Good morning and 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 will help shape both the pipelines and the energy businesses in the years ahead.
We'll begin today with Russ Girling, our 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 key priorities as well as our promising outlook for the future. It will be followed by Karl Johansen, Stan Chapman, Dean Patre, 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 the 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 Investors section under the heading Events. And 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. And finally, just a couple of brief comments on non GAAP measures.
We will make reference to comparable earnings before interest, taxes, 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 meeting under U. S. GAAP and therefore may not be comparable to similar measures used by other entities. With that, I'll turn the podium over to Russ Sterling for his opening comments.
Thanks David and can everybody hear okay out there? No problem, it's good. So good morning, everyone, and thank you very much for joining us today. Very much appreciate obviously the ongoing support of company and your ongoing interest in our company. It's hard to believe that it's been 18 months since we closed the Columbia transaction.
It was a $13,000,000,000 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 4 hours or so, myself and 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 $75,000,000,000 in high quality, low risk pipeline and power generation assets. Today, our $86,000,000,000 portfolio of assets produces about $7,000,000,000 of EBITDA with over 95 percent of that EBITDA coming from regulated businesses or businesses that are underpinned by long term contracts. But 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 5 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, as I can tell you, are performing very well in 2017 and the result comparable to 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 cost to both us and our customers. We've maintained 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 $24,000,000,000 of near term growth projects that are largely expected to enter service between now and 2020. We're also advancing another $20,000,000,000 of medium to longer term projects. And expect our existing businesses will generate significant organic growth opportunities in the years ahead. And finally, we do understand the value that our shareholders place on a stable and growing dividend.
And 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% to 10% range through 2020. And as highlighted in our news release this morning, we are also extending the 8% to 10% range up to 2021. So 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 delve a little bit deeper into each one of these themes, starting with the 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 $75,000,000,000 into high quality, low risk pipeline and power assets. Through that investment, the United States and Mexico.
We've developed 4,800 kilometers or about 3,000 miles of our liquids pipeline business and we've expanded our power generation portfolio by about 4,500 megawatts. 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 $0.80 per share in the year 2000 to the current level about $2.50 today.
That represents a compound average growth rate of about 7% and equates to a payment of about $14,000,000,000 in common dividends to our shareholders over that period.
And while
we maintain 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 $10 per share in 2000 to about $63 today. And 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 1st 9 months of the year. Comparable EBITDA was about 5 point 5 $1,000,000,000 up 15% over last year.
Comparable funds generated from operations were about $4,200,000,000 in the 1st 9 months of the year of about 12% from last year and comparable earnings per share at $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 0.62 $5 which equates to that $2.50 per share on an annual basis and as we've noted represents a 10.6% increase over 2016. But 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 $250,000,000 of synergies that we promised at the time we acquired that company. During the year, we also acquired Columbia Pipeline Partners for US1.2 billion dollars 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 $24,000,000,000 near term capital program. By the end of this year, we expect to place more than 5 $1,000,000,000 of those assets into service.
At the same time, we continue to replenish our portfolio of growth assets by adding about $3,000,000,000 of Canadian and U. S. Natural gas pipelines expansions. And we continue to advance our over $20,000,000,000 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.
And then in October, after careful review of changed circumstances, we informed the National Energy Board that we would no longer be moving forward with our energies project. On a 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 see us move 1,400,000,000 cubic feet a day from Empress to Don under that 10 year agreement. The new request for service on the NGTL and Canadian mainline systems 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 substantial amount of money this year across the capital spectrum on very compelling terms that included more than $6,000,000,000 of long term debt and hybrid securities in both Canada and United States. In addition, we completed the drop down to TC pipelines for about $765,000,000 dollars and we generated another US1.1 billion dollars 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, supported by an A grade credit and we remain well positioned to fund the balance of our capital program. So in summary, it's been a very busy year, but I can tell you that I'm 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 $100,000,000,000 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 2 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 5 155,000 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 6,000,000 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, you just have to ask us. So 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. But I think our real advantage is in our 7,100 people across Canada, the United States 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. And 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 6 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. 2nd, we will continue to improve the profitability of our existing businesses by focusing on maximizing the revenues and reducing the costs and efficiencies in each of our businesses.
3rd, we'll continue to focus on executing the $24,000,000,000 program, bringing it in on time and on budget. 4th, we'll continue to advance that $20,000,000,000 of medium to longer term projects that are in development in a careful, as you've seen us do in a careful and cost effective manner. And 5th, we will cultivate a portfolio of additional low risk organic growth opportunities from our existing footprints in our existing geographies. And 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 CitiVic 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 track record 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 are focused on ensuring that we have world class capability to respond, to protect the public and the environment and restore those facilities to service as quickly as possible.
And I think you saw an example of that over the last couple of weeks. And 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. And TransCanada 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 and we won't be satisfied until we've achieved our goal of 0 incidents. That's why we invest about $1,500,000,000 a year in integrity and maintenance record of collaborating with various stakeholders and communities in which we work.
We treat landowners with respect and fairness, and 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 stake always plans. In summary, while our customers are always looking for the best price services, they are becoming more environmental stewardship and respect for others is aligned with theirs. We believe that our world class practices in operations, project execution capabilities, strong track record of working collaborative with stakeholders and a strong financial positions means that we are well positioned to be their partner of We have $24,000,000,000 of projects that we are advancing today that will expand and extend our footprint across North America. Our $24,000,000,000 growth program includes a series of projects in jurisdictions where we have relatively normal what we would call normal course permitting and construction risks that we think are infinitely manageable.
That includes about 22,000,000,000 dollars 1,000,000,000 of natural gas pipelines expansions in Canada, the United States and Mexico. It includes about $1,000,000,000 of projects related to regional liquids developments projects related to regional liquids development in Alberta, and it includes $2,000,000,000 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 $10,500,000,000 with the remainder to be spent over the next 2 years or so. Notably, each of the projects is 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 $5,900,000,000 in 2015 to approximately $9,500,000,000 in 2020. That equates to a compound average growth rate in EBITDA of approximately 10%. But just as important is 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. So looking forward, I'm confident that we're all 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 $20,000,000,000 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. And as I mentioned earlier, we received broad interest in that open season. Over the last few weeks, discussions with to conclude sufficient binding shipping commitments to advance the project.
On the Nebraska front, Nebraska on November 20, Nebraska Public Service Commission issued its decision on the routing through Nebraska. And as we've said, we continue to review that decision and its potential impacts on both the cost and schedule of the facilities are also permitted. So what we're doing is we're waiting for a final investment decision facilities are also permitted. So what we're doing is we're waiting for a final investment decision from the project sponsors to move that project forward. And finally, in our long 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 $5,300,000,000 investment that represents our share of the expected refurbishment costs in $20.14 So that 5 point $3,000,000,000 investment will extend the operating life of Bruce Power through to 2,064 with all the power generated sold to the continue to rise. This growth will require 1,000,000,000 of dollars 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 30,000,000,000 cubic feet a day between now and 2,030. 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 2 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 United States. 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.
And 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 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 Portland 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 United States 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 expertise to participate in other forms of generation, which includes wind, solar and in our case, nuclear refurbishments at Bruce Power. So 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. And 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 $24,000,000,000 near term capital program is expected to produce $9,500,000,000 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 investments in projects between now and then. However, as I pointed out, with numerous growth opportunities expected to emanate from our vast North American footprint, dollars 20,000,000,000 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 average annual rate at the upper end of the 8% to 10% range through 2020. And we expect that dividend growth to grow by an additional 8% to 10% in 2021.
Importantly, our dividend growth outlook is supported by growth in earnings and cash flow and strong coverage ratios, leading 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. So before I conclude and pass it over to my colleagues for their presentations today, I'd like to offer a few comments about our executive team. As I said earlier, while we have great assets, they don't produce results on their own and they require significant human ingenuity and expertise. And while I'm obviously very biased, I have been at this for 35 or 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 the slide are familiar to a lot of you here today, Carl, Stan, Paul. Paul won't be here today. Dean or Dean Patrick will be filling in for him and Don provide you with updates from their respective areas. But as well, we have Christine and Francois with us today.
Along as you met last night, a number of our Senior Vice Presidents, I'd encourage you continue through the breaks today, seek them out, ask your questions. That's why they're here is to let you get to know them. But as well, they are supported by 7,100 other folks. And as you think about a $100,000,000,000 plus company with only 7,100 people, each of those people has a lot each of those people have a lot of responsibility for certain parts of our company. They're in Canada, the United States and Mexico.
They are experts in their fields and they work tirelessly to safely build and operate the tirelessly to safely build and operate the blue chip portfolio of long term and energy infrastructure assets that we now hold. And it is their efforts that will drive the success of this company going forward. So that concludes my initial remarks today. I'll turn the podium over to Carl. He's going to update you on Canada and Mexico Natural Gas Pipelines and later he'll provide an update on energy.
In terms of questions, I'll be available later in the morning. We're not going to take any
right now, but as folks get through their presentations,
I'll join them on the podium here and be able to answer questions with them throughout the morning. So again, thank you for joining us today. And Carl, the podium is
yours.
Well good morning
everybody.
I think I'll get right into it. I'd like to start with the 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 in the U. S. I guess I want to make a point here that we've been very, very successful in building franchises in this business.
Now when I talk about a franchise, I'm not talking about something the regulator has given us or 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. And what franchises give us are a couple of things. Number 1, we've built up critical masses in these regions that we are lower cost producer. So people come to us, we actually have competitive advantages because we do have actually have the infrastructure there.
2nd thing is this 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. And 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 3 pretty large franchises there. Number 1 is NGTL.
75 percent of the basin production goes through NGTL. Right now, we're moving about 12 a little over 12 Bcf a day. We haven't seen those volumes on NGTL in over 10 years. So it's a huge amount of natural gas that comes on the system. And really, 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 that TransCanada system in the Appalachian Basin one way or another depending upon whether you're going to market or if you're just want to get your supply on the system. And the third would be, and this one that we talk less about, is our Eastern Triangle on our mainline. When you take a look at that Eastern Triangle, it still has about 70% of the market share for market in that area.
