for risk and return. Our Keystone system moves approximately 20% of Western Canadian exports. We provide access to approximately 6 million barrels of key refining end-use market.
When you look at our capacity in the ground today, it is very, very highly contracted. In Alberta, we gather crude from major and emerging supply sources. We've established a toehold in diluent infrastructure in the Edmonton Heartland Corridor. When you look at our existing asset footprint in Alberta, we believe we are very, very strongly positioned to lever those assets to continue to capture growing crude oil supply in the Athabasca region. Turning our attention to the Lower 48, when you look at our Gulf Coast line, sometimes we refer to that as the Marketlink line between Cushing and the U.S. Gulf. It's a very, very valuable asset with great optionality, both in terms of being an important part of the potential Keystone XL service offering, also in terms of meeting customer needs in the region.
Again, while doing all this and establishing the business that we have today on the way through 2017, when you look at our EBITDA, we're more than 90% contracted. In 2017, we did accomplish a couple of important project-related priorities. In late August, we put into service our CAD 900 million Grand Rapids Pipeline in Northern Alberta. In November, we also achieved commercial in service on our Northern Courier project, which is a hot bitumen and diluent system that is exclusively serving the Fort Hills oil sands mining joint venture operated by Suncor. Want to spend a little bit of time diving deeper into the way we think about market fundamentals, both from a global and a North American context, just to set the stage a little bit. I'll get into each of these in a little bit more depth, but the real key points at a headline level.
The concept of peak oil demand is, of course, one that has been bandied about the marketplace for several decades now on and off. We're not espousing a particular view on peak oil demand, but we've looked at our business through the lens of a scenario that actually does see global demand peaking off in the late 2030s, and we'll show that picture here in a little more detail in a minute. It's interesting to note that in that timeframe, in this scenario of global crude oil demand plateauing in that timeframe, along the way, heavy oil demand actually increases by a rather notable amount. A huge driver in this is the fact that the U.S. Gulf Coast refining complex, and in particular of interest to us and our Western Canadian base producers is among the most advanced and highly competitive and complex refining centers on the planet.
As I'll show you in a few minutes, it represents the next great opportunity for Western Canadian heavy oil producers. The other very compelling fact, notwithstanding a view and a scenario of plateauing global oil demand, is that the world needs to find between now and the late 2030s, something in the range of 36 million barrels a day of new supply that doesn't exist today. Needs to find it and needs to bring it online to deal with the treadmill of declines and then some modest growth. Of course, oil sands, in our view, and in the view of many others, continues to play an important part of that supply picture. We're going to show a few pictures here on fundamentals. The graphics that we're showing you here are a base case prepared by IHS Markit.
Over the last few months, we've spent a little bit of time with IHS. Of course, like most others, we have IHS and the other major economic forecasting firms at our disposal to occasionally check our assumptions and our thought processes on fundamentals. In this case, we'll be showing you some of the conclusions of IHS and their base case, which we subscribe to. I should note that the base view of IHS roughly aligns with those of those other major forecasting houses. Let's start first with a view of global demand, which I've got on the screen right now. It's an interesting dichotomy when you examine OECD nations versus non-OECD.
In the case of OECD, as is well understood, with lower rates of population growth and further maturity primarily around vehicle efficiency standards, we anticipate that demand growth will continue to be rather flat and to, in fact, modestly decline over the next 20 years or so. When you flip your view to non-OECD nations, it is a very different dynamic. You've got stronger rates of population growth and a bigger trend of modernization, and there's no getting around the significant and rather insatiable demand for crude oil globally when you look at the full picture. A couple of other interesting thoughts that we believe are relevant. You can't go too far in a day without reading something about emerging technologies, in particular, the penetration of electric vehicles. A few interesting thoughts that we factor in and think about that market dynamic.
Notwithstanding that focus, in 2017, year-over-year demand growth is at an all-time record high. The IEA midyear, a couple of months ago, updated their year-over-year forecast to something like 1.6 or 1.7 million barrels per day year-over-year growth. The other thing to remember is that when you look at a typical barrel of crude oil, only 30% or 40% of that barrel actually goes to producing fuels for light-duty vehicles. Of course, to make the global economy and our lifestyles work, we're still flying airplanes, we need to sail ships, and we move an awful lot of goods and merchandise over great distances on trains. Not to mention the elements of a barrel of crude oil that go into absolutely critical materials that we use in our everyday life, such as plastics.
Nonetheless, again, the IHS base case that we've looked at our business through does see total global demand plateauing toward the latter part of this forecast period. Let's zero in for a moment, moving from the total global picture, and talk a little bit about heavy[crude oil] over that same timeframe. It is interesting to note, and we've highlighted it here on this graphic with a dotted red oval, that if you look over the last couple of years of recent history and IHS's view that, in fact, over this period of gradually slowing demand, heavy crude oil, and in particular heavy sour crude oil, is anticipated to grow quite significantly. Total heavy crudes globally are anticipated to increase from around 9.5 million barrels a day today up to a level of around 12 million barrels a day by the end of this forecast period.
Why is that? This is all about the investment decisions of refiners from a global perspective. They make their capital investment decisions based purely on their long-term outlook for crude oil supply, availability, cost. They make their decisions as a function of that view. The IHS view, looking at it through that lens, is that the major additions to global refining capacity, which will primarily emerge in Asia, are going to be complex refineries that are equipped to handle the heavier barrel. Again, we've seen this trend recently, and we anticipate it to continue. The other very interesting number that falls from the base IHS view, again, flipping our view back to the global total supply outlook is that, again, declines from today's supply sources are quite significant.
When you factor in a slowing but modest growth and declines, again, the world, the upstream sector, and the infrastructure sector serving it are going to be involved in finding, over the next couple of decades, around 36 million barrels a day of supply that doesn't exist today. One interesting feature, of course, of oil sands supply as part of that picture is that once they're online, they require very low, modest levels of sustaining capital to sustain their production levels, which is a key advantage that helps offset, of course, the much higher capital intensity of oil sands production to begin with. Let's zoom back and talk heavy and the U.S. Gulf Coast and what we believe is a very significant near-term opportunity for Western Canadian crude to continue to make inroads into the U.S. Gulf Coast marketplace. It's interesting to note that the U.S.
Gulf Coast heavy refining market is fed entirely by a combination of Canadian supply and waterborne imports. Those waterborne imports have traditionally been from Latin America, primarily Mexico and Venezuela. Those two producing countries have, of course, experienced considerable decline in recent years, as well-publicized. IHS and TransCanada believe that will continue to be the case. As the graph on the right-hand side of the slides illustrates, over the last, call it five to seven years, Canadian supply has started to make material inroads into this critical market. We think it's really the next huge wave of opportunity for Canadian heavy producers to continue to put a dent in that market share.
Again, just to round out the picture from a global heavy crude oil marketplace, we see Canadian supply growing quite considerably, both as part of the overall growth in the heavy supply picture that I talked about a moment ago, and then again, partly at the expense of some dwindling supply sources in Latin America. Of course, Canadian heavy supply growth is quite dominated by oil sands growth. Just to put a couple of numbers to the story, both the IHS and the CAPP views are illustrated here on this slide. Today, we have oil sands production somewhere in the range of 2.7 million barrels a day. Again, over the forecast horizon, depending if you subscribe to the IHS view or the CAPP view, we're going to get up to a level approaching 3.5 million-4 million barrels a day.
Keystone XL is obviously directly driven by the market fundamental dynamics that I just described. The project provides a direct and contiguous pathway for both WCSB producers looking to, again, continue to make inroads into the U.S. Gulf Coast and also for market that continues to look back to Canada to diversify its supply portfolio. KXL is a highly cost-competitive alternative for this particular pathway in this timeframe. TransCanada and our shippers continue to view the U.S. Gulf Coast as the largest and most attractive market for growing Canadian heavy crude oil. We also remain resolute in our view that KXL is the safest and the most efficient and the most environmentally sound way to move growing U.S. Canadian crude oil supplies down to the U.S. Gulf Coast. I'll come back to commercial in a moment. We continue to make important progress on permitting Keystone XL.
