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TransCanada Corporation (NYSE:TRP)

2013 Investor Day Conference

November 19, 2013 8:00 am ET

Executives

David Moneta - Former Vice President of Investor Relations & Communications

Russell K. Girling - Chief Executive Officer, President and Director

Alexander J. Pourbaix - President of Energy and Oil Pipelines

Karl R. Johannson - Executive Vice-President and President of Natural Gas Pipelines

Donald R. Marchand - Chief Financial Officer and Executive Vice President

Analysts

Andrew M. Kuske - Crédit Suisse AG, Research Division

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Carl L. Kirst - BMO Capital Markets U.S.

Robert Kwan - RBC Capital Markets, LLC, Research Division

Linda Ezergailis - TD Securities Equity Research

Theodore Durbin - Goldman Sachs Group Inc., Research Division

Steven I. Paget - FirstEnergy Capital Corp., Research Division

Juan Plessis - Canaccord Genuity, Research Division

Paul Lechem - CIBC World Markets Inc., Research Division

Patrick Kenny - National Bank Financial, Inc., Research Division

Pierre Lacroix - Desjardins Securities Inc., Research Division

David Moneta

Great. Good morning, everyone, and welcome to TransCanada's 2013 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 and our industry overall. We intend to use this morning to provide you with some insights into the many initiatives that are underway that are expected to drive significant shareholder value in the years ahead. We hope to provide some insight both into the trends that will help shape the future of both Pipeline and Energy businesses as we move forward, as well as some of the challenges that we and others in our industry face.

We'll begin this morning with Russ Girling, our President and Chief Executive Officer. Russ will provide you with some comments on our vision, our progress over the past year, our priorities going forward and the business environment in which we operate. He'll be followed by Alex Pourbaix and Karl Johannson, who'll provide with an overview of things going on in our Oil Pipeline business, our Natural Gas Pipeline business and our Energy businesses. And finally, Don Marchand, our Chief Financial Officer, will close out this morning with a finance update.

Copies of the agenda and our presentations are included in your handout. For those of you who are listening via webcast this morning, a copy of the presentation material is available on our website, and it can be found in the Investor section under the heading Events and Presentations.

Following each presenter's prepared remarks this morning, we will provide you with an opportunity to ask questions. I would ask that you limit yourself to one question and a follow-up. Hopefully, that will provide everyone with an opportunity to have their questions answered.

Before we begin, I would like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on those risks and uncertainties, please see the reports filed by TransCanada with Canadian security regulators and with the U.S. Securities and Exchange Commission.

And finally, just a couple of comments on non-GAAP measures. We will make references this morning to comparable earnings per share, earnings before interest, taxes, depreciation and amortization or EBITDA, as well as funds generated from operations. These measures are used to provide you with additional information on our operating performance, liquidity and our ability to fund our capital program. However, they do not have any standardized meaning under U.S. GAAP and are therefore considered to be non-GAAP measures. As a result, they may not be comparable to similar measures used by other entities.

So with that, I'll turn the podium over to Russ Girling, our President and Chief Executive Officer, for his opening remarks.

Russell K. Girling

Thanks, David, and good morning, everybody, here today and joining us by webcast. We do appreciate you taking time off your schedule to join us and for your ongoing interest and support of our company. It's hard to believe that 12 months have passed since we were here last. And looking back on the last 12 months, I can tell you that we have accomplished a lot, and I'm very pleased with the progress of the company over the last 12 months. Over the next few hours, myself, the executive team, look forward to sharing with you some of those accomplishments over the last year, as well as some of the challenges that we faced and how we expect to move forward over the coming year.

In short, I guess what I would tell you is that our base business has performed very well through the first 9 months of this year despite continued ongoing challenges in some of our long-haul pipeline businesses in the U.S., a lack of storage spreads and those kinds of things. But still, despite those things, I think the resilience of our assets continues to shine through.

We successfully resolved a number of the issues that we're facing us 12 months ago. I remember I put up a slide last year that showed a number of challenges. We got through those. There are some that remain, and we continue to work on those, and I'll talk a little bit about that today. But in addition, we've also secured an unprecedented number of high-quality growth opportunities that I think will transform this company in the years ahead and places on a platform for continued growth for a number of decades. I'm confident the momentum that we've been able to build this year will continue and that we're very well positioned to continue to grow shareholder value in the years ahead.