There's no obviously, there's no supplier originating on that area, but a market area. And it's very difficult to get around. If you want to build by it, you're building literally through very, very large cities. So and 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.
But when you take a look at our map there, other than a couple of holes, we've got a pretty good franchise started there in the Mexico City, in the Central Mexico area. Outside of the franchises, I think this also gives us a good feed into market areas. When you look at the when you look at NGTL, you can go on the Pacific Northwest, you can get to California, you can get to Northern border to Chicago, you can get to the mainline and then down Great Lakes into the Midwest US. You can get down the mainline into the Eastern Canada and the mainline into the US Northeast. So 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 that 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 2 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. It's just like 6, 7 short years ago, we used to think there is about 150 TCF left in WCSB and now there is over 1,000 accounting, quite frankly. This represents between the Appalachian WCSB and North American demands, there's probably 100 years of reserves and counting still. And so those are going to be a big those are the 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 2, the Appalachian WCSB.
And it is really up to us to make sure that we keep the activity 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 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 of a broader look at it, kind of a 10, 12 year view. And we're seeing a lot of this right now.
So where is the gas going to go? We all know in this room, everybody covers the upstream sectors. Well, we all know that the prices are moderate, financial gas, lot lower than they used to be but 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 start a new. 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.
And 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 in North America wise. It's at a price point now where we're starting to beat out coal. And so we're seeing that we're going to see gas continue to penetrate electrical generation space.
You can see that in this graph. And 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. And of course, LNG exports.
So this map is this graph is a little bit misleading. This is actually this is average annual, but there's more LNG exports even today than it 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. So in LNG experts, I think we're 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 want to kind of put up a chart on kind of what we think the actual growth is going to look like. And think this graph is a little telling. If you take a look at our traditional markets, that being kind of the WCSB, the net market, the Eastern Canada, kind of Midwest, U. S.
Northeast, they're all growing still. And they all are 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 interconnectivity, play for on gas. When you take a look at the Gulf the Southeast.
It's really a big LNG place. And if you take a look at our infrastructure on this map, you'll see 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. And 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.
And Stan will talk a little bit about his plans on the Gulf Coast. I can tell you that Russ brought it up on the West Coast, B. C, we're still fully engaged and I'll talk about that in a minute on West Coast, B. C. We're still fully engaged on moving gas there.
And 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 the is going to be where the LNG is. Just to give you an idea what our system can do today, we can move and we have made proposals discussions. 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 mountain area all the way into the all the way in the Gulf Coast using predominantly our own system.
And we can we can we can we can put a tariff together for that And we can I think we can make it competitive? We have seen some WCSB gas move into the Gulf Coast LNG market already and not through our systems, but I think we could even we can compete with any other system out there. So if our producers But if 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 in the Mexico City once we get started to Texas fully built up, which should be about a year about a year from now. So we we we can offer our suppliers flexibility depending upon where they want to go.
They can stay in local markets or they can go off to far flung markets. It's we 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 except this high new gas production that we have and
then finding
external markets for getting connectivity to those external markets. We did 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. We've we have placed in NGTL. We have placed $2,300,000,000 in service this year or we will have placed $2,300,000,000 by the end of year.
That's 30 odd projects that we brought in this year at NGTL. Actually, we actually beat our estimate a little bit. We didn't expect to get all 30 projects in this year. And it's and you can tell just by the gas where we've now hit new peaks in production on it. And there are less constraints in the system right now, but 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, so that is alleviating some of the problems we have with oversupply. We also secured an additional $2,000,000,000 worth of projects out of the NGTL system over the last year. This is interconnect 3,000,000,000 cubic feet a day of new gas supply and delivery request. About 2,300,000,000 cubic feet a day of that is new receipt supply and new supply on to our system.
That will be coming in, in the 'nineteen 'twenty, a little bit in the 'twenty one range. And $700,000,000 they have new delivery service on their system. So that's getting the gas off our system into markets. But equally split between going to GTN, going down the West Coast and going into the oil sands. So we are starting to see a bit of an imbalance right now.
We're getting more receipts than delivery contracts. But I suspect with the price signal going out to our customer base, that we will see that moderating and reverse itself over time. I think you can expect as time goes on, we'll see more delivery contracts being being being being requested and and less receipt to kind of take that balance off. If you look at our balance contracts on NGTL system right now, they're actually quite balanced, which to understand they both they each have different load factors. A receipt contract is a different load factor than an LDC contract, for example.
So even though our contracts are balanced, you will see supply demand imbalances crop up depending upon the load factors of the different, of the different contracts. Our system this year as well. The the LTFP was was approved by the by by the the NEB and was implemented for November 1. That was quite successful approval. I think it cleared a lot of the surplus that has been kind of nagging us on the mainline for years.
So what it has done is it's taken 1,400,000,000 cubic feet a day, really taken it out of the market and now the rest of our capacities is that much more valuable. That's that much more sought after once we got that in. So I think that LTFP was a very meaningful thing for the mainline. And we've also expanded through this year. We've expanded the Eastern Triangle.
And we've continued 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, $8,000,000,000 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 to the entire system to entire NGTL system to really 85,000,000 is actually a little bit higher than that.
Last I calculate was closer to 90% of it's coming out of that kind of Montney, Duvernay, Deep Basin part of the system. So 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. You know, everybody's probably aware of the struggles of 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 the supply going up, we have seen more supply in our system, the local demand. So we've seen a number of issues on our system, but we've had some cuts, we've had some maintenance that people are feeling now because the system is so full and 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 is here. Demand is up in our system, but come spring, you will find that the volatility will reach a return. The real trick on the system right now is to get export capacities and go find markets other where that aren't in such a surplus right now.
The maintenance cuts, there are few far between the capacity cuts, they're very few. We're talking the cuts that are episodic. They're small. They're generally under 300,000,000 a day. They're not causing the volatility you're seeing right now.
The volatility is being caused by more supply more local supply on net than local demand. And 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. And we and see with the 30 projects we put on this year, we'll go down even more and next year our projects will reduce it even more. Our current rate base is $8,000,000,000 in NGTL.
We are working with just today's construction program, we are working up to about 12,000,000,000 cubic feet a day. And we will and we're expecting some more, quite frankly. We still have over 1,000,000,000 cubic feet a day in the queue of new receipt service requests. And we were expecting to hold an open season shortly for some demand services from delivery services request. So there'll be some more coming out of this as we continue to work to deconstrain it and to get more connectivity 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 the where people were using IT, not Feet. And then there was no more IT. So the producers, after some pain and so on and so on searching,
started contracting for Feet.
And now we're seeing the same type of we're we're starting to see them want to get out of net and buy delivery service. The main line is I see some changes over the past few years as well. We're still on track to split the main line in 2, the Western System, the Eastern Triangle in 2020. That's still on track. But 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 rates on the mainline. So it's been a long road. I've seen lots of rate increases during my tenure on the mainline as we started out the issues. But the volumes are stabilized. The things like the LTFP brought stability to this mainline.
And I think for the 1st period of time there I'm not going to go over what the exact cuts are. It depends where you are, but it will be the first time since I've been here that we've actually seen the rates go down on the mainline. So that's some work we're quite proud of that we've been able to bring the mainland to point where we stabilize and start lowering the tools. The contracting on this system is about 8,000,000,000 cubic feet a day, a little bit higher than that. 3.88 of it is coming on the Western system, so long haul and the rest of it will be very short haul contracts.
So significant billing determinant still on the system. And as you can see, significant gas is moving on the system. It's, I would like to say that the lines in good shape today. The LTFP has worked. It has cleared our surpluses and
I think
that is actually made the rest of the capacity on the mainline more valuable to our customers now that there's not this big overhang. So what's the future capacity that we're going to look at? Well, we have to find roots out everywhere. And I'll let Stan talk a little bit about what he's planning for us kind of some of the U. S.
Pipelines to take away WCSB. If you think of the WCSB and the NGTL and the main lines kind of headwaters of some of the U. S. Pipelines, Dan will talk about that. But really, we're working with everything we can.
We will 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 point 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, 3.8. If our shippers want to ship more, we can bring some of the latent capacity on the mainline back in the services.
It shouldn't be that difficult. When we took it out of service, it was just better maintenance. We can do the maintenance and bring it back on service. So if our customers want to go east, we can bring back some of that capacity. We can do another LTFP.
We are working with our LNG customers to whatever we can do to make that LNG more viable. We certainly will do a successor could be very important for the WCSB. Other concepts we're looking on is aggregator roles. If we need to aggregate volumes take it 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 pool, but if I have to and it's in the best interest of TransCanada, we will. Just 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're we have been told to a decision in 2018 at some point. So we look forward to that.
I think it's still it remains an important project for WCSB. It's very it's very sad that we lost the Petronas project. We did submit all of our bill for all of our cost in that project and we did get that paid. So I think Canada has lost a very stand up company. They're great to work with and won't miss them being a big customer of ours.
So what is the near term growth projects? I think we talked about most of these. It's all LNG or NGTL NGTL base and some Canadian mainline. But as I said, I think there's some more in the hopper as we go to continue to deconstrain the system and as we go to get more conductivity outside of the system. So stay tuned for that.
In maintenance capital, I'd like to spend a couple of minutes on. This system maintenance capital on our systems, regulated systems are as good as growth capital. We immediately in Canada, we start earning return on investment on them. And 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 600,000,000 a year on both of them. And that's been consistent even before the 2017 start here. And we're expecting it will 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. This is a fairly both systems are actually fairly old and they do require to keep that capacity going, they do require some maintenance.
So we consider maintenance capital to be a good thing in this particular business because we do get to roll in the rate base and we do get to earn our return on and up capital on that. Just to show you the natural gas net income outlook, it's I put up net income as well as EBITDA. EBITDA is tough in Canadian 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 flow through. So it's probably not as good indicator. We tend to use EBITDA everywhere else in the company. But I threw out the net income outlook 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, I will talk a little bit about it.
We've been right now have 4 projects that are actually earning revenue. We've got 3 that are in construction. We got the 2 and build to raise both about little over $500,000,000 each U. S, double of 9 $1,000,000 a day. These are really pipelines that take it from the Gulf Coast into the Mexico City Heartland.