As Russ alluded to in his opening remarks, we were pleased to receive the U.S. presidential permit in March of this year. As you know, on November 20th, the Nebraska PSC rendered a decision on our application. The PSC did not approve our preferred route as filed, but it did approve an alternative route. As Russ mentioned, we continue to analyze that decision. Last Friday, on November 24th, we filed a procedural motion with the Nebraska PSC. The motion is effectively asking the PSC to allow TransCanada to address some questions that were raised by the November 20th PSC decision. To be very clear, the motion is not an attempt by TransCanada to have Nebraska PSC alter its approval of the alternate route. In parallel, as we work through these issues, we're not standing still. We've begun engagement with landowners and other stakeholders impacted by the alternate route.
The alternate route would involve a number of new landowners for us, as always, we're striving to understand their perspectives on the project. We will continue to strive to reach agreement with them on mutually beneficial terms. As Russ described a little bit earlier, we continue to work through the interest that we received at the end of October in the open season. Again, the interest expressed by the marketplace was indeed broad and was very encouraging. Again, discussions with the shipper community over the past few weeks have also been quite encouraging in terms of the progress that we're making. Given the strong fundamentals that I just walked everybody through, as Russ mentioned, we continue to expect to conclude sufficient definitive binding agreements with shippers that would support advancing the project. Of course, KXL does remain subject to final investment decision.
We expect to commence construction in 2018, I expect that actual construction would take approximately two years. In the event we advance Keystone XL, there are a basket of other opportunities that we've had out in the marketplace for quite some time. These opportunities are in various stages of maturity. A KXL proceeding would definitely bring them back to the fore for us, and this is driven entirely by what KXL would do in terms of new needs for our shippers in the marketplace. Just very quickly at a high level, Grand Rapids, we have a second line and expansion fully permitted for 36-inch. Again, to basically expand our capacity in the corridor between the Western Oil Sands and the Edmonton Heartland hub.
Recognizing that when you look at today's supply gathering dynamic within Alberta, about two-thirds of the oil produced in the region gathers in Edmonton and about a third gathers at Hardisty. To the extent KXL comes into the picture, there's going to be a pretty considerable market need to shift more of that Edmonton-delivered supply over to Hardisty, and our Heartland Pipeline Project was conceived, and in fact, fully permitted with that market need squarely in mind. In addition, KXL would open up a myriad of other options. Shippers would be looking for various options for downstream market access that have various needs for terminalling services and storage and the like that go hand in glove with long-haul transportation of crude oil. Again, we're in various stages of discussion with the shipper community about these projects.
A key advantage that we have, provided that ample commercial support does materialize for these KXL-driven opportunities, is again, in the case of the Alberta projects, they're permitted and ready to go. Shifting gears for a moment. One other quick update on a project that we've sanctioned and have slated for completion next year is our White Spruce Pipeline. This is a very important extension, effectively, of our Northern Alberta system. White Spruce connects with Canadian Natural Resources Horizon Oil Sands mine. For TransCanada, it provides nice supply diversity and growth, obviously, and provides CNR with another good alternative for market access. We're in the very late stages of permitting on this project. We anticipate it to be in service in 2018. Want to spend a moment on our Marketlink asset.
Again, this is our sizeable pipe from the Cushing, Oklahoma storage and pipeline hub down to the U.S. Gulf Coast. Apart from being a considerable part of the KXL value proposition, this asset is incredibly well-positioned. In recent weeks, as we've seen some interesting shifts in global pricing and supply-demand fundamentals, Marketlink has played an important role in this very critical and active corridor. Marketlink is a key lever for us, both in terms of connecting, again, that Western Canadian crude down to the U.S. Gulf, but also participating in myriad commercial pathway opportunities that include Cushing. When you think about how everything comes together at Cushing in terms of pipelines and storage, there's an awful lot of commercial activity from various supply sources and off to various markets where Cushing is part of that pathway.
Owning a critical asset like this in the middle of that pathway provides us tremendous flexibility. Marketlink to us is a great example of a broader theme in the way that we think about our business. We view our assets both in terms of the integrated whole, but we also very carefully manage the balance between preserving flexibility to optimize value by taking advantage of regional opportunities as the marketplace shifts. Just to put a wrap on our piece of the story. Looking out to 2020, the Liquids Pipelines business unit we anticipate will be at an EBITDA level of about CAD 1.5 billion. This includes, again, our recently completed Grand Rapids and Northern Courier and our sanctioned White Spruce Pipeline being into service over this timeframe. In a nutshell, for the Liquids Pipelines business unit, our focus remains on discipline.
Discipline on what growth we pursue, discipline in the way that we make decisions to commit the company's capital. As you've heard from other speakers today, we're blessed with myriad investment opportunities across the board from our different franchises, and we're just part of the mix and trying to compete, and we know what we need to do to deliver opportunities that fit that profile. Our goal, quite simply, over the next five or 10 years, is to extend on the great success that we've achieved in this part of the energy infrastructure space in the last seven years or so. With that, I turn over to questions.
Thanks, Dean. Again, we've got a few minutes for questions, if you do have a question, just raise your hand, and Stuart or Rondo will get a mic to you.
Thanks. Faisel Khan with Citigroup. The recent news on the potential to reverse Capline, can you just talk about how that impacts the need for KXL? Does it mean that you can expand more capacity from Steele City to Patoka? Does it really compete with you head-on over the long run? Thanks.
Yeah. Capline, from our perspective, is a relatively early-stage initial concept for that corridor. One of the considerations that you got to think about in terms of Capline is how do you feed it, given constraints on moving crude oil down into the line. When we think about our portfolio of opportunities, really doesn't impact our thinking and what we're focused on too much to the extent KXL advances, again, contiguous path from A to B that we can control entirely and offer what we think is a very compelling offering to the marketplace. In which case, the base Keystone system, we'll be looking at the best and highest value use of that capacity into Wood River and Patoka.
Linda?
I realize you're still assessing Keystone XL's Nebraska decision, but maybe you can just help us think of your evolving thoughts about the earliest you'd be able to get to an FID, and maybe the bookends of what the latest timing might be.
I think rather than getting prescriptive around timing, we'll maybe just emphasize that FID for us is obviously going to be a very careful and thoughtful consideration of all the complexities and risks around the project, including relating to permitting. Also setting that against, again, what we clearly see and have articulated in terms of the significant financial and strategic impact of the project. I would stress that, as you might imagine, both commercially and from a permitting point of view, our goal is to work our way through those two critical elements as quickly as we can.
Sorry.
Just as a follow-up, my recollection in the last go around, there was a critical construction window you had to hit by early summer. Is that still the case? Would you need to hit FID by a certain time to do that, or would there be mitigants and workarounds? Am I getting too specific?
I don't know, Russ, if you have anything to add on that.
I'd say, again, to Dean's point is we need to work our way through-
The regulatory legal commercial issues first get to an FID. We can plan our construction schedule around that. There is certain parts along the route that aren't available to us to construct in the spring with migratory birds and things like that. Given that the length of the project, we'll do our planning as to which spreads we start first and which ones we do later based on the start date. The plan is to build it over two seasons, and we'll align that best to how we can optimize the schedule when we get there based on when we get there. At the current time, our thinking is still approximately two years to construct this, plus or minus a bit based on that time of year that we actually get underway.
Hi. Robert Hope, Scotiabank. Just realizing that you're still in commercial discussions, but they seem to be relatively far along. How do you look at the potential EBITDA from the project versus the, I believe, 2014 Investor Day, where you were saying it was going to be about a US $1 billion project? Secondly, how do you think about incremental capital at the door for the project as well?
I'm sorry, the last part of your question?
The incremental cost of the project.
Okay. Well, clearly, I think we've provided some discussion around range of return expectation and CapEx around the project. Our perspective remains roughly in the range for both of those elements, which you can do your own math on the potential for EBITDA benefit. It is stating the obvious, quite significant. The financial prize is quite clear. For us, we're going to be very diligent and thoughtful around all elements around the FID decision, not just financial and strategic, but looking through the lens of permitting to ensure that when we do embark, if we do embark, that we're doing it within a range of tolerance on risk that we have a high degree of confidence in.
In terms of the cost, the CAD 8 billion, is that still in the ballpark? How do you think about the incremental capital you spent so far?