So I plan this morning to spend the next 20 or 30 minutes giving you an outline of our vision and where we're going and how expect to achieve that. The rest of the team will fill in with the details here over the morning.

So to start with our vision, it's a vision that has remained essentially the same since about the year 2000. Our goal is to be America's leading -- North America's leading energy infrastructure company. We will focus on businesses that we know, and that is pipeline and power generation, in regions where we have or can build substantial competitive advantage. Our focus is on large-scale things, long-life assets, those that will provide stable and steady returns for our shareholders for decades, some 20, 30, 40. We've got assets in the Northeastern United States. Our hydro assets have been running for over 100 years. Our focus is on those long-life stable assets.

Since the year 2000, we have invested about $40 billion into the long-life energy infrastructure assets in our 3 core businesses, and I think we're well on our way to achieving that vision. That investment, this slide kind of outlines our performance over that period of time, has led to a significant increase in cash flow and earnings over the past 14 years, which has, in turn, resulted in an annual total shareholder return of about 15% since that year 2000.

Looking forward, as I said, I think we're well positioned to continue to deliver significant shareholder value through a combination of visible growth opportunities in all 3 of our core businesses and an attractive and a growing dividend. Before I highlight those opportunities that lie ahead, I'd like to spend a few minutes talking about the strong foundation that we have at this company and why we're confident that we'll continue to grow going forward. As I've said on numerous occasions and in front of you before, it is our assets and our people, along with the strong financial position, that will allow us to continue to grow, and it does separate us from the competition that's out there today.

So just to dive in, start with our assets. This map highlights, as you can see, that we're no longer just a Canadian gas pipeline company. And when I talk to people, they still refer to us sometimes as TCPL. But we're much more than a Canadian gas pipeline company. Today, we are one of the largest North American gas transmission companies, #1 or #2, depending on how you measure things. And we're the third largest storage operator in North America. As well, we are the largest private sector power company in Canada. Most people don't see us as being that. They look at the folks that -- or the private power companies as being the largest, but we have about 11,000 megawatts. And we've become a significant player in the oil transmission business with the startup of our Keystone Pipeline 3 years ago. With all the [indiscernible] about Keystone, some people forget that we actually have delivered about 500 million barrels to the U.S. already.

We have an enterprise value of about $60 billion. Today, we own interest in about 70,000 kilometers of natural gas pipeline system that move about 14 Bcf a day car or about 1/5 of the supply that moves in North America today. So 20% of the supply that moves in North America comes through our system. We have about 406 Bcf of gas storage facilities throughout North America. We have 20 power plants with a capacity of about 11,000 megawatts. And we have the Keystone Oil Pipeline system, as I said, which is operating and delivering 530,000 barrels a day to the U.S. every day. So my view of that is large, diversified portfolio of high-quality assets is critical to delivering the energy that North America needs on a daily basis and provides us with the enviable position on which to grow. This backbone system will continue to attract opportunities for many years to come.

And while we have great assets, what we all know is that they don't produce any results without significant human ingenuity and significant human expertise. And while I'm a bit biased here, obviously, but based on my 30 years in this business, I believe that we've assembled the best talent that's available in the industry, and that starts with our executive management team. Many of you area familiar with these faces. Alex, Karl and Don are going to join me this morning in sharing with you what the company is up to, and they'll provide you with an update here later on this morning.

But to give you a better sense of our depth, our executive team has joined us as well today. There's several of our executive leadership team, Executive Vice Presidents and Senior Vice Presidents, some of which you would have seen last night. They're pictured here and listed in the front of your programs. These are the people that run our business every day. And I hope you got a chance to talk to some of them last night. If you didn't and weren't here, take the chance to meet them. We've got a display booth out here with some of our technology. And as we to move forward, understanding what we do, I think, will help you understand where we're going as a company. They're a talented group of people. They have a wealth of industry knowledge. And I'm 100% confident that we've got the right team to actually get us through the challenges over the coming year.