And we have Sur de Texas which is the offshore going from Brownsville down into and connecting into both of these facilities. The construction is going well. We've run on Chile, we have run into some indigenous issues where there's a bit of a delay on certain portions
of it. But for the most part, we're
going to get year. There might be some that are going to have to wait because of consultations. So year. There might be some that are going to have to wait because of consultations, but we should be able to get at least partial usage of leases for the end of next year. The Circuit of Texas, which is kind of the more technically complex, we're putting 42 inches pipe on the ocean floor.
It's going really well. We're laying about 3 kilometres of pipe a day. We're probably over about 300 kilometres right now have already been laid. And we're starting all the tie ins on the onshore pieces of it. So it's 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 got this fairly good infrastructure there. Now we have to go fill it up.
So now we got to do marketing marketing department, we 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 The they've never had natural gas deliveries have 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 butane. So this gives you an idea where we're going to be working on next little while. We're going to be filling up our pipelines.
Our pipelines have got great basis now with our CFE contracts. But every dollar we can earn from feeding industrial, we get to keep. So it's going to be smaller business but very, very profitable for us. And this one gives you an idea of what Mexico is 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 $500,000,000 $600,000,000 in EBITDA a year on it. And it's this will come about with the completion of our existing $2,500,000,000 construction project.
So you'll still see quite 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 and term
projects
term projects. Number 1, we are not going to stop until we get these projects finished, until we get NGL 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 in 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 2 rate settlements that we're working on right now, 1 on NGTL and 1 on the mainline.
Mainline will go to a hearing. We just won't be able to get a settlement on. But I will say we have we do have people that are supporting what we're going to be filing. So it is just a rate hearing. There is no real real depreciation studies or anything like that coming this hearing it will just be a reset of the rates.
And then on any detail we remain in negotiations with potential settlement there. And driving competitive growth initiatives, the capacity investments across our network, the WCSB growing. Now 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 in 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 that is we do recognize that in order to get that gas and attract that gas, we're going to have to find a new home for outside of the year. And the vast long term opportunities, close to gas leak. It's a bit of a sleeper. Call. People have Shell has certainly relate to us as a partnership that they're excited about that project and I see every day that they're 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.
And with that, maybe I can open up for a few questions.
Sure. Great. And just for as we take questions, we've got a couple of mics that will move around the room quickly. One, so that 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 people, numerous people have an opportunity to ask questions.
Go ahead.
You confident those projects can overcome those challenges?
Well, you know, it's a good question. What has happened, I guess, is the question. And what can be done about it? It's hard to tell. You have to talk to Petrogas to find out really exactly what happened in their project to go.
But I can tell you Petronas had a lot of difficulties just with the permitting And the market changed as they were through this long journey of permitting. I think the last I think major project standing, there's a bunch of smaller projects still on the West Coast that are still motoring along. But the last major project, LNG Canada doesn't have those same problems. It's already fully permitted by but it's already fully permitted. It's really an economic problem and- economic issue for them.
And and it's an allocation accountable for them. So I do think that my understanding is 2023 ish is the kind of 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. And I think that's 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 kind of come out with FID in this particular time already hit that type of window. So I think right now for projects like LNG Canada, it's hitting the proper window and capital allocation 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 got a rebate there the capital. Rebid the project.
They're asking us to sharpen our pencil. Certainly, they're doing all the right things there. But I do think it's a matter of their own capital allocation and and and trying to meet that window and how do they best meet that window. Is it better to do West Coast LNG or better to evolve coast? Maybe these types of decisions they're making.
Sure go
ahead. Andrew.
Andrew Kusky credit suites Carl, when you think about just the mainline and reactivating portions of it that haven't been used for years. So 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 think manage to draw more shipper interest. How far do you think tolls can go down?
I haven't looked at that to be honest. And 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. But what I probably would do is I'd probably do another LPFP.
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. So I'm not sure and 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.
So I would not do it unless it didn't mean that system would get revenue that it wouldn't have otherwise already that wouldn't otherwise get, which means direction of the 12th will decrease with it. But it's just a speculative right now to kind of try and give you a number. But it we would not proceed with it unless it added to the revenue of the mainline and would moderate everybody else's tool. Every time you do a low attraction rate, you really have an obligation to make sure that rate. Has something in it for other shippers on the system as well so we we would make sure that would be- that that would be the case so directionally down.
Faisal
sorry. Thanks guys- Faisal Khan with Citi Group. Just if I look at all the capital you're spending on NGTL in the mainline and I look at the incremental EBITDA net income, it seems fairly low. So can you just help us bridge the gap on what sort of financial metrics you're looking at in terms of how you're going to what kind of return you're going to earn on this capital you're putting to work over the next few years?
Well, I guess I tell you a couple of things. There's a couple of reasons for that. Number 1 is we still have a 3.19 percent composite depreciation rate. So although I'm investing $2,000,000,000 a year in the system and pulling out $500,000,000 a year in depreciation, when you take a look at it. So the full
you have to take a look
at the net capital we have in there. The on the net 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. Thickness. So those are numbers you're in their net capital and with those types of returns and when we've done those, we've assumed that return carries on. But I do think when you add up the numbers, you have to take you have to think about how much appreciation we're taking out every year as well.
So it doesn't completely. If we have a $5,000,000,000 program over 5 years for example you know we've taken 2.5000000 or not not quite 2.5000000 but 2, 2,000,000,000 plus of depreciation over that period of as
well. Rob Hope, Scotia. You mentioned earlier about a 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 of the basin and at what cost?
Well for the delivery capacity for the NGTL, we haven't really started engineering on that but I got to be much for 2020 21. I think that's what- you know I think that's kind of the- that seems to be the regulatory schedule we're on right now I don't think it's as you know, it's not construction that's the issue. It's just the time of thing is regulatory permits. Capital class, I don't have yet. I'd be speculating as far to get born right now but it's a- give you an idea of the size we will probably go out looking for maybe a 1,000,000,000 cubic feet a day of natural gas to- to- get it delivered contract with so.
You know. Give me an idea that.
Jeremy Tonet, JPMorgan. I think in Western Canada, you noted the potential to be an aggregator or marketer. And 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 kind of took that step to try to push more volumes out?
Well, I think and I've been advocating 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 massive, they got such different load factors, especially in the off seasons, you're not going to get away from the volatility. And it's easy to kind of blame the volatility on maintenance or on cuts, but volatility has come because there's more supply going after a limited market. So I've been we have in the last year, we have sold about 1,000,000,000 cubic feet a day of more delivery capacity if people wanted to get out of our system either through the kind of the west going down GTN or out east on the mainline.
And I still think we need more. I think people have to now start thinking about their portfolio differently than they used to. No longer you just dump it in net and expect this could be a premium market. I think right now you're going to think about producing in net and what portion is going to leave and what portion is 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. And I'm expecting that to work with them over the next couple of years and move it out. So I think any incremental comes along, we'll have to find some delivery service for.
Yes. Pat Kenny, National Bank. A related question on NGTL, but just with the rate base going up 50% or so over the next few years. Just a few weeks ago, we saw the 2nd largest natural gas producer in Canada say that it doesn't make sense to grow their natural gas volumes at 2.50 AECO or less. So 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?
So couple of points I'll make on that. One is they're really speaking to they're not going to produce into the net market because they think the net market 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 tools fall.
Our interim tools right now for on NGTL for next year that we've already filed have shown depending upon where you are, a decrease, overall average decrease, but depending where you are because we have floors and ceilings, you might have seen locally, you might have seen some increases in some parts of the system. But overall, on average, it's been a fall. So I don't think yet because we've seen supply back up the expansions, I don't think we've seen it actually adds to the tariffs. It's actually gone the other way. So I don't think that's the immediate issue with producers.
I think the immediate issue of 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 Abramson, Morgan Stanley. Just wondering if you could talk about Mexico a little bit, elaborate on the permitting process down there. You 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 in
the background.
So Mexico, is no free ride anywhere unfortunately. In Mexico, you go in, it's just hard to get a permit in Mexico as it is right now in Canada and bystander. So we kind of we have good of share clauses. If they don't get it to us by the time we get relief from our contract and different provisions. So we still it doesn't it's 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 could be successful in their consultations. And consultation is a consensus, what is consensus? That's some of this debated every day in Mexico just like it's debated in Canada. What is the end goal of consultation?
But just to give you an example, right now on top of Bombo, we had the Raquiche group that didn't want the pipeline going through there. And we finally gave up waiting and we routed around them. And that's how we got around that particular issue. So on to the with this one, we will only wait so long. We do see progress by the way, which is why we haven't moved to reroute.
We have seen progress, but it does delay the project. At least a section of it, when you take a look at 2, you got section in the City of Mexico that actually can be used. So we get that in service. You got section around the coast, it can be used. It's the middle part that actually we have the consultations.
And so 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.
Thank you. Carl, just continuing on Specifically, how much did that factor into the decision Specifically, how much did that factor into the decision to keep 100% of Mexico?
Yes. I don't know if that factored in the decision to keep 100% of Mexico. I think other things factor into our ability. When we took a look at it, our ability to actually continue to finance this internally, the discounts we're 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're selling it, I was kind of I was not happy that nobody was given 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 dollar we get, we get to keep. Is it going to be like getting another huge investment? Probably not. This is all kind of on the margin sort of stuff.
But I think we can actually 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. So I'm not sitting here and speculate on how much money we can pull out of it, but I do note that nobody uses gas. And that's over time, we will find a way to make sure that gas is a preferred fuel. And over time we will find a way to make sure gas gets in that process heat there. But it's I can't give you a number right now.
Actually I don't have it. And if I did, it would be speculative anyway. So it would be I have a marketing group kind of doing some analytics for me, telling me what they can do, but they're looking for funding. I'm not going to share that with other people just yet until we see some proof in it.
I think, again, as we've highlighted before, management's around all morning, so 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. And then he'd be prepared to take your questions as well.