Yeah. That is still in the ballpark. Of course, as we've talked about in the future, the silver lining is that we do have a considerable portion of long lead pipe, with the exception of around 20%, I believe, in hand. A good chunk of that CAD 8 billion estimate is characterized by relatively low risk because we've got a good chunk of it behind us.
That's great. If that's all the questions for Dean, thanks very much, Dean. With that, we'll turn the podium back over to Karl Johannson . Carl's going to provide you with an overview of our energy business. Again, Don will be up to conclude things with the financial outlook.
Thanks, David. Let me start by talking a little bit about what the changes we've made in this business over the last year and a half, and just talk a little bit about our commitment to this business. I know we've made some pretty material changes, but I wanted to emphasize first that TransCanada's in this business for the long haul still. We consider this business to be key and strategic to rest of our businesses. For example, we acknowledge that our gas is used quite extensively in gas-fired generation. We understand that environmental policies that may impact our other businesses, including the oil pipelines and the gas pipelines, generally manifest themselves through experiments with regulation on the electricity side. So we do consider this to be a very important business for us to stay in.
We have cycled some assets to both pay for our acquisition of Columbia and just to cycle them out on a normal course as they became more valuable. But I would say that it's important to make note that we're in it for the long term. I'd also point out that not only have we cycled some assets, but we've actually made some pretty big commitments to this business over the last year and a half as well, two years. The Bruce Nuclear refurbishment, really, it's a 40-year deal. It goes out to 2060. And we're on the verge of commissioning our largest gas-fired power plant, the Napanee, that we've ever built. So we both cycled assets out of this business, and we have both put new assets in. Last year, we did change the business. We did exit our merchant positions almost.
We haven't got rid of 100% of it. We still have some cogens in Alberta, which got a piece of merchant, but the main merchant pieces of this business have been sold. That's the U.S. Northeast business, and the coal PPAs out of Alberta have been turned back to the government. So we have put this business in a better risk profile that we consider. It's very, very highly contracted now, and most of our new money is going into areas like the Bruce Nuclear that is fully contracted. But what remains in this business is still significant. It's a 6,100-megawatt business, still one of the largest non-government-owned power businesses in Canada. So still a significant business. Even though we have recycled lots of capital out of it, we still remain a very large player in the Canadian scene for energy.
Our 2017 accomplishments, well, our earnings in the business remain strong even with the divestitures. We'll be quickly back to about CAD 1 billion of EBITDA in this business. We've had significant work investing in Napanee. Napanee, we're still planning on bringing that online next year, and we look forward to commissioning it. The sales of the U.S. Northeast and the solar projects have been completed. Now, we haven't closed the solar yet, but we have completed the sale of it, and we look forward to closing it hopefully before the end of this year. Significant progress has been made in the first Bruce Power refurbishment. I'll talk about it a little bit later, but it is the first refurbishment is unit 6 in Bruce Power, and it's pretty much all hands on deck getting that ready for its first major component replacement.
The Ontario solar sale allowed us to surface good value for our shareholders. If you think of it, this particular business represented about 1.5% of our megawatts in our business, and we got CAD 540 million for it. It was significant capital rotation in this portfolio. That doesn't mean that we are leaving the renewable business at all. Some businesses that when you take a look at it and the sale proceed you can get from it actually are better than your hold value. It just makes good disciplined effort to cycle it. When we did sell it, the initial thought was that we'd cycle it because just of the economics. It did fit in well with our capital plan right now. Really, we sold that just because it was worth more than our hold value.
I'd say we do that in pretty much all of our businesses. I can speak personally from my experience in gas. We have an LP in the gas business, which we tend to use for doing our sales of our assets. It's a little different. We still hold some control, but we do nonetheless cycle assets out of the gas pipeline business as well. Where's the power business going? This is an interesting graph. I could do this for both-- something like this for both transmission, local distribution companies, generation utilities, generation capacity. It's an interesting market right now in that the power market isn't really growing all that fast. The actual consumption of megawatt hours is not growing all that fast. It's kind of dislocated from GDP, so to speak.
Yet the business is still requiring lots of capital into it, that's really because of the capital stock that's turning over. It's turning over in generation right now because we're moving off coal. Both, I talked about this earlier in the gas side, it's moving off of coal because gas is actually more economic in some cases, and it's moving off of coal because it's getting regulated out of the coal business. What's coming in behind that is both gas, wind, and solar. Renewables and gas are still are playing in that space. We see this going on for quite a while. In the generation capacity, it's still a good play. There's still lots of contracts out there for renewables. We expect as renewables continue to grow in the market, there'll be more contracts for gas.
The question is, can we access that in our market areas, the market areas that we're working in? Talk a little bit about the Ontario, which is a very important market for us right now. The Ontario Long-Term Energy Plan. I wanted to talk about that for a couple of real key reasons. Number one is it came about in big support of nuclear, which is very important to us given that we have a contract to refurbish nuclear, that contract runs right until the 2060s. We got good support again for this nuclear, I would add that even the opposition parties in Ontario have come out supporting nuclear. We feel really good about our position in the nuclear, we feel really good going in this first refurbishment that there is support there. What else does that document say?
That document also says that gas is still a preferred fuel. It's recognized that the renewables can't run without it, and it recognizes it's going to be needed for the future of the grid. That's important. It also recognized that this market in Ontario here is not as overbuilt as everybody thinks. When you take a look at this graph and you start looking at those white bars, and you start looking at this graph, just the decline in it. When you get the nuclear refurbishment going, and you get units taken off from nuclear refurbishments, and you start retire Pickering, and you have Darlington and Bruce with nuclear plants down, there's actually a gap in the resources. Which means a couple things.
Number one is there'll be more procurement at some point of resources for this market, and those resources will probably be gas, given that we're taking base load nuclear off, they'll probably need some sort of base load product on there. Secondly, it says that there's life for our contracts that we have existing right now after the contracts end. There's reasons for those plants to stay in useful life after the contracts end. Now, our contracts don't end till the end of this cycle, or those don't end till the end of the cycle. Still, it does say that with refurbishments going on and the growth in the market, that even when we do get to the point where our contracts start ending, there's more market for it. More importantly, there'll be another opportunity in this market to build some capacity.
Getting into our actual assets, the Napanee Generating Station. This is about 65% complete right now. We are on schedule to bring it in. We said that this will be brought in 2018. We're still predicting it'll be in 2018. Hopefully by the time we have this next year, it'll be at least in commissioning or up and running. It is a 20-year PPA. This is the old Oakville Generating Station that was relocated after the government canceled in Oakville. I guess the moral to this story is that, if you hang in there long enough, and you keep working at it, you can actually get these through, because we're what? seven years later, and we're almost finished the plant. Now it's not in Oakville anymore.
The plant did ultimately get built, and we will not only see our investment materialize for ourselves, but the citizens of Ontario will actually get the opportunity to crystallize some megawatt hours for that expense that they spent on it. Again, it's a CAD 1.1 billion project. I would say right now when I look at it's pretty much on budget and certainly on time. We're still planning on bringing it in before the date of the contract, which is December next year. Hopefully we can get it in a little earlier. Talk a little bit about Bruce. The Bruce right now is all about how are we going to get the refurbishment done? What the contract look like? How are we going to go into the first refurbishment, which is unit number 6.
The Bruce Power contract and this new amended restated contract that we signed in 2015 is an important agreement for this plant. What it gave us was it gave us a uniform price for all the units. It gave us a price that is adjusted for inflation. As time goes on, if we can line up our costs and our union agreements and so forth to the inflation factors, we can make sure that there is a guaranteed return that comes out of this plant. It also gives us an opportunity to refurbish the 6 units that we haven't refurbished already. We're going to do them one at a time. I'll show you a schedule here shortly. Really the essence of this contract is when these units go into refurbishment, we don't lose the revenue per se on these units.
The entire price of all the rest of our units, of all the rest of our megawatts flow will increase. The basic theory behind that was that TransCanada was just not up to doing a 6-unit replacement, where every time a unit went down, we didn't get paid for that unit for the 4 years it was down. We had to come up with a mechanism by which we got the revenue during that period of ownership. This is a fairly complicated agreement, but it's a good agreement that way. You will see the revenue fluctuate depending upon general availability of the plant. That's the way that we've set it up. The government wanted us to be incented to make this plant as high a load factor for the units that are operating as we can. We touched on 90% this year.