Obviously, I'd like also to acknowledge, there's 5,000 people that work at our company every day that have the expertise and the talent to deliver on the challenges they see in their businesses every day. Those people are located in 8 Canadian provinces. We are still across Canada company. But what most people don't realize is that we actually operate in 32 states in the United States and we have offices now in 8 states in Mexico. So we truly are a North American enterprise, and we look to add diversity and talent to that pool on an ongoing basis.

Obviously, I'm extremely proud of the achievements this team has delivered over the last year. And I guess what I would tell you is make no mistake about why we will be successful in the future because these people are proud of what they do and they consciously work very hard to make sure that everything we do is done right the first time and that stakeholders want to continue to do business with us.

So before I talk about the opportunities that lie ahead, I thought I'd spend a couple of seconds -- or a couple of minutes here just talking about the significant accomplishments that team of people has made over the last 12 months. First of all, our construction teams have placed approximately $3.5 billion of new assets in the service throughout 2014, starting with the Bruce Power Units 1 and 2. First time in decades that we have a full 8-unit running site at Bruce. We brought 3 of our 9 Ontario Solar facilities into service. And we've had numerous NGTL expansions to capture gas in Northeast British Colombia and Northwestern Alberta over the last year. They also advanced the construction of the $2.5 billion Gulf Coast Project. Line fill is expected to start here shortly, and we hope to commence more of our commercial operations from Cushing to Port Arthur around the end of the year.

At the same time, our project team continued to advance about $5.4 billion of other projects, including Keystone XL. And we remain optimistic that Keystone XL will receive a presidential permit, hopefully, sometime in early 2014.

One of the major accomplishments on the year, as I said, is unprecedented growth. Our business development team is commercially secured, an unprecedented $19 billion of new projects, including the $12 billion Energy East project that is designed to deliver about 1.1 million barrels a day to Eastern Canada but also to export markets, all of that starting in later in 2017 and into 2018 by the time we get to New Brunswick.

Our Canadian gas team also had several accomplishments on the year. They implemented the NEB decision in the summer of this year. They were able to secure 1.3 billion cubic feet a day of additional contracts on their system, as well as they negotiated settlements with our mainline shippers for the period going forward from 2015. And as well, they were able to negotiate a settlement with our NGTL shippers going to port over the next couple of years.

The power team successfully dealt with a number of their issues this year. If you recall last year, we had a number of issues at Ravenswood and Sundance coming into the year. They successfully resolved those. Sundance is now back up and operating.

And our finance team, as we are in a growth mode, and our finance team was able to secure about $5 billion of financing on very attractive historically low rates. So clearly, a year of significant accomplishments. If you look where we were last year at this time and where we are today, I think you can see that we're in a different position to continue to deliver shareholder value and grow this company.

And further evidence of that progress can be seen in on this slide. As you can see, incremental earnings from $3.6 billion of recently commissioned assets, as well as improved results in our base businesses. At the same time, I can tell that we're growing. We're focused on making sure that our base businesses operate efficiently every day, contributed to an increase in earnings and cash flow over the last year. For the first 9 months, ended September 30, we reported earnings of about $1.66 per share, which is a 15% increase over the same period last year. And funds generated from operation were about $2.9 billion, which is an 18% increase over the last year. So the momentum is there, and we continue to show improved results.

Looking forward from today, we remain focused on some simple priorities. And these are simple priorities that you've seen and we talked about in the past. And first of all, we will continue to maximize the value of our $50 billion asset base by operating safely and reliably every day. That's what we do, and that's what our customers expect us to do.

Second, we'll continue to advance that $38 billion portfolio of new projects through the permitting and construction phases. Collectively, these projects will transform this company. I'll show you a map here in a minute as to what the company looks like going forward. But they will transform our company and set us on a platform to be able to continue to deliver shareholder growth for many decades to come.

Thirdly, we'll continue to add and pursue low-risk, both acquisition and development, opportunities that are available to our core businesses in our core geographies.