Thank you, Dave. Good morning, everyone. I appreciate the growth story. It's a growth story. And my hope is that after I finish my remarks over the next 20 minutes or so, you'll share the enthusiasm that I had, 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 5 50 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 and we touch about 1 in every 5 molecules of gas that's delivered across the United States. Our assets are strategically connected to 2 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. And then I'd ask you to think about our pipeline systems like GTN and Northern Border and Great Lakes as conduits markets, but LNG off take 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, MLP.
2017 was a pretty busy year for the U. S. Pipeline group. Good news, the Columbia integration is now behind us. If you recall with respect to synergy capture, we had a target of $250,000,000 of synergies, dollars 100,000,000 of which was finance synergies that were undertaken earlier in the year and then we had a target of taking out about $150,000,000 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 and that our growth projects are starting to go in service and rain express and our Gibraltar projects were placed into service earlier this month and in very early January, we're going to place our Leach X project 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 comeback provision on Great Lakes is not required for 5 years, so summer of 2022 give or take, and on the northern border system a comeback is not provided required until 6 years, which would be very early in 20 24. We are about to finish at the end of this year, Phase 1 of
Columbia's modernization program, which in
the aggregate was a the modernization program, which will span from 2018 through 2020. That in of itself will
be a
$1,100,000,000 investment opportunity. And for the first time, 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 $8,500,000,000 We completed 2 drop downs with respect to our LP and 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.
And 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. Carl'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 OE 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.
So 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 A and R Southeast mainline and then to the right is have 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 particulated system and you could also hear references to that as a TECO from time to time, The leg that extends in a southwesterly direction down to the Gulf Coast is the Columbia Gulf system.
Now 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 1,000,000,000 of dollars 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 Columbia system is around 9 years. You'll hear references quite frequently to TECO pool. TECO 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. And you'll see that a majority of the 8 $500,000,000 backlog that we have is tied up on the Columbia assets either on the Columbia Gas or the Columbia Gulf System and 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. And you could think of an average contract term of about 10 point 9 years, so just under 11 years. Significant provider of storage services predominantly in the Michigan area And big success for us in 2016 was the culmination of the ANR rate case. All things equal generated an uptick in EBITDA of about $82,000,000 and had its own unique modernization program in a way, a program that provided for additional maintenance capital expenditures to the tune of $837,000,000 to be spent over a 3 year period, but it also provided for recovery of those dollars effective day 1 in August some Mar some Marcellus and Utica growth on the ANR system, recently writing 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 recs interconnected Fairfield or at our Westrick 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. Nixie ANR also provides key interconnects to the Carls system in Canada via the Great Lakes system as well. With respect to growth opportunities, again predominantly on the Columbia system, you see our backlog here has grown to about $8,500,000,000 I thought I'd take a few seconds and just walk you through a couple of these. Our RAIN Express and Gibraltar Express projects, roughly $700,000,000 of capital were placed into service earlier this year. Our modernization I proceedings, as I mentioned, will culminate here on December 31st with a $1,500,000,000 cumulative investment.
Cumulative investment. Leach Express is our first big project that will go into service in very early January of 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 in service here in the next couple of days. There's one spread, which is spread 1, which we refer to as our mountain spread that during late October, or 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 and we weren't able to recover from those pipeline slips and get the project in as early as we like.
So very, 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 will take care of over the Christmas holidays and then get this in the ground with all due haste. A Cameron access project is one 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 Q1 of 2018, although the terminal itself is going to be delayed into much later in 2018. Very excited excited that we recently received our WB Express 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. And 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 2 slippage on the eastern in service state, but that will not be material.
Big project that we're waiting for a FERC order next is our Mountaineer Express and our Gulf Express project. Mountaineer Express $2,600,000,000 Gulf Express $600,000,000 again Expecting 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 expectation of receiving an order by year's end. I think that there's a potential for that to slip into early January. But 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 2, again, a great opportunity for us to spend $1,100,000 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 Express is our latest project out of the Appalachian Basin, which I'm going to talk about in more detail in a second. And then 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 $400,000,000 worth of other projects.
So when you think about it in the context of rate base, rate base across all of our assets today is somewhere just north of $10,000,000,000 a little over $1,000,000,000 of that is held by the LP, but you could think of us as effectively doubling our rate base, dollars 9,000,000,000 worth of 9 LP assets today, dollars 8,500,000,000 more of assets going in the ground by this time next year, getting us to a total rate base of around $18,000,000,000 $19,000,000,000 That's pretty exciting growth. 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. And you could think of us as spending around 600 $1,000,000 in maintenance CapEx this year and then staying in that general zip code for the next several years. And you could think about maintenance capital falling into 1 of 2 categories. First is associated with reliability work that needs to be done to predominantly what the ANR maintenance capital work is for.
So I referenced earlier the additional 2 Bcf a day of contracts that we sold across the South East Mainline, the $837,000,000 that we'll be spending from 2016 to 2018 is to support those flows. And again, 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 class changes associated with pipeline encroachments. And you could quite simply think of pipeline encroachments as population centers, housing areas and like coming closer and closer to the pipeline, which all things equal means we either need to take a derate and reduce capacity, which doesn't make sense because in most cases we have excess demand for that capacity or do certain work to operate the system, which could include cutouts and replacing the pipes. So that will be a program that will be undertaken for the next 3 years or so.
When you look at EBITDA growth out of the U. S. Business in particular, it's pretty darn impressive, I think. So let me just walk you through the evolution. Go back to 2015 prior to the Columbia acquisition and the U.
S. Pipelines, TransCanada's U. S. Pipelines at that point in time earned around $700,000,000 of EBITDA. 2016, the Columbia acquisition went live on July 1, 2016.
So we only had a half year of earnings. But if you were to annualize Columbia for a full year of 2016, EBITDA for the U. S. Pipes would have been about 1.5 $1,000,000,000 so almost a doubling in and of itself with the Columbia acquisition from 2015. This year in 2017, we'll earn just north of $1,800,000,000 in EBITDA.
And what's exciting is once we cash flow and get the balance
of these projects in
projects that are underway today, 20 run rates just with the projects that are underway today is going to generate just under $3,000,000,000 of EBITDA. Those are U. S. Dollars. So again, just tremendous growth when you look at it, 2015, dollars 700,000,000 growing to almost $3,000,000,000 by the end of 2020.
So the question then becomes, what's next? Because we're not going to stop on our laurels just yet and we think that there is a whole host of opportunities out there. 1st 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 opportunity that I think is somewhat unique is our Buckeye Express forward. And one opportunity that I think is somewhat unique is our Buckeye Express project.
Buckeye Express 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 inches piece of pipe with a light size of 20 inches piece of pipe. It doesn't make sense for us to do that. So what we're going to do as part of the project is we're going to replace that 20 inches piece of pipe with a 36 inches piece of pipe. And that's going to match up with the 36 inches piece of pipe on Leach Express. It's going to debottleneck our system and create a 36 inches high pressure header all the way back effectively to Southwest Pennsylvania.
This gives us a first mover advantage, such that as that 40 Bcf, we're going to have 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 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 PNGTS 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're able to win the PNGTS expansion when others couldn't largely because ours was a compression only expansion. 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 LTFP 2 type deal that Carl 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.
And 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. So we see 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 Express project. What's unique about that is not only will we get additional capacity by upsizing the pipe from a 20 inches piece of pipe to a 36 inches piece pipe, we then have the opportunity to drop additional compression on top of that and create even more capacity over time.
So again, a very efficient, very environmentally friendly way of expanding capacity there. And then 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 and 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. So again, a lot going on with respect to the opportunity set in the U.
S, tremendous growth opportunities, particularly on the supply push side and 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 United States. So with that, I will pause and entertain any questions that you all may have.
Same, if you just raise your hands and we'll get a mic to you.
Thanks. It's Ted Durbin with Goldman Sachs. So Stan, we've historically thought of the returns on your U. S. Growth projects as sort of a 5 to 7 times EBITDA build multiple, even one with Columbia.
Are you still holding on to those returns overall for the portfolio? And then how do you think about the risk of this delay with Mountaineer and 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?
Yes. So let me back up and just give you some perspective. We did see some cost increases on Mountaineer to the tune of $600,000,000 in and of itself. And 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 often 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. So that was the main driver with respect to the cost increases predominantly on the Mountaineer Xpress project. Now good news is we do have cost sharing agreements with our customers where we share that cost increase on a fifty-fifty basis up to a predefined cap. And yes, to answer your question, when you look at our entire portfolio of projects, the $8,500,000,000 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 overruns than we obviously were prior.
With respect to the second part of your question and the confidence factor around Mountaineer Express and pushing the contractors. We have incorporated lessons learned from Leach Express and the terrain is very similar trigger is going to 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. But 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 Express. But again, if we get that order now, we believe that we have a really good chance of a service on time.
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. It's, 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. But 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. So 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. And 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 can withstand that rehearing scrutiny.
So again, I think it's more about just working the process. When you look at our projects, again, dollars 8,500,000,000 worth of projects, but only about 160 miles of greenfield builds. So most of our projects are in quarter expansions. And West Virginia and Pennsylvania, not in New York and New Jersey. So 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. It's Ben Pham, BMO Capital Markets. Just wondering on organic growth, GTN expansions, Colombia, etcetera. 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?
Yes, there's a couple of questions there. So 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 continued debottlenecking upstream. Carl knows better than I, but the WCSB is a basin that's constrained only by takeaway capacity. So 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
production growth growing from 25 Bcf
to 40 Bcf, look at the production growth growing from 25 Bcf to 40 Bcf, think of projects like our Mountaineer Express project, Mountain Valley, ACP and Navy Rover as subsuming or taking up the first 5 Bcf or 6 Bcf of that growth. So there's likely to be a little bit of a quiet period, if you will, during 2018, 2019. But then once you get into 2020, 2021, 2020 2, 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 region and without an export from the region.
Linda?
Thank you. I always like looking at maps and thinking about the long term. And I do see some blanks. I mean, you're not showing your Mexican pipes there, but and I realize you want to focus on your existing corridors because it's easier to build. But long term, how do you think about extending your reach into some of those you're looking for in terms of longevity.