Probably won't be able to get that next year, but we're seeing distinct improvements. The incentive is working. Every time that we get that above our baselines, we get to share in that money with the IESO. Right now, as we go in the refurbishments, we will see our revenue per megawatt hour produced jump, and that should not materially impact the revenue we see out of this unit. As we get close to 2020, when the unit goes into service, we'll be able to give you a better feel for what exactly that means. Right now, we submit unit 6 to the government about a year from now. We submit unit 6 for the major component replacement to the government.
We believe that the price will be fine, and it'll fall in within the band that we gave them, and we'll get the go ahead, and at that time, we can give you guidance as to what the impact that'll have on our per megawatt hour price. At that time, we'll be in a better position to give you a better feeling for what the availability will look like going forward. I have a video here, and it's from Bruce Power. I thought I would just show it to everybody. I thought the video gave a pretty good explanation of Bruce Power. It's about 3 minutes, so maybe if I could turn it over and if I can get back, there we go. Just to give you an idea of what we're planning on the unit, the major component replacement.
There's really two parts to the refurbishment. One is the asset management program, and that's the non-core nuclear work that we're doing just generally every day. They give us credit for our asset management, and we're working on that for unit 6 right now. We're doing it. These are stuff that we don't need a major outage to do. We could do it during the regular outage, or we can just do it during its operating time. That's the asset management. The major component replaces when we actually take it down, and that's what you're seeing right here. That's when you actually do the core nuclear part of the refurbishment, when you take it down. As you can see, it can last up to four years to rebuild that unit.
The question I get on this quite often is, what makes us think that this is going to be better than units 1 and 2? I imagine there's a lot of people in this room that probably saw me or Russ or Alex talking about units 1 or 2 years ago at these meetings. If you recall, the cost went over. The time was probably a year and a half to two years over as well, and it was a very difficult refurbishment. I can tell you a couple of things that we're expecting to be different. Number 1 is learnings. We didn't go through that and not learn anything, I can assure you. To this day, they still have committees at Bruce that go over the learnings that we learned from the 1 and 2 refurbishment to make sure we don't repeat those errors.
Second thing is that these units are completely different. Units 1 and 2 were shut down, in 1 case, for 25 years. They were shut down. They hadn't operated for years, decades. These units right now, 3 through 6, they're operating as we speak today. They're on regular maintenance schedules. There's nowhere that we're going to open anything up in these units that we're going to be surprised because we've seen it all on them. I think that's the biggest difference right now, that we are familiar with these units. They operate today. Everything that is to know about them, we already know, and that wasn't the case with 1 and 2. 1 and 2 had been down for so long that really every time we opened up something, it was a new experience.
Second thing is that the contract we have in place right now does a couple of things. Number 1, it gives us time. Before we started construction, we were under time pressure, we started construction before engineering and all the stuff that you do when you're under time pressure. Here, with our asset management program and our major component replacement, we got the time beforehand to do it right, make sure all the engineering is done, make sure the price is completely thought out before we submit it. It also gives us time afterwards that as everything we learn in the unit 6, we can apply to our next refurbishment and so forth. We price each one individually to the ISO before we move ahead, so we can adjust as we learn even through this program. Last thing is it gives us information from other refurbishments.
Darlington is actually going on as we speak right now. We have people actually embedded on the Darlington refurbishment with OPG to determine what's going right there and what's going wrong there so that we can use these learnings. I'm quite optimistic that we have found the secret sauce here, that we have a very rational plan and a very good contract to enable it, and I'm looking forward to submitting unit 6 this time next year, and we'll see how that I'm quite certain we're going to get it under the CAD value that the IESO is looking for. I'm pretty certain next year I'll be up here talking to you about what that looks like and how we're moving forward. The Alberta power assets, we're watching closely. We have some very good co-gens there.
As I said, there's a merchant component to them, but we have very long-term contracts for most of them for steam and the local power. We have a long history of being in this market. Since we have turned back our coal units, we haven't really been that material player in the market. We are watching to see what the market does. We're not happy with the risk profile of that market right now. We said even when we had a big position in there, of course, we had some very good years in Alberta. We always advocated for a more contracted market, a capacity market. The government is starting to talk about that now. We're fully engaged in it, and we'll see if they're able to come out with a construct that will fit our risk preferences and go forward.
We have participated through partners in the initial wind auction. We'll see how that goes. For anything more material right now, we want to see where the market goes for it. There is some upside in Alberta with the coal being legislated out. I got a little graph here that shows kind of what's going to happen. There is a need for more resources there. With a properly structured market, with proper contracts, I think we can participate both in the renewable section of that and in just the base load that they're going to need. We'll see how that goes. We're monitoring it closely. If we do not get a market structure there that we're comfortable with our risk preferences, we have lots of scope that we can redeploy our capital elsewhere. It's not a need to be there. It is our home market.
We actually know quite a lot about it, we're hoping that we can work closely with the government to put something in place that'll work with our risk profile. I did it a little differently. Given that we sold so much assets, I kind of put a bar on there just to show kind of what part of our EBITDA growth we sold the asset. You can see how it bounces back, and that's basically Napanee and the Bruce nuclear that's kind of shown that it's bouncing back there. Even with all of our rotations of assets, it's still a pretty good business. We have a pretty good base to work off of. Again, a very large business by Canadian standards for non-government-owned power businesses. Just to finish it off to what's our key focus? Well, we've got to maximize the value of our existing assets.
We've got to get Napanee up and running on time and on budget. We've got to get Bruce through the life extension program. We have good teams working on both of them. We're going to keep pursuing growth through appropriate transactions in areas that are in our core geography. We will be active in Alberta if the construct is right. We'll be active on the renewables, again, we have a big core area here in Ontario, which will be active as well. Having said that, I can open it up for questions.
Any questions for Carl? Robert. Robert first.
Carl, historically, just going a little bit further back, you were taking cash out of the pipelines business that was earning sub 10% returns and deploying that into the contracted power side.
Yeah
kind of with a look and feel of regulated. With your gas outlook improving and that part of the business taking a lot of capital and the sale or the capital recycling around the solar assets, how are you looking at the existing power assets going forward? Is it a platform that you do want to grow significantly if you can find the contracted side? Should we be thinking about it as potential asset sale proceeds to fund the capital plan?
Yeah. It's a good question. You're absolutely right. Early in the century here, I guess, it was a great outlet for surplus cash coming off of that gas pipeline system in particular. We were able to redeploy that cash. They're quite merchanty. We had a different risk profile at that time. Much higher returns. That's just turned around. One of the problems we have in the actual generation or IPP market is just twofold. Number one, on the merchant side right now, the risk/reward just isn't there, and nor does it fit the risk profile that we have built our balance sheet against. We're just not going to go there and do the same type of merchant. Even if it comes back, but it's not there right now either.
On the renewable side, to be honest with you, right now we've been a seller. You saw the solar. People are bidding up so much. They're so valuable right now, these assets. They don't fit our return profiles. In order to get the returns that people are looking for, I think you have to do something else with these assets, either put leverage on them that is far in excess of what we're willing to do with our balance sheet or do some other financial engineering to make it work. You can see with the solar sale, just the value that we brought out of that it's suggesting that today's time is maybe not to be investing, it's maybe to be cycling some capital. I guess I could answer your question by saying, these all are business cycles.
We will see renewables back to the point one day where we will invest in them. They'll fit our balance sheet, and they'll fit our risk profiles. We will see other parts of this business that make sense for us. It may not be merchant generation because of the merchant component of it, but there may be other parts of the value chain that we can participate in the long run in the energy sector that keeps us in this business and keeps us within our risk profiles. You probably won't see us buy Ravenswood again. Ravenswood, like I said. Some people might smile about that since I know it was controversial, but that's just not within our risk preferences anymore, and you won't see that. Anything we do, you'll see look much different than we used to.
Maybe just to continue with that, because you presented around Alberta, and so you've done kind of the month-to-month capacity thing on Ravenswood, although that was a high proportion of revenue, and you've done the three-year forward look, both in New England and PJM.