Can you comment on how you're thinking long term?
Yes. So you noticed that Boyd 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. So think about it from this perspective, and we'll start with the obvious, Permian. Permian is likely to double in size, from 6 Bcf a day to double in size, from 6 Bcf a day to 10
to 12 Bcf a day
going forward over the next
5 to 7 years. There seems to be, room for at least 2 pipeline expansions out of the Permian, perhaps going east over to either Abu Dulce or Katy. The first in the 20 19, 20 20 timeframe and we think that there is probably 1 competitor pipeline that has a pretty good line on that all things equal. But we think the 2nd pipeline expansion out of the Permian is up for grabs. And there's probably 4 or 5 announced projects right now looking at that and we're quietly doing the same.
So 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. And what I mean by that is there are a lot of incumbents in trastate 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.
So we'll see where they go.
Okay. Thank you. And just if I may as a follow-up, your presentation is silent on your midstream gathering business, and I'm assuming that's for a reason. But 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?
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 constraint, materiality constraint. Our midstream business this year will kick off about $85,000,000 to $90,000,000 in EBITDA. Next year, it will grow to about $110,000,000 in EBITDA with the Gibraltar project. So we'll continue to compete for and win our fair share of the projects.
But again, the key is we're going to do it within our risk preferences and 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. And that's true whether it's a gathering or transmission type midstream project or processing type project.
Jeremy Tonet at JPMorgan. I was just wondering if you could touch on the outlook for Bison a bit more, kind of given the changing flows of gas since I was originally put into service?
Yes. Bison is 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. And 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. So 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. And one last quick question.
Thanks. I appreciate some of the color on the sort of, I guess, the revenue synergies with Buckeye Express and Portland Express. But 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? I mean, what could we see over the long run? Because that's something that we 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 A ANR and Columbia, right? The opportunity that most comes to my mind is the Crossroads system. I do think that there's an opportunity there to use Crossroads as a bridge to aggregate Marcellus and Utica volumes on the Columbia system and then perhaps move them over to ANR Southeast Mainline and that the Crossroads 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 not to spend $5,000,000 $10,000,000 or so to put interconnects in there to promote additional gas flows.
So I don't know that there is 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 Carlin and trying to make sure that we're maximizing expansions on the GTN or the Great Lakes system. Now keep in mind, these are systems where 5 or 6 years ago, we were mothballing compression and turning off compression because we didn't have enough flow to run them. So the synergies that I see are going to be more like a Buckeye Express 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, Dan. We'll at this point take a mid morning break. If I could, we're only a couple of minutes which is a good news. So we've got until 10:15. I'd ask for everybody to return at that point and we'll start back up again with Dean Paudrey and our Liquids Pipeline business.
Thanks, David. Good morning. Again, once again, Paul Miller sends his regrets for not being able to join us today, but I'm pleased with the opportunity to fill in 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. And 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 and it's fundamentally centered on market fundamentals. And our strategy at the highest level is all about connecting major sources of supply that have solid fundamentals behind them, 2 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 WCSP all the way down into key refining markets in the U. S. Midwest and 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 and we fully anticipate that that will continue for the foreseeable future. Those opportunities relate to expanding, increasing connectivity, attaching a new supply as 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. And that's fundamentally the 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, but 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 6,000,000 barrels of key refining end use market. And when you look at our capacity in the ground today, it is very, very highly contracted.
In Alberta, we gather crude from infrastructure in the Edmonton, Heartland, toehold in diluent infrastructure in the Edmonton to Heartland corridor. And 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 at Lower forty 8, when you look at our Gulf Coast line, sometimes we refer to that as the market link 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, but also in terms of meeting customer needs in the region. And again, while doing all of 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 $900,000,000 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.
I 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. And 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 Pico 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 based producers is among the most advanced and highly competitive and complex refining centers on the planet. And 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 scenario of plateauing global oil demand is that the world needs to find between now and the late 2030s something in the range of 36,000,000 barrels a day of new supply that doesn't exist today, needs to find it, needs to bring it online to deal with the treadmill of declines and then some modest growth. And 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. And the graphics that we're showing you here are base case prepared by IHS market. 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. So in this case, we'll be showing you some of the conclusions of IHS in the base case, which we subscribe to. And I should note that the base view of IHS roughly aligns with those of those other major forecasting houses. So let's start first with a view of global demand, which I've got on the screen right now. And 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 around 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's 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 and 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. So the IEA mid year a couple of months ago updated their year over year forecast something like 1,600,000 or 1,700,000 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. And 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. So let's 0 in for a moment moving from the total global picture and talk a little bit about heavy over that same timeframe. It's 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 9,500,000 barrels a day today, up to a level of around 12,000,000 barrels a day by the end of this forecast period.
So 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 and they make their decisions as a function of that view. So 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. And again, we've seen this trend recently.
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. So when you factor in 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 36,000,000 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. So 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 that the U.
S. Gulf Coast heavy refining market is fed entirely by a combination of Canadian supply and waterborne imports. And those waterborne imports have traditionally been from Latin America, primarily Mexico and Venezuela. And those 2 producing countries have of course experienced considerable decline in recent years as well publicized. IHS and TransCanada believes that will continue to be the case.
So as the graph on the right hand side of the slides illustrates over the last, call it 5 to 7 years, Canadian supply has started to make material inroads into this critical market. And 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. So 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. And of course, Canadian heavy supply growth is quite dominated by oil sands growth. And just to put a couple of numbers to the story, both the IHS and the CAP views are illustrated here on this slide.
So today, we have oil sands production somewhere in the range of 2,700,000 barrels a day. And again, over the
forecast horizon, depending if you
subscribe to the IHS view or cap view, we're going to get up to a level approaching 3,500,000 to 4,000,000 barrels a day. So 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 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. And as you know, on November 20, 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. And as Russ mentioned, we continue to analyze that decision. Last Friday on November 24, 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 20 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.
And as always, we're striving to understand their 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. And again, our interest was the interest expressed by the marketplace was indeed broad and was very encouraging. And 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. So 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 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, but 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. And just very
quickly at a high level, Grand Rapid and expansion fully permitted for 36 inches 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 sort of supply gathering dynamic within Alberta, about 2 thirds of the oil produced in the region gathers in Edmonton and about 3rd gathers at Hardisty. So 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 will be looking for various options for downstream market access within 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. But 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.
So 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 Market Link asset. Again, this is our sizable pipe from the Cushing Oklahoma storage and pipeline hub down to the U.
S. Gulf Coast. Apart from being a considerable part 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, Market Link has played an important role in this very critical and active corridor. So MarketLink is a key lever for us, both in terms of connecting again that Western Canadian crude down with the U.
S. Gulf, but also participating in myriad commercial pathway opportunities that include Cushing. And 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. So owning a critical asset like this in the middle of that pathway provides us tremendous flexibility. So market linked 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 story, looking out to 2020, the Liquids Pipelines business unit, we anticipate we'll be at an EBITDA level of about $1,500,000,000 This includes, again, our recently completed Grand Rapids and Northern Courier and our sanctioned white spruce pipeline being into service over this timeframe. So in a nutshell, for the Liquids Pipelines business unit, our focus remains on 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. And our goal quite simply over the next 5 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 7 years or so.
With that, I'll turn it over to questions.
Thanks, Dean. So again, we've got a few minutes for questions. So if you do have a question, just raise your hand and Stuart or Rondo will get a mic to you.
Faisal Khan with Citigroup. The recent news on the potential to reverse Capline, can you just talk about how that impacts the need for XL? Is it does it mean that you can expand more capacity from Steel City to Patoka? Or does it really compete with you head on over the long run?
Thanks. Yes. So 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, it 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.
And 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.
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?
Well, 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, but 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, I mean, our goal is to work our way through those 2 critical elements as quickly as we can.
And
just as a follow-up, my recollection in the last go around, there was a critical construction window you kind of had to hit by early summer. Is that still the case? And 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?
Yes. I don't know if Rusty had anything
to add on that. Yes.
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, then 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. But 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 is where the plan is to build it over 2 seasons and we'll align that best to how we can optimize the schedule when we get there based on when we get there. So at the current time, our thinking is still approximately 2 years to construct this plus or minus a bit based on that time of year that we actually get underway.
Hi. Rob 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're saying it was going to be about a US1 $1,000,000,000 project? And then secondly, how do you think about incremental capital out the door for the
project.
Well, I mean, clearly, I think we've provided some discussion around range of return expectation and CapEx around the project. And 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 and the financial prizes is quite clear. Again for us, we're going to be very diligent and thoughtful tolerance on risk that we have a high degree of confidence in. And then in terms of the cost, the $8,000,000,000 is that still in the ballpark and how do you think about the incremental capital you spent so far?
Yes, that is still in the ballpark. And then 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 around 20%, I believe in hand. So a good chunk of that $8,000,000,000 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 Johansen. Karl is going to provide you with an overview of our Energy business. And then again, Don will be up to conclude things with the financial outlook.
Thanks David. Let me start by talking a little bit about kind of what the changes we've made in this business over the last year and a half and kind of just kind of talk a little bit about kind of our commitment to this business. I know we made some pretty material changes, but I want to emphasize first that TransCanada is in this business for the long haul still. We consider this business to be key strategic to our rest of our businesses. For example, we do we acknowledge that our gas is used quite extensively in gas fired generation.
And we understand that environmental policies that may impact our other businesses, including the oil pipelines and the gas pipelines, generally manifests itself through experiments with regulation on electricity side. So we do consider this to be a very, very important business for us to stay in. We have cycled some assets to both pay for acquisition and just to cycle them out on a normal course as they became more valuable. But I would say that it is it's important to make note that we're in it for long term. I'd also point out that we've actually not only we cycled some assets, but we've actually made some pretty big commitments to this business over the last few year and a half as well, 2 years.
The Bruce nuclear refurbishment, really it goes out to it's a 40 year deal, goes out to 2060 and we're- we're on the verge of- commissioning our largest gas fired power plant- the napping- That we've that we've ever built so it's you know we both cycle the cycle the 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 co gen is in Alberta, which got a piece of merchant, but the main merchant piece of this business have been sold. That's U.
S. Northeast business and the coal PPAs of Alberta have been turned back to the government. So we are so so we have kind of put this business in a better in a better risk profile that we consider. It's a very very highly contracted now. And most of our new money is going into areas like the Bruce nuclear that is fully contracted.
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 it's still 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 were our earnings in the business remain strong even with the divestitures.
We'll be quickly back to about $1,000,000,000 of EBITDA in this business. We've had significant work investing in Napanee. In Napanee, we're still planning on bringing that online next year, and we look forward to commissioning it. The sales of the US 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 end of this year.
And significant progress has been made in the first power refurbishment. I'll talk about a little bit later, but it is the first refurbishment is June 6 and Bruce Power and pretty much all hands on deck getting that ready for a smart major 1st, 1st major component replacement. The Ontario solar sale allowed us to serve us good value for our shareholders. If you think about this, this particular business represented about 1.5 percent of our megawatts in our business and we got $540,000,000 for it. So it's a significant capital rotation in this portfolio.
And it 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 proceeds you can get from it actually are better than your home value, it just makes good disciplined effort to cycle it. So when we did sell it, the initial thought was that we would cycle it because just the economics, it did fit in well with our capital plan right now. But really, we sold that just because it was worth more than our hold value. And 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. So 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?
Well, this is an interesting graph. And 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 and 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. And that's really because of the capital stock is 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 just moving off coal because gas is actually more economic in some cases. And it's moving off coal because it's getting regulated out of the coal business.
And what's coming in behind that is both gas, wind and solar. So renewables and gas are still are playing in that space. And we see this going on for quite a while. This is 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. And 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 very, very important market for us right now. The Ontario long term energy plan, we want to talk about that for a couple of real key reasons. Number 1 is it came about and big support of nuclear, which is very important to us given that we have a contract to refurbish nuclear until that contract runs right until 20 60s.
So we got good, good support again for this nuclear and I would add that even the opposition parties in Ontario have come out supporting nuclear. So we feel really good about our position in the nuclear and we feel really good move going in this first refurbishment that there is support there. But what else does that document say? The document also says that gas is still is still a preferred is still a preferred fuel. It's recognized that the renewables can't run without it and recognize it's going to be needed for the future of the grid.
So that's important. And 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, you start and you start looking at this graph just kind of the decline in it. When you get the nuclear refurbishment going, you get units taken off from nuclear refurbishments and then and you start to retire with Pickering and you have Darlington and Bruce with nuclear plants down, there's actually a gap in the resources, which means a couple of things. Number 1 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 baseload on nuclear off, they'll probably need some sort of baseload product on there. But 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 plans to stay
in useful life after the contracts. And now
our contracts don't end until the end start until the end of the cycle. But 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 in, there's more market for it. But more importantly, there'll be another opportunity in this market to build some capacity. Getting into kind of our actual assets and 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. Yes, we will we're still predicting it will be in 2018. So hopefully by the time we have this next year, it will be leasing 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. So 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 7 years later and we're almost finished to finish the plant now. It's not in Oakville anymore. But it is the planted that ultimately get built and we will actually see you can not only see our investment materialize for ourselves, but the citizens of Ontario will actually get the opportunity to to to to crystallize the megawatt hours for that expense that they spent on it. This is, I guess, $1,100,000,000 project.
And then I would say right now, when I look at it, it, it's pretty much on budget. And certainly on time, we're going to be we're still planning on bringing in before the date of the contract, which is December next year. And hopefully, we can get in a little earlier. Talk a little bit about Bruce. The Bruce is all right now is all about what are we 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.
This is the Bruce Power contract and this new amended restated contract that we signed in 2015 was an important 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. So 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, the guaranteed return that comes out of this plan. And it is also it also gives us an opportunity to refurbish the 6 units that we haven't refurbished ready.
It is we're going to do one at a time. I'll show you scheduled here shortly. But really, the essence of this contract, when these units go into refurbishment, we don't lose the revenue per se on these units. We are to be the entire price of all of the rest of our units of all the rest of our megawatts will increase. And the basic theory behind that was that TransCanada was just not up to doing a system replacement where every time the unit went down, we didn't get paid for that unit for the 4 years it was down.
So we had to come up with a mechanism by which we got the revenue during that period of ownership. We've had this is for the complicated agreement, but it's a good agreement that way. You will see the revenue fluctuate depending upon availability general availability of the plant. But and that's the way that we've set it up. The government wanted us to be incented to Kate that to make this plant as high and low 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 the share in that money with the ISO. And 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 year.
Now as we get closer to 2020, when the unit goes into service, we'll be able to give you 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 of the government. We believe that the price will be fine. It will fall in within the band that we gave them and we'll get to go ahead and at that time we can give you guidance as to what the impact that will have on our per megawatt hour price.
And 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. Now this particular, I have a video here and it's from Bruce Power. And I thought I would just show it to everybody. I thought it was good video, it could give pretty good explanation of Bruce Power. So it's about 3 minutes.
So maybe if I could turn it
over and
If I can get back to you. Just to give you an idea kind of what we're planning on the unit, the major component replacement. There's really 2 parts to the refurbishment. 1 is the asset management program. And that's the non kind of 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 can do it during the regular outage or we can just do it during its operating time. That's the asset management. The major component replacements when we actually take it down and that's what you're seeing right here.
That's when you actually do the corn nuclear part of the refurbishment when you take it down. And as you can see, it can last up to 4 years to rebuild that unit. The question I get on this quite often is, what makes us think that we can this is going to be better than Units 1 and 2? And I imagine 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. And if you recall, the cost went over.
The time was probably a year and a half to 2 years over as well. And it was very, very difficult refurbishment. But 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 they go over the learnings that we learned from the 1 and 2 refurbishment to make sure we didn't, we didn't, we don't repeat those errors. Second thing is that these units are completely different. US 12 were shut down in one 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. And I think that's the biggest difference right now that we are familiar with these units operate today. Everything that is know about them, we already know.
And that wasn't the case of 102. I want to be down for so long. 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 and we started construction for engineering and all the stuff that you do when you're under time pressure. Here with our asset management program and our major component placement, we got the time beforehand to do it right. Make sure all the engineers done, make sure the price is completely thought out before we submitted. And then 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. And last thing is it gives us actually, 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 around there so we can use these learnings. So 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 our to submitting Unit 6 this time next year and we'll see how that we'll see how that I'm quite certain we're going to get it under the dollar value that Dice was looking for. So I'm pretty certain next year I'll be up here talking to you about kind of what that looks like and how we're moving forward. So The Alberta Power assets, we're watching closely. We have some very good coach ends there. As I said, there's a merchant component to them, but we have very, 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, but 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, we're in of course, we had some very good years in Alberta. We always advocated for a more contracted market, a capacity market.
And the government is starting to talk about that now. We're fully engaged in it and we'll see if it's if they're able to come out the construct that it will fit our risk preferences and go forward. We have participated through partners in the initial wind auction. We'll see how that goes. But for anything more material right now, we want to see where the market where the market goes for.
There is some upside in Alberta with the coal being legislated. I got a little graph here that shows kind of what's going to happen. It's There isn't a need for more resources there. And with a properly structured market with proper contracts, I think we can participate both in the renewable section of that and in the base load that they're going to need. So we'll see how that goes.
We're monitoring it closely. If we don't get a if we do not get a market structure there that we're comfortable to our risk preferences, we have lots of scope that we can redeploy our capital elsewhere. So it's not a need to be there, but it is our home market. We actually know quite a lot about it. And we're hoping that we can work closely with the government put something in place that will work with our risk profile.
What's the evidence? I did 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 is bouncing back there. So it is still 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, very large business by Canadian standards for non government owned power businesses. And just to finish it off, what's our key focus? Well, we got to maximize the value of our existing assets. We got to get nappening up and running on time and on budget.
We got to get Bruce we got to get Bruce through the life extension program. And we have good teams working on both of them. And we're going to keep pursuing our growth through appropriate transactions in areas that are in our core geographies. So we will be active in Alberta if the construct is right. We will be active on the renewables.
And we'll again, we have a big core area here in Ontario which will be active as well. And 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, but you were taking cash out of the pipelines business that was earning sub-ten percent returns and deploying that into the contracted power side,
kind
of with the look and feel of regulated. With your gas outlook improving in 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? It a platform that you do want to grow significantly if you can find the contracted side or should we be thinking about it as potential asset sale proceeds to fund the capital
plan? It's a good question. You're absolutely right in the early in the century here, I guess. It was a great outlet for surplus cash coming off of the gas pipeline system in particular. And we're able to redeploy that cash and it's a pretty high they're quite merchanty.
We had a different risk profile at that time, but much higher returns. And 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. So we're just not going to go there and do the same type of merchant type of 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 that 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.
So we've been you can see with the solar sale, just the value that we brought out of that, that it's suggesting that today's time is maybe not to be investments, maybe to be cycling some capital. So 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 makes 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, in the long run-in the energy sector that keeps us in this business and keeps us within our risk profiles. But you probably won't see us go back to you probably won't see us buy Ravenswood again. Ravenswood like asset. You may have some people may smile about that. I know it was controversial, but it's just that's just not within our risk preferences anymore and you won't see that.
So anything we do, we do, you'll see it look much different than we used to.
And 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 3 year forward look both
in New England and PJM.
Do you
think Alberta is going somewhere different than a roughly 3 year forward look or is that really a market for longer term renewables for
you? Good question. So I think the renewables are going to be handled differently than the Power Pool in Alberta. But, you know, the discussion isn't finished yet. So I'll just caveat by saying, you know, these are just just feelings, observations we're making.
But and they're not surprising. The ISO, the people buying the power would like to see a shorter duration capacity market than the people selling the power. And 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 want to if they do go down that road, you'll probably see us in the sidelines deploying our money elsewhere. If they do go down the road with the longer term contractual coverage for it, then we'll be interested in. And that's basically the message we're leaving them right now is that if you construct it certain ways will be there.
If you construct it differently, we will not. And then we're being quite clear with
them. Linda?