Do you think Alberta's going somewhere different than a roughly three-year forward look? Is that really a market for longer-term renewables for you?
Good question. I think the renewables are going to be handled differently than the power pool in Alberta. The discussion isn't finished yet, so I'll just caveat by saying, these are just feelings, observations we're making. They're not surprising. The people buying the power would like to see a shorter duration capacity market than the people selling the power. That's not unusual. You see that everywhere. You talked about the New England pool, and you talked about the New York pool, and that's pretty normal. That's not something we're interested in. If they do go down that road, you'll probably see us on the sidelines deploying our money elsewhere. If they do go down the road with longer-term contractual coverage for it, we'll be interested in it.
That's basically the message we're leaving them right now is that if you construct it certain ways, we'll be there. If you construct it differently, we will not. We're being quite clear with them.
Linda?
Thanks, David. I just wanted to follow up, Carl, with a comment you made about going along or being along or interested in other parts of the energy value chain. Clearly, you're commenting on your natural gas transmission.
Can you comment on your appetite and interest in other parts of the electricity value chain, whether it be electric transmission,
electric distribution, and maybe this is a question as well about gas distribution and how you're thinking about that. Will that become increasingly important, maybe as some of the secular change you're seeing in the oil and gas industry dissipates and stabilizes?
No. Certainly, when you take a look at those businesses you mentioned, those all, I think, fit our risk profile. Some of them take us out of our comfort area. We're a gas company right now that has maybe 200 customers, and making a transition to 2 million in an LDC might be a step too far. It would certainly come with lots of thought. I do think that something like that fits well with our risk preferences. Something like that, to be quite frank, is something that we would be interested in, but I will tell you that right now, the valuations of that sector are sky high, and it's not something that we think is something with our capital availability and the other use we have in our capital that would make sense. Stay tuned.
If the valuations ever moderate in those sectors, I do think they fit our risk preferences and they would warrant a look from us. I think we are good at regulated type businesses. Not at these valuations. These valuations, quite frankly, with the capital that we have right now, we have better projects and better deals to pursue.
Great. Maybe we'll take one more question from the back, then we'll turn it over to Don.
You talk about pursuing growth in contracted power infrastructure, right? I'm assuming you're going to do that in the U.S. as well. Can you talk about some of the competitive dynamics when you go for contracted power infrastructure in those markets, please?
Yeah. First of all, we're going to look at opportunities within our footprint.
Okay.
Right now, that means Alberta, Ontario, Arizona. Arizona's had lots of competitions for peaking plants and solar plants and so forth coming out as well lately. Right now, that's what we're looking for. If we were to step out to a different area, and which we might, it would have to be an area that we're still familiar in, so maybe an area where we have pipeline infrastructure but not a lot of electricity infrastructure. I doubt you'll see us in a place where we don't have any infrastructure at all. California always calls. It's such a big place with large. We got no infrastructure there. It just doesn't make sense for us to start figuring out California regulatory and whatnot. I think our priorities will be, first, where our power plants are. Second, where our other infrastructure is.
If there's absolutely nothing there, we have to wonder if this is a business that is right for us right now. If we can't find anything in those two places, we have to wonder if this is a business that is right for us. My suspicion is that we'll be able to keep this CAD 1 billion EBITDA growing modestly through this period of time. As more capital becomes available or as valuations on some of the renewables and/or even some of the other regulated businesses start moderating a bit, we can start adding more material. Right now, we're going to stick pretty close to home.
Great. Thanks, Karl. Again, Karl will be available through lunch if you've got any further questions. With that, we'll turn it over to Don Marchand, our Chief Financial Officer. Don's going to provide you with an overview or a finance update.
Great. Good morning, everybody. It occurred to me that with marijuana being deregulated here next year, the term Canadian pipe sector may have a whole different meaning by next Investor Day. This is my seventh investor day. It seems we oscillate back and forth from what are you going to do with all the money to how are you going to get all the money, and there's elements of both of that this year here. Spend the next 20 minutes or so just reviewing our strategy on the finance side, some of the tangible progress we've been making on our commitments, as well as give you a snapshot of what the next three or four years look like. Here, there'll be a lot of numbers. Try not to sound like an auctioneer going through them too quickly here. A few key assumptions embedded in the presentation here.
Everything's in Canadian dollars unless I mention otherwise. We're using a 130 currency rate and I'll talk a bit about some of our variability associated with currency a little later on here. Using an effective tax rate in the early years and excluding Canadian regulated, which is flow-through and AFUDC in our U.S. and Mexican business. It's about low 120s migrating up to the 124-125 range at the end of the horizon period. Here, depreciation. We generally depreciate our assets over 40 years, 2.5% per annum on gross PP&E. With that, just touching on our financing strategy, it's quite simple and it really hasn't changed over the past 15 or 20 years here. Fundamentally, we invest in long-term annuity streams and regulated franchises, and very driving long life, low variability cash flows.
By long-term contracts, we generally mean 20 or 25 years, not three, five or seven years. Very long life cash flows. We finance that with long-term capital. It is a fairly simple model. You lock in your revenues, you lock in your biggest input cost of money, capture that spread, repeat over a growing asset base. We have about CAD 22 billion of book equity, CAD 4 billion of perpetual prefs. Average term of our debt is 20 years. That includes our hybrids to a final maturity and 13 years with our hybrids to first maturity. We preserve our ability to act at all points of the economic cycle. We never want to compromise our long-term prospects because of short-term events. The A grade credit rating is quite important to that underpinning here. It allows us the ability to act under virtually all conditions.
We saw that actually during the global financial crisis, when we continued to have access to the marketplace. It allows us the lowest cost of capital long term and to issue for size. The A credit rating also differentiates us, particularly in times of stress, but also from a counterparty perspective. As we are dealing with customers that are looking for a pipe provider for the next 30 or 40 years, that is a distinguishing factor for us. We believe in a simple, understandable corporate structure. Generally prefer to own 100% of our assets and operate them. We have one single pipe LP in the marketplace, and we tend to finance in the center. We use TransCanada PipeLines Limited as our main financing vehicle. We do have some asset level debt in our U.S. gas pipes, which is mainly for rate-making purposes and at Bruce because of its unique nature.
Generally, keep it very simple. I will talk a bit about FX rates and interest rates, as I mentioned, a little later on. From a counterparty perspective, I think this is a bit of a hidden strength or an unheralded strength of the company here. We have had really de minimis credit counterparty losses here over the past 10 or 15 years, and that is a testimony to the effort we put into that side of the business. Had a healthy to-do list going into 2017, and this is our report card here. By the end of the year, have brought CAD 5.6 billion of assets into service. The biggest components would be NGTL, our two liquids pipelines in Alberta, as well as probably CAD 1 billion plus in the U.S., including Rayne XPress and Gibraltar. We also added CAD 3 billion of new assets.
The biggest component was NGTL, with an additional CAD 2 billion added to the growth portfolio. Another CAD 1 billion in the likes of Buckeye XPress, Portland Xpress, and on the Canadian Mainline. As Stan mentioned earlier, we declare ourselves successfully integrated with Columbia, including the sexy stuff like SAP integration, which went fairly seamlessly back in April. On track to capture the $250 million per year of targeted synergies. Those are U.S. dollars. We got the U.S. Northeast power assets sold and retired the balance of the Columbia bridge loan in the second quarter of this year. We bought in Columbia Pipeline Partners for $920 million U.S. back in February, gave us full control of the Columbia assets. Again, consistent with keeping our structure simple, have no duplicate of LPs in our portfolio. I will go over the funding that we completed this year. It is about CAD 13 billion.
It was a fairly ambitious year on that front. That'll be on the next slide here. We maintained our A grade credit ratings. We added Fitch to our rating complement here. That gives us one more independent view of our credit. Since the beginning of 2016, on the left-hand side of the balance sheet, we have exited the Alberta PPAs. We've exited the Northeast U.S. Power business, which was merchant. We've added Columbia, giving us an incumbency position in the Appalachian, and we brought about CAD 9 billion of almost all completely contracted regulated assets into service. On the right-hand side of the balance sheet since the beginning of 2016, we've added about CAD 15 billion of subordinated capital to the balance sheet, nine of which was common. About CAD 5 billion is in the form of hybrids and CAD 1.5 billion of preferred.
In terms of left-hand, right-hand side of the balance sheet, we've been walking the talk on the A credit. This is our 2017 funding program. The tagline should probably read, No Banker Left Behind. Moving left to right, it was a fairly heavy lift this year. About CAD 20 billion was required. Capital program will come in around CAD 9.5 billion. We bought in CPPL, as I mentioned, CAD 1.2 billion, paid about CAD 2.5 billion of dividends and distributions to our LP, refinanced CAD 1.7 billion of maturities, and repaid a $4 billion U.S. Columbia bridge loan. In the middle box, we generated about CAD 6.4 billion internally from operations, probably around CAD 5.6 billion, and raised about CAD 800 million under our DRIP program at a 2% discount there. Seeing about 35%, 36% participation on that front right now.
That left about CAD 13.5 billion to raise and, as you can see on the far right-hand bars, in a fairly diverse, in some cases, innovative, fairly attractive set of financings on that front. About CAD 3.5 billion came from senior debt. That included our proportion of Bruce's debt funding, as well as some commercial paper draws and cash on hand. We did, on TransCanada's balance sheet, raise about CAD 2.6 billion of term debt, average term 10 years, average coupon 2.7% pre-tax. We raised CAD 3.5 billion equivalent of hybrids. These are 60-year non-call 10 deeply supported instruments that we achieve 50% equity credit from the credit rating agencies on this product. We raised CAD 1.5 billion in the U.S. markets earlier in the year at a coupon of 5.3%.
We did the inaugural Canadian hybrid as well for about CAD 1.5 billion at a pre-tax coupon of 4.65%. The order book was approaching CAD 4 billion on that specific deal. Moving on, top of the box here, about $3.1 billion U.S. raised in the sale of the U.S. Northeast power assets. The other CAD 2.3 billion in the purple box was made up of a series of transactions, including the pending sale of our solar assets for CAD 540 million. That should close by the end of the year. We received CAD 600 million back from Progress Energy Petronas at the cancellation of the PRGT project. That occurred in October. We did a CAD 765 million drop-down to our LP back in June.
Earlier this year, we did establish an ATM program, which is something that's fairly commonplace in the U.S. midstream space, something we've been running at our LP for several years. I think it's reasonably new to Canada here. We filed for CAD 1 billion, just under 2% of our float. That's good for the next 25 months. We do have cross-border ability to issue under the ATM. This is a tool to manage more surgically our capital structure and credit metrics over this timeframe. It will be influenced by the pace of our CapEx program, business results, and our other funding activities, how they compare with this option. We'll balance this. We are at this time financing CAD 24 billion of growth and effectively de-leveraging at the same time.
It is a balancing act right now, and this is an important tool for us as we do that. On our third quarter call, we indicated we had not yet issued under that. We will issue some ATM here in the fourth quarter, and we'll report the extent of that when we report fourth quarter results in February. We do reiterate that there is no need, in our view, for discrete common equity to complete the CAD 24 billion program underway right now. Moving to the elusive one font in PowerPoint that we continue to work towards. This is a depiction of our capital program right now. It's about CAD 24.5 billion. The biggest components would be U.S. gas at about CAD 11 billion and Canadian gas at CAD 8 billion.
The takeaways from this slide would be it's a fairly diverse set of projects here, by geography, by business line, by customer. It is essentially all regulated, contracted. It is a large number of small to mid-size projects with what we would describe as normal course permitting and construction. It's a fairly compressed timeframe to complete these. The vast majority of these projects are in service and cash flowing by the start of gas year, November 1, 2018. Holistically on time, on budget, we have a few ahead of time, ahead of budget, a few that are lagging. Holistically, we would describe it as on time, on budget. As Russ alluded to earlier, we have a proven ability to replenish that portfolio. We've talked about this over the course of the morning.
We've seen a notable uptick in maintenance capital spend, this slide captures what we see as about CAD 5 billion in maintenance capital over the upcoming three years here. There's two principal trends here, as have been talked about. Number one, the actual dollars being spent on maintenance capital has increased as system utilization has risen. The gas systems have tightened up. We've also seen class changes, and greater integrity spend. The dollars are up. The second major trend is the recoverability of maintenance capital. It's de facto growth capital in that we earn a return on and of this capital as it is invested. It does actually contribute to earnings power. Again, CAD 5 billion is what we expect in maintenance capital, through the 2018, 2019, 2020 timeframe. In Canada, it's about CAD 1.8 billion. This has historically been immediately reflected in rate base under Canadian regulation.
We have about $700 million for ANR in this timeframe. That includes the tail end of the $837 million program that was included in the 2016 rate settlement, as well as additional spend that we believe will be recaptured in upcoming 2019 rate negotiations or rate case. It's about $1.2 billion for Columbia, which we fully expect to recover in a rate case in 2022 onward there. There's a small amount in here for our liquids business, which is fully recovered through tolling arrangements we have with our shipper community on those assets. When you add it all up, our capital spending over the next three years is just under CAD 18 billion, about CAD 17.8 billion in total. CAD 12.5 billion of that is to complete the CAD 24 billion growth program underway, CAD 5 billion for maintenance capital, and about CAD 300 million for capitalized interest over this timeframe.
We do allude to development costs in here on the long-tail projects, but I would describe them as more of a rounding error. The observations here, the program is heavily concentrated in 2018, at CAD 9.2 billion. That is largely consistent with the CAD 9.5 billion that we'll spend this year. Another heavy lift coming up in 2018, but something we view as eminently manageable. The maintenance capital side, probably about 85%, CAD 4.3 billion-ish, is what we would consider recoverable and de facto growth capital. The capitalized interest, of course, excludes Energy East and PRGT, which we've exited. As I mentioned, the development costs are minor in this timeframe. How are we going to pay for all this? This is the funding program through 2020 over the next three years. Again, moving left to right. CapEx, about CAD 17.8 billion.
We expect to pay dividends and distributions to our LP unitholders of probably about CAD 9.75 billion. That's including dividends at the upper end of the 8%-10% growth range here over that timeframe. A total need of about CAD 27.5 billion. In the middle box, we expect funds from operations to be just north of CAD 20 billion. Funds from operations is in excess of CapEx over this timeframe. We do have the dividend reinvestment program running through the end of 2018 at a 35% participation rate here. At present, given, again, the magnitude of the capital program and the need and intent to deleverage, this is, in our view, a necessity for the time being. It is not a permanent feature of our capital raising is to have this thing on forever.
We did have the dividend reinvestment plan off during the 2011-2016 timeframe. We will turn it off at the appropriate time, recognizing its dilutive effect here. On the far right-hand side, we have a capital markets need of about CAD 6.5 billion-CAD 6.75 billion. That's aside from refinancing maturities, which I'll touch on in the next slide. About CAD 2.9 billion, just under CAD 3 billion of that will come from incremental senior debt. That's within the constraints of our A grade credit metrics. About CAD 2 billion from preferred shares or hybrids. We see those two products combined comprising about 15% of capital structure going forward. The hybrids tend to come in lumps, but they should settle around the 15% over time. CAD 1.7 billion will come from a combination of various other elements that we'll look at here. First of which would be LP dropdowns.
The LP remains a key financing alternative for us going forward. We did do dropdowns in 2016 and 2017. We never give a specific cadence for that, the LP will be looked at in the context of our needs and other competitive fundraising ability or options for us going forward here. We think the LP has capacity to take up to $1 billion a year of assets. Remind everyone that any third-party equity raised at the LP is de facto dollar-for-dollar equity on the TransCanada balance sheet. Other options within that purple box would include further portfolio management. We're quite enamored with our portfolio, but we'll be unemotional about it, if it is the best route amongst all the options here is to sell additional assets. Potential project recoveries should Coastal GasLink not move forward. It has the same arrangements as PRGT did, and ATM is appropriate.
No need for discrete equity for the CAD 24 billion that is underway right now. Debt maturities over the next few years here, about $5.25 billion U.S. and about CAD 500 million. This includes Columbia debt assumed of about $1.25 billion, a little higher than normal, but that is with Columbia debt now consolidated on the balance sheet. It's fairly smooth profile. It's something we endeavor to do. We try and avoid maturity towers. We'll always look to the cheaper market to raise term debt funding. Our bias is to U.S. dollars, given the growth of the U.S. dollar business right now as a natural hedge. We are considering a European bond program as a means of diversifying funding sources as well going forward. We're in the process of renewing our shelf facilities in both Canada and the U.S. right now.