Thanks, David. I just wanted to follow-up, Karl, with a comment you made about going along or being along or interested in other parts of the energy value chain. I mean, clearly, you're commenting on your natural gas transmission. But maybe 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?
And 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, we'll certainly we take
a look at those businesses
company, a gas company right now that has maybe 200 customers and making a transition to 2,000,000 and 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 the 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 other use we have in our capital that wouldn't make sense.
So you'll stay tuned if the valuations that were moderating in those sectors, I do think they fit our risk preferences and they would want to look from us, because we are I think we are good at regulated type businesses, but not at these valuations. These valuations, quite frankly, we got better 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 and then we'll turn it over to Don.
You talk about pursuing growth in contracted power infrastructure, right? So I'm assuming you're going to do that in the United States as well. Can you talk about some of the competitive dynamics when you go for contracted power infrastructure in those markets?
Please? Yes. We're so first of all, we're going to look at opportunities within our footprint. So right now, that means Alberta, Ontario, Arizona. Arizona has had lots of competitions for peaking plants and solar plants and so forth coming out as well lately.
And so right now, that's where we're looking for. If we were to step out to different area, and which we might, it would have to be an area that we're still familiar in. So we would maybe an area where we have pipeline infrastructure, but not electricity infrastructure. So we I doubt you'll see us in a place where we don't have any infrastructure at all. There's all in California always calls such a big place with large but we've got no infrastructure there.
We have no it just doesn't make sense for us to start figuring out California regulatory and whatnot. So I think our priorities will be, 1st, where our power plants are second, where our other infrastructure is. And if we do if we have 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. And but my suspicion is that we'll be able to keep this $1,000,000,000 EBITDA growing modestly through this period of time.
And then as more capital becomes available or as valuations on some of the renewables and or even some of the other regulated businesses start moderating, but we can start adding any more material. But right now, we're going to stick pretty close to home on it.
Great. Thanks, Carl. Again, Carl will be available through lunch if you've got any further questions. But with that, we'll turn it over to Don Marchand, our Chief Financial Officer. Don is 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 meaning by next Investor Day. So this is my 7th Investor Day. It seems we oscillate back and forth from what are you going to do with all the money to how you're going to get all the money and there's elements of both of that this year here.
Spend the next 20 minutes or so going over 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 3 or 4 years look like. Here, there'll be a lot of numbers. I'll try not to sound like an auctioneer going through them too quickly here. A few key assumptions embedded in the presentation here. Everything is in Canadian dollars unless I mentioned otherwise.
We are using a 1.30 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 percent per annum on gross PPA PP and E. So 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 regulatory franchises and very driving long life low variability cash flows. And by long term contracts, we generally mean 20 or 25 years, not 3, 5 or 7 years. So it's a very long life cash flows.
We finance that with long term capital. It's a fairly simple model. You lock in your revenues, you lock in your biggest input cost, cost of money, capture that spread, repeat, repeat, repeat over growing asset base. We have about $22,000,000,000 of book equity, dollars 4,000,000,000 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 1st 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 to the ability to act under virtually all conditions.
We saw that actually during the global financial crisis when we continue 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're 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 percent 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, but generally keep it very simple. I'll 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've had really de minimis credit counterparty losses here over the past 10 or 15 years, and that's 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. We brought approximately we will by the end of the year have brought $5,600,000,000 of assets into service. The biggest components would be NGTL.
Our 2 liquids pipelines in Alberta as well as probably $1,000,000,000 plus in the United States including rain, rain express in Gibraltar. We also added $3,000,000,000 of new assets. The biggest component was NGTL with an additional $2,000,000,000 added to the growth portfolio. And another $1,000,000,000 in the likes Buckeye Express, Portland Express and on the Canadian Mainline. As Stan mentioned earlier, we're we've declared ourselves successfully track to capture the 2 $50,000,000 per year of targeted synergies.
Those are U. S. Dollars. We got the U. S.
Northeast power assets sold and retired balance of the Columbia Bridge loan in the Q2 of this year. We bought in Columbia Pipeline Partners for US920 $1,000,000 back in February, gave us full control of the Columbia assets. And again, consistent with keeping our structure simple, have no duplicate of LPs in our portfolio. I'll go over the funding that we completed this year. It's about $13,000,000,000 It was a fairly ambitious year in that front.
That will be on the next slide here. And 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. But 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 is merchant. We've added Colombia, give us an given some incumbency position in the Appalachian and we brought about $9,000,000,000 of loans 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 $15,000,000,000 of subordinated capital to the balance sheet, dollars 9,000,000 of which was common, about $5,000,000,000 is in the form of hybrids and $1,500,000,000 of preferred.
So 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's a fairly heavy lift this year, about $20,000,000,000 was required. Capital program will come in around C9.5 billion dollars We bought in CPPL, as I mentioned, C1.2 billion dollars paid about CAD2.5 billion of dividends and distributions to our LP, refinanced CAD1.7 billion of maturities and repaid a $4,000,000,000 U.
S. Columbia Bridge loan. In the middle box, we generated about 6.4 $1,000,000,000 internally, funds from operations, probably around $5,600,000,000 and raised about 800,000,000 dollars under our DRIP program at a 2% discount there, seeing about 35%, 36% participation on that front right now. So that left about $13,500,000,000 to raise. And as you can see on the far right hand bars, a fairly diverse, in some cases innovative, fairly attractive set of financings on that front.
So about $3,500,000,000 came from senior debt. That included our proportion of Bruce's debt funding as well as some commercial paper draws and cash on hand. But we did, on TransCanada's balance sheet, raise about $2,600,000,000 of term debt, average term 10 years average coupon 2.7 percent pretax. We raised $3,500,000,000 equivalent of hybrids. These are 60 year non call supported instruments that we achieved 50% equity credit from the credit rating agencies on this product.
We raised $1,500,000,000 in the U. S. Market earlier in the year at a coupon of 5.3%. And we did the inaugural Canadian hybrid as well for about CAD1 1,500,000,000 at a pretax coupon of 4.65 percent. The order book was approaching CAD4 1,000,000,000 on that specific deal.
Moving top of the box here, about US3.1 billion dollars raised in the sale of the U. S. Northeast power assets and the other US2.3 billion dollars in the purple box was made up of a series of transactions including the pending sale of our solar assets for $540,000,000 that should close by the end of the year. We received $600,000,000 back from Progress Energy Petronas at the cancellation of the PRGT project that occurred in October. We did a $765,000,000 drop down to our LP back in June.
And 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, but I think it's reasonably new to Canada here. We filed for CAD1 1,000,000,000 just under 2% of our float. That's good for the next 25 months.
And 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. We 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 24 $1,000,000,000 of growth and effectively deleveraging at the same time.
So it is a balancing act right now and this is an important tool for us as we do that. So we'll on our Q3 call, we indicated we had not yet issued under that. We will issue some ATM here in the Q4 and we'll report the extent of that when we report Q4 results in February. We do reiterate that there is no need in our view, for discrete common equity to complete the $24,000,000,000 program underway right now. So 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 CAD24.5 billion. The biggest components would be U. S. U.
S. Gas at about CAD11 billion and Canadian Gas at CAD8 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's essentially all regulated mid sized projects with what we would describe as normal small to midsize projects with what we would describe as normal course permitting and construction. It's fairly compressed time frame to complete complete these.
The vast majority of these projects are in service and cash flowing by the start of gas year, November 1, 20 Holistically, on time, on budget, we have a few ahead of time, ahead of budget, a few that are lagging. But holistically, we would describe it as on time, on budget. And 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, and this slide captures what we see as about $5,000,000,000 in maintenance capital over the upcoming 3 years here.
There's 2 principal trends here as have been talked about. Number 1, 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. So the dollars are up.
The second major trend is the recoverability of maintenance capital. So it's de facto growth capital and that we earn a return on and of this capital as it is invested. So it does actually contribute to earnings power. So again, dollars 5,000,000,000 is what we expect in maintenance capital through the 'eighteen, 'nineteen, 'twenty timeframe. In Canada, it's about $1,800,000,000 This has historically been immediately reflected in rate base under Canadian regulation.
We have about US700 $1,000,000 for ANR in this timeframe. That includes the tail end of the US837 million dollars 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 $1,200,000,000 for Colombia, which we fully expect to recover in a rate case in 2022 onward there. And 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. So when you add it all up, our capital spending over the next 3 years is just under $18,000,000,000 about $17,800,000,000 in total.
Dollars 12,500,000,000 of that is to complete the $24,000,000,000 growth program underway, dollars 5,000,000,000 for maintenance capital and about 300,000,000 dollars for capitalized interest over this time frame. We do allude to development costs in here on the long tail projects, but I would describe them as more of a rounding error. So the observations here, the program is heavily concentrated in 2018, dollars 9,200,000,000 that is largely consistent with the $9,500,000 that we'll spend this year. So another heavy lift coming up in 2018, but something we view eminently manageable. The maintenance capital side, probably about 85%, dollars 4,300,000,000 is what we would consider recoverable and defacto growth capital.
The capitalized interest, of course, excludes Energy East and PRGT, which we've exited. And as I mentioned, the development costs are minor in this timeframe. So how are we going to pay for all this? This is the funding program through 2020 over the next 3 years, again moving left to right. CapEx about $17,800,000,000 We expect to pay dividends and distributions to our LP unitholders of probably about $9,750,000,000 That's including dividends at the upper end of the 8% to 10% growth range here over that time frame.
So total need of about 27,500,000,000 dollars In the middle box, we expect funds from operations to be just north of 20,000,000,000 excess of CapEx over this timeframe. And we do have the dividend reinvestment program running through the end of 20 18 at a 35% participation rate here. At present, given again the magnitude of the capital for the time being. It is not a permanent feature of our capital raising is to have this thing that's on forever. We did have the dividend reinvestment plan off during the 2011 to 2016 timeframe.