That gives us fairly rapid access to global markets, including the likes of Taiwan, where we have issued bonds into the Formosa market in the past as well. Liquidity is solid, about CAD 9 billion of committed bank lines with a group of 20 long-term relationship banks and three commercial paper programs that allow us pretty attractive funding. We're funding at about LIBOR plus 20 basis points right now. This is the prize going forward. We see EBITDA growing from CAD 5.9 billion in 2015, CAD 6.6 billion in 2016, about CAD 7.3 billion this year, up to about CAD 9.5 billion in 2020. This assumes we complete the CAD 24 billion growth program. It delivers about a 10% CAGR over this timeframe, and at the end, you end up with a very limited portfolio variability with about 95% of EBITDA contracted or regulated. You can see the build here.
We'll lose about CAD 200 million from the sale of the liquids assets. The biggest growth components would be the Columbia assets coming at about CAD 1.2 billion and CAD 300 million from gas pipes in Canada here and about CAD 300 million from energy as Napanee and Bruce contribute more there. Just spend a few minutes here on DCF coverages in two ways. You may wish to view this in the context of the size and the nature of our increased maintenance capital spending going forward here. Two observations. First, we still believe earnings matter. DCF is a supplemental measure as we assess our financial health and ability to pay dividends going forward.
We define distributable cash flow as cash available to common for capital allocation. It is derived as comparable funds from operations, excluding working capital movements, less payments to non-controlling interests, mainly LP distributions, less maintenance capital. Maintenance capital in our case has an asterisk. As I mentioned, we believe we are different with about 85% of maintenance capital that is recoverable in rate base for our assets going forward. We've included two ways of looking at DCF coverage here. One is fully loading all maintenance capital, regardless of whether it's recoverable or not. That gives you fairly healthy coverages of 1.5 to 1.8 times over this timeframe. Reflecting only non-recoverable maintenance capital, you end up with coverages in the 2.1 to 2.3 times range over this timeframe.
DCF is a data point for us, along with funds from operations, along with earnings per share, in terms of assessing our ability to grow the dividend going forward. Just touching on variability inherent in the business, moving left to right here. From a foreign exchange perspective, about 57% of our EBITDA this year will be denominated in U.S. dollars. If you exclude the Northeast U.S. power assets today to sale, that number is about 55%. That number has grown substantially and will continue to grow going forward. We naturally hedge that with about $24 billion U.S. of debt and hybrid securities and the associated interest expense that comes with that. That leaves us structurally long, about CAD 1 billion a year after tax going forward here. We actively hedge that on a rolling four-quarter basis to give us some predictability and smooth things out.
For context here, the currency that we achieved post-hedging programs as an exchanger is about 131 in 2016. We're fully hedged at 130 this year. We're largely hedged at 130 next year. In terms of sensitivity to currency, through 2018, given our hedge position, it'd take about a CAD 0.10 move in the Canadian/U.S. dollar to impact earnings by CAD 0.01. Going forward, excluding active hedges, it's about CAD 0.01 for CAD 0.01 in the post-2018 timeframe right now. From an interest rate perspective, you can see very heavily fixed rate long-term focused here in terms of our portfolio. We don't control valuation, but the elements of interest rate exposure we do control, we do manage. I'd point out that our cash flow is largely immune to interest rate movements. The long-term nature of our portfolio, again, 20-year average life to a hybrid fund maturity.
A significant element of our interest expense is flow through to our customer base, particularly in the Canadian regulated pipes. We'd note that in a rising interest rate environment, ROEs tend to rise, as allowed by regulators, albeit with a lag basis. We don't assume these historical low rates in sanctioning new projects. We assume something more normalized going forward. Lastly, on the volumetric side here, commodity risk side, it's never been very large, but it has dropped notably here in the past couple of years as we've, again, exited the Alberta PPA business and the Northeast U.S. Merchant power business as well, seeing Great Lakes contract back up again here. You can see the mix here, about 61% is NEB FERC-regulated pipes, 34% is long-term contracted assets.
We've got 3% in here for commodity exposed businesses, but when you carve out the Northeast U.S. power businesses here, that's probably closer to 1%. Then about 2% is volumetrically exposed, that is really Keystone South of Cushing, where there is spare capacity there. I think in homage to my roots, I've described this as a Saskatchewan earnings cliff a couple of years ago. This is our EBITDA look-out to 2025. What this is meant to highlight is the long life and low volatility nature of our cash flow streams as well as our capacity for new investment that starts rising 2019 onward here. Again, this assumes CAD 24 billion of capital under the current program is completed, and normal course U.S. pipe recontracting. We do have a visible CAD 9 billion of EBITDA effectively lock-in in 2025 at this point.
Another half billion dollars that we would describe as variable, which again is really Keystone EBITDA South of Cushing right now under the Marketlink asset there. As I mentioned, we do have growth capacity in 2019 onward. You've heard over the course of the morning here, we consider ourselves as having a fairly high-quality opportunity set with five different platforms in gas, oil pipes, Canada, U.S., Mexico, and the energy business. We've managed to find CAD 75 billion of stuff to do since the year 2000. We don't think we're going to run out of opportunities, but in the event that we don't have sensible things to do with the money, we will return it to the shareholder, in terms of a higher dividend payout, or we will shrink our balance sheet proportionately in a manner that preserves the A grade credit rating metrics.
With the backdrop of the base business performing well, visible growth here over the next few years, healthy coverage ratios, a solid opportunity set, and the financial capacity to pursue that. We, again, reaffirm dividend growth at the upper end of the 8%-10% range through the end of the decade and, as well, extend that 8%-10% range to 2021. Again, this is backed by real growth in earnings and cash flow, with no fundamental change to payouts, no fundamental change to corporate structure or leverage. To wrap things up, I'd love to show you an accounting video or something on the heels of Carl, but I just don't have one on hand here right now. It's a proven resilient business model. It's delivered a 14% TSR since the year 2000 through just a myriad of economic and industry conditions.
We'll continue to focus on the long term, but not at the expense of the short term. Great opportunity set, the means of funding it with the capital structure here. We won't pursue growth just for the sake of growth. We will be disciplined, and we will focus on share count and per share metrics going forward. With that, I will stop there and invite any questions you might have.
Sorry, just back there. Then after that, Andrew. I saw Andrew's hand.
Don, just wondering, as you look towards 2020 and beyond, assuming the DRIP is off by then, just what level of annual growth capital you believe can be fully funded without having to turn the DRIP back on?
Probably north of CAD 5 billion a year would be my thumb in the air number. A portion of that would probably be spoken for with maintenance capital that is recoverable. Something in that neighborhood, about CAD 5 billion a year.
Andrew?
Andrew Kuske, Credit Suisse. Don, when you think about the competitive positioning of the company overall as you're de-leveraging at this point in time, when you get through the hump of 2018, how do you think about just the relative positioning as we think the asset base that you've got on a network effect that allows you to rinse and repeat on your financial model then also deploying capital through the network? Then you've also got a balance sheet of the size that you can weather the storm for 10 years of a KXL or an Oakville that turns into Napanee. How do you think about that duality? Does that allow you to get more business or just increase returns on the business that you win?
It's probably a bit of both, to be honest. In terms of improving the returns on what we have, it's fairly basic. We're chasing fairly low-risk stuff that's in a fairly low band of return profile. We wouldn't expect to step off the curb and take on far riskier businesses, in terms of chasing things outside our risk preferences to drive returns higher. I think we'd stick to our knitting. We think over time, that works fairly well. The capacity to do a multitude of things that we think the CAD 100 billion asset base will spin off a significant amount of organic opportunity going forward. If we can land one or two or potentially all these major projects over time here, it gives us some comfort that we can fund it in a sensible fashion and preserve the A-grade metrics going forward.
We always say from a financial capacity, the A rating isn't worth anything until it is, then it's worth a lot. That tends to show itself when there is stress in the marketplace, we're not going to just chase stuff because we have capacity at any given point in time, but we'll make sure it's sensible and wait for our opportunities.
Maybe just as a follow-up, given the fact you've got an A-grade credit rating and it's pretty unique in the industry, do you attract a different kind of business and just higher quality business because of that and higher quality customers?
In some cases, yes. I would think that when you start looking at some of the very long life contracted assets that we have, the counterparts, if they're going to sign up for 30 or 40 years, do look to the stability of TransCanada as exemplified by its credit rating. If we're delivering an absolutely essential service to their assets, an example would be the LNG projects. I don't think it's lost on our customer base, the credit rating and the financial strength going forward.
Ben.
Yeah. Two questions on maintenance CapEx. On the CAD 500 million increase from last disclosure a year, can you comment on the extent to which integrity spend is driving that versus the reallocation of growth to maintenance? Secondly, on post 2020, assuming modernization spending is starting to decline, wouldn't you expect pretty big decline in maintenance CapEx and big increase in coverage ratios?
Yeah. The first part of the question in terms of the half billion CAD increase, it wouldn't be any changes of color coding from growth capital to maintenance capital. Under GAAP and under FERC and NEB regulation, it's fairly distinct what constitutes maintenance capital versus growth capital. There's really no significant migration between those two color codings there. Going forward post 2020, it's difficult to tell at this point in time, if there would be a dramatic decline in maintenance capital. We would expect, given the gas flows and what's been outlined this morning in terms of the amount of gas coming through the system, WCSB and Appalachian, that the assets would continue to sweat fairly hard over that timeframe. Could there be some dissipation of that?
Yes, there could. We don't see gas flows declining substantially such that the workload on the assets would decline materially. It's early days on that, but don't know. In terms of a modernization, the Modernization program at Columbia, Modernization 1 and 2, that was the fact of growth capital color-coded, not maintenance capital. Could there be a Modernization 3 program? Yes, there could. We don't have any clear line of sight to that at this point in time.
Faisel.
Thanks. Just a couple of questions. In terms of maintaining your A rating and with the capital program you have, what's the target sort of debt to EBITDA and FFO to debt metrics that sort of allow you to maintain the rating over the long run?
Yeah. The key metrics we're looking for are debt to EBITDA under five times and FFO to debt in excess of 15%.
Okay. That incorporates the upgrade in the business from the agencies since you've sold some of the power assets too?
Yeah. We're starting from a fairly strong business position of the credit rating agencies. There's probably not a lot more headroom to move up in terms of business position. It's really on the quant side that we need to get to here, and we'll hit those levels in 2018.
Okay. Last question. On the dividend, as you look out over the next few years at the growth rate, is there a target payout ratio you look at on EPS, earnings per share? Are you just targeting the coverage ratio on DCF?
Yeah. Not specifically. What enters into our thinking here is, and you can look back over history, we tend to pay out 80%-90% of accounting earnings, which equates to about 40% of FFO. You've seen, depending how you define DCF coverage here, still very healthy coverage ratios. Those are three things we look at here, as well as what is the growth pipeline going forward and the visibility to continue adding new projects.
Sorry. Robert, go ahead.
Thanks. Don, you've laid out the funding plan, but I'm just wondering, when you look at the potential to funding KXL, how does that change, especially with the focus on the share count, and can you make the same kind of no need for discrete equity around KXL funding?
Can't say that unequivocally today, but I start looking at it as to much of the KXL spend would be in 2019 and 2020, which is when we start having significant and growing capacity internally to fund new projects. The fact that we do have significant amount of the long lead time items already purchased on KXL would suggest that we'll avoid that to the extent we can. Turning on DRIP, extending ATM, selling more assets, dropping more assets into the LP, we have a lot of tools to avoid discrete equity in that case. When you're generating CAD nine-plus billion of EBITDA a year, that's fairly healthy, and it doesn't move around a whole lot depending on different economic conditions. Our hope would be we watch share count very closely on this front here.
I'm not dodging the question, but it's hard to tell at this point. We do have significant capacity in those years.
I guess, just given how much of the story's been around highly visible growth from small to medium-size projects, KXL obviously comes with a much bigger ticket. As much as you like owning 100%, would you consider a partner to help reduce the capital intensity of that project?
At this point, we've come pretty far on this one. It's not something that we've really kicked around substantially here. Russ, anything you want to add in terms of a partner on KXL?
No, I think, as Don said, for CAD 100 billion-plus balance sheet here, we look at taking on a CAD 7 billion or CAD 8 billion project split over a two- or three-year period. It is doable. I think historically, we would have probably thought more about that. We'll see when we get there. To Don's point is, we look at everything through the lens of per share value, and risk-return tradeoff. As we move forward, we'll keep those things in mind. Right now, our plan doesn't include partners. We never say never to things like that.
Any other? Ted, just give us a sec.
Just on the dividend again, you're extending that by a year, the 8%-10%. How do you think about the balance of that versus you are issuing equity on the DRIP? You talked about turning on the ATM. Why push the 8%-10% now? Are you getting paid for it, do you think, in your valuation? Why not pull back on that and maybe reduce your equity funding needs?
We debate that at length. We think the 8%-10% is affordable. In our sense is it's valued by our shareholder base. As long as we're being rational and not getting out ahead of ourselves. Our view is we will grow the dividend prudently and turn on the DRIP and give investors the opportunity to reinvest into the stock at a modest discount versus just restraining dividend growth going forward. We think it's a balancing act between those two things that is, in our view, appropriate.
Maybe this is probably a question for you and or Russ. As you look at the valuations in more in the U.S. side of the world, and you made obviously a very nice acquisition of Columbia that's driven a lot of growth. How do you think about the opportunities that are maybe out there for third-party M&A?
I'll start. We're pretty full right now, and we hope to fill up again here with organic stuff. It's not something that we set money aside to do. If high-quality stuff does come along, we'll certainly look at it, and I think the state of the company is such where we have that luxury right now. It's not something we have to do. We'll bide our time on that front. Everyone has their wish list. The stuff never comes up for sale, the really good stuff, or very rarely. When it does, it's quite often under strange circumstances, so you need to act quickly. This isn't exactly strange circumstances right now in our view.
Great. I think in the interest of time, we'll leave it at that. Again, Don will be around through lunch if you've got other questions for him. I very much appreciate that, Don. In the interest of time, we'll wrap it up here. Russ will just have a couple of minutes of closing comments, and then we'd invite you all to join us for lunch.
As we sort of close up on the day, wanted to refer to our key messages from the day. I think firstly, I would say that we have delivered on our strategic objective of being a leading energy infrastructure company with a pretty strong track record of delivering long-term shareholder value with about CAD 86 billion of high-quality assets, about 7,000 talented employees. Again, to put that in perspective, you think back to when TransCanada and NOVA merged, we had more employees than that, and the company's worth approximately CAD 20 billion. We've come a long ways. We have five platforms for growth. The Canadian, U.S., and Mexican natural gas business, our liquids business, and our energy business all have opportunities for continued growth.
Since 2000, we have delivered an average annual shareholder return of about 14% by investing about CAD 75 billion into low-risk assets that generate predictable, sustainable earnings, cash flow, and support a strong and growing dividend. As we advance the CAD 24 billion near-term portfolio of commercially secured projects, we expect to deliver significant additional growth in earnings and cash flow. Further, as evidenced by the fundamental long-term outlook for natural gas, for crude oil, and for power, our view is there will be plenty of opportunities to continue to reinvest our strong growing cash flow into our core businesses and into our core geographies. Today, we're advancing about CAD 20 billion of larger-scale projects, and we expect numerous other growth opportunities to emanate from our extensive asset footprint that we have today.
As a result, as you've heard many times today, we expect to continue to grow our common dividend at the upper end of the 8%-10% range on an annual basis through 2020, we foresee additional growth of 8%-10% in 2021. At the same time, as you heard from Don, we expect to maintain our strong financial position to ensure that we're able to prudently fund our near-term capital program as well as our future growth opportunities. That's the end of our prepared presentation today. Thank you again for your time, patience, and most importantly, your support and interest in our company. As Dave said, we have lunch here coming up for those of you that can join us, ask more questions. For those of you who can't or are traveling home, you'll travel safe.