So we will turn it off at the appropriate time recognizing its dilutive effect here. So on the far right hand side, we have a capital markets need of about $6,500,000,000 to $6,750,000,000 That's aside from refinancing maturities, which I'll touch on in the next slide. About $2,900,000,000 just under $3,000,000,000 of that will come from incremental senior debt. And that's within the constraints of our A grade credit metrics. About $2,000,000,000 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. And $1,700,000,000 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 2017. We never give a specific cadence for that, but 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 US1 $1,000,000,000 a year of assets, and 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 an ATM is appropriate. Again, no need for discrete equity for the $24,000,000,000 that is underway right now. Debt maturities over the next few years here, about US5.25 billion dollars and about US500 million dollars This includes Colombia debt assumed of about 1 point $250,000,000 so a little higher than normal, but that is with Colombia 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 as well going forward.
We are in the process of renewing our shelf as well going forward. We're in the process of renewing our shelf facilities, 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 $9,000,000,000 of committed bank lines with a group of 20 long term relationship banks and 3 commercial paper programs that allow us pretty attractive funding. We're funding at about LIBOR plus 20 basis points right now. So this is the prize going forward. We see EBITDA growing from $5,900,000,000 in 20 15, dollars 6,600,000,000 in 2016, about $7,300,000,000 this year, up to about $9,500,000,000 in 2020. This assumes we complete the $24,000,000,000 growth program, 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 $200,000,000 from the sale of the liquids assets. The biggest growth from gas pipes in Canada here and about CAD300,000,000 from energy as Napanee and Bruce contribute more there. So just spend a few minutes here on DCF coverages in a couple of 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. A couple of observations. First, we still believe earnings matter. DCF is a supplemental measure as we assess our financial distributable cash flows, cash available to common for capital allocation and it is derived as comparable funds from operations excluding working capital movements, less payments to non controlling interest, mainly LP distributions, less maintenance capital. Now 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. So we've included 2 ways of looking at DCF coverage here. 1 is fully loading all maintenance capital, regardless of whether it's recoverable or not. That gives you fairly healthy coverages of 1.5x to 1.8x over this timeframe. But reflecting only non recoverable working sorry, maintenance capital, you end up with coverages in the 2.1x to 2.3x range over this timeframe.
So 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 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, the sale that number is about 55%, but that number has grown substantially and will continue to grow going forward. We naturally hedge that with about US24 $1,000,000,000 of debt and hybrid securities and the associated interest expense that comes with that. That leaves us structurally long about $1,000,000,000 a year after tax going forward here.
And we actively hedge that on a rolling 4 quarter basis to give us some predictability and smooth things out. For context here, the currency that we achieved post hedging programs is exchanger is about $131,000,000 in 2016. We're fully hedged at $130,000,000 this year and we're largely hedged at $1.30 next year. In terms of sensitivity to currency, through 2018 given our hedge position about it take about a $0.10 move in the Canadian U. S.
Dollar to impact earnings by a penny going forward excluding active hedges. It's about penny for penny in the post-twenty 18 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 hybrid final maturity. Significant element of our interest expense is flow through to 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. And 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 and 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 as seeing Great Lakes contract back up again here. So you can see the mix here, about 61% is NEB FERC regulated pipes, 34% is long term contracted assets and we've got 3% in here for commodity exposed businesses. But when you carve out the Northeast U.
S. Power business this year, that's probably closer to 1%. And then about 2% is volumetrically exposed and that is really Keystone South of Cushing where there is spare capacity I think, in homage to my roots, I described this as a Saskatchewan earnings cliff a couple of years ago. So this is our EBITDA look out to 2025. And what we meant 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.
So again, this assumes $24,000,000,000 of capital under the current program is completed and normal course U. S. Pipe recontracting. And we do have a visible $9,000,000,000 of EBITDA effectively locked in, in 20 25 at this point and another $500,000,000 that we would describe as variable, which again is really keystone EBITDA south of Cushing right now under the Market Link 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 5 different platforms in gas oil pipes, Canada, U. S, Mexico and the energy business. We've managed to find $75,000,000,000 of stuff to do since the year 2000. So 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 8 grade credit rating metrics. So with the backdrop of the base business performing well, visible growth here over the next few years, healthy coverage ratios, a solid opportunity set in the financial capacity to pursue that.
We again reaffirm dividend growth at the upper end of the 8% to 10% range through the end of the decade and as well extend that 8% to 10% range to 2021. 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. So 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 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 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. So with that, I will stop there and invite any questions you might have.
Sorry, just back there,
Stuart. And
then after that, Andrew, I saw Andrew's hand.
Yes, Don, just wondering as you look towards 2020 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 5,000,000,000 dollars a year would be my thumb in the air number. And a portion of that would probably be spoken for with maintenance capital that is recoverable, but something in that neighborhood about $5,000,000,000 a year.
Andrew?
Andrew Kasky, Credit Suisse. Don, when you think about the competitive positioning of the company overall is you're deleveraging 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 and then also deploying capital through the network. And 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?
I wouldn't it's probably a bit of both, to be honest. We're not going to in terms of improving the returns on what we have, we are it's fairly basic. We're chasing fairly low risk stuff that's in a fairly low band of return profile. So 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. So 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 $100,000,000,000 asset base will spin off a significant amount of organic opportunity going forward. And if we can land 1 or 2 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 then it's worth a lot. And that tends to show itself when it then it's worth a lot. And that tends to show itself when there is stress in the marketplace, but we're not going 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.
And then 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? Two
questions on maintenance CapEx. On the $500,000,000 increase from loss disclosure a year, can you comment on the extent to which integrity spend is driving that versus the reallocation of growth to maintenance? And then secondly, on post-twenty 20, assuming modernization spending is starting to decline, wouldn't you expect pretty big decline in maintenance CapEx and big increase in coverage ratios?
Yes. So the first part of the question in terms of the $500,000,000 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. So there's really no significant migration between those two color coatings 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 amount of gas coming through the system WCSB in Appalachian that the assets would continue to sweat fairly hard over that time frame. So that's what comes with that. Could there be some dissipation of that? Yes, there could, but we don't see gas flows declining substantially such that the workload on the assets would decline materially.
So it's early days on that, but I don't know. In terms of a modernization, the modernization program at Columbia Modernization 12, that was de facto growth capital, color coded, not maintenance capital. So could there be a Modernization 3 program? Yes, there could. But we don't have any clear line of sight to that at this point in time.
Thanks.
Just a couple of questions. In terms of keep 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?
Yes, the key metrics we're looking for are debt to EBITDA under 5x and FFO to debt in excess of 15%.
Okay. And that incorporates the upgrade in your business from the agencies since you've sold some of the power assets to?
Yes, we're starting from a fairly strong business position of credit rating agencies. So, it's there's probably not a lot more headroom to move up in terms of business position, but it's really on the quant side that we're we need to get to here and we'll hit those levels in 2018.
Okay. And last question is on the dividend. As you look out over the next few years of the growth rate, is there a target payout ratio you look at on EPS, earnings per share for the are you looking are you just targeting coverage ratio DCF? Yes, we'd
not specifically. What enters into our thinking here is and you can look back over history, we tend to pay out 80% to 90% of accounting earnings, which equates to about 40% of FFO. And you've seen depending how you define DCF coverage here, still very healthy coverage ratios. But those are three things we kind of look at here. As well as what is the growth pipeline going forward and the visibility to continue adding new projects.
Sorry, Robert.
Don, you've laid out the funding plan. 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 started looking at it as to most much of the KXL spend would be in 2019 2020, which is when we start having significant and growing capacity internally to fund new projects. So, and the fact that we do have significant amount of the long lead time items already purchased on on KXL would suggest that it will we'll avoid that to the extent we can, but turning on DRIP, extending ATMs, selling more assets, dropping more assets into the LP. We have a lot of tools to avoid discrete equity in that case. This is, when you generate a 9 +1000000000 of EBITDA a year and that's fairly healthy and it doesn't move around a whole lot depending on different economic conditions. So our hope would be the we watch share count very closely on this front here.
So not dodging the question, but it's hard to tell at this point, but we do have significant capacity in those years.
And I guess just given how much the story has been around highly visible growth from small to medium sized 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 in 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 KXO?
No, I think as Don said for $100,000,000,000 plus balance sheet here, we look at taking on a $7,000,000,000 or $8,000,000,000 project split over a 2 or 3 year period. It is doable. I think historically, we would have probably thought more about that. But we'll see when we get there, to Don's
point, is we look at everything
through the lens of per share value, we'll keep those things in mind. But right now, our plan is it doesn't include partners, but we never say never to things
that. Ted, just give us a sec.
So, just on the dividend again. So you're extending that by a year, the 8% to 10%. How do you think about the balance of that versus you are issuing equity on the DRIP? Talked about turning on the ATM. Why push the 8% to 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 to 10 is it's affordable. In our sense, it's valued by our shareholder base as long as we're being rational and not getting out ahead of ourselves. We would Our view is we will grow the dividend prudently and turn on the DRIP and give investors the opportunity to reinvest if into the stock at a modest discount versus just restraining dividend growth going forward. So we think it's a balancing act between those two things that is, in our view, appropriate.
And then maybe I could just play a question for you, Andrew 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 3rd party M and A?
I'll start and we're pretty full right now and we hope to fill up again here with organic stuff. So, 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, but it's not something we have to do. And so we'll bide our time on that front. Everyone has their wish list.
The stuff never comes up for sale, the really good stuff are very rarely. So when it does, it's quite often under strange circumstances you need to act quickly, but 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. And in the interest of time, we'll just 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.
So it's sort of close-up on the day. I 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 $86,000,000,000 of high quality assets, about 7,000 talented employees. And again, to put that in perspective, you think back to when TransCanada and Nova merged, we had more employees than that and the company is worth approximately $20,000,000,000 We've come a long ways. We have 5 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 $75,000,000,000 into low risk assets that generate predictable sustainable earnings, cash flow and support a strong and growing dividend. As we advance the $24,000,000,000 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 into our core businesses and into our core geographies. Today, we're advancing about $20,000,000,000 of larger scale projects, and we expect numerous other growth opportunities to emanate from our extensive asset footprint that we have today. So 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% to 10% range on an annual basis through 2020, and we foresee additional growth of 8% to 10% in 2021. And 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. So 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, are traveling home, you'll travel safe.