And finally, we'll maintain our financial strength, discipline and flexibility in order to fund that growth going forward. I'll talk about each of these in the next few minutes. And then after that, Karl and Alex and Don will provide you with some detail. But I did want to provide a little bit of an update on where we're at on each of these priorities here and where we're going over the next year.

So first of all, I think what I'd talk about is Job 1 at our company is to up our game as a builder and operator of large-scale energy infrastructure assets. And it may sound strange that a company like TransCanada is saying that they have to up our game. We are at the top of our industry in terms of integrity, reliability and safety. But what I would tell you is in the world that we live in today, that is not good enough. We have to be better.

Our competitive advantage will be about maintaining this lead, and at the same time, being this company that stakeholders want to do business. And that is sort of important piece of why we have won as many of these projects as we won over the last year. It really hit home with me recently where at the celebratory dinner at one of the projects that we had been successful in winning, and one of the executives from the sponsors took me aside and said, "Russ, I just want you to know that we're very pleased with what you guys have been able to provide us." It wasn't your engineering. It wasn't your design. It wasn't your pricing, which is where the world was historically. It was about pricing, lowest cost. What he said was we know that a company like TransCanada can deliver on those kinds of things. Their decision was based on your track record of working in communities, solving issues, being open. What they said is that we cannot afford to risk our brand name on something blowing up in the middle of this thing. And you, being the person that's operating our project, we can't afford to risk our brand and our reputation and being in the newspapers across the globe with folks that don't know how to deal with these issues. And that hits home to me. That's what we've been doing for the last 60 years as a company. That's what we're extremely good at today, and that's what we're going to focus on going forward. And it will separate us, and it already has. I mean, you can take a look at the $38 billion portfolio of commercially secured projects with the largest companies in the world signing long-term, 20-plus year, contracts with us. I think it's evidence that there's a lot of confidence in this company and what it's able to do. Certainly, everything that we've got to do going forward has challenges, but they recognize that TransCanada has the capability of doing it.

At TransCanada, safety is our #1 priority. We have a culture of safety at TransCanada, where everybody is encouraged to report incidents, obviously, without fear of discipline, without fear of reprisal. We're committed to continually improve that safety performance. Our belief at TransCanada is that all occupational-related incidents, whether they be onuses, trips, slips and falls, pipeline ruptures, there is an ability to get that number to 0 on all of those fronts. Our employees and contractors, this slide is just to give you one example of the many statistics that we track. And our employees and our contractors are all at the top quartile and sometimes the top decile ends of performance.

But as I said, there's room for improvement on all of these things. And as I said, this is one example. And I think you can see from this chart, the amount of activity that we've got going on at the company has increased substantially. And in this particular example, our vehicle incident rates have gone up above top quartile. And we've asked ourselves, why is that the case? Well, first of all, as you can see in this last year, between our contractors and our employees, we've driven over 100 million miles. And that's double from what it was before as you try to manage all of those people in 3 countries, as I said, 32 states in the United States, 8 states in Mexico, 8 provinces in Canada. We're trying to make sure that those employees understand what we want out of them in terms of performance.

We've implemented new things. As I said, this is just one example, and we've seen our vehicle incident rates start to come down. This is the kind of activity that we're going to up to. If we're at 100 million miles today, you can imagine where we're going to be as we start to implement $38 billion of capital projects. We're going to see those, the amount of activity, increase, and we have to make sure that our processes and procedures are at the top end in our industry and that we're continuing to push for that 0 incidence rate that I talked about. It will be what separates us going forward, and again, why companies want to do business with us is because we're conscious about those things, and they don't want to be associated with companies that don't have the same values and culture.

So turning now to the $38 billion of capital projects. This is a pretty daunting looking list. And as you can see from the map, the scale and scope of these projects is truly unprecedented and that once completed, we will position ourselves as being a leader in each one of our core businesses, as being a leader in North America. Overall, the portfolio is about approximately $23 billion of crude oil pipeline projects, $13 billion of natural gas projects and $2 billion of power generation facilities. They'll add approximately 3,000 kilometers of large diameter pipeline to our natural gas networks. So our gas business is continuing to grow even after transferring out 3,000 kilometers to our oil business. We'll add more than 7,500 kilometers to our crude business and about 1,000 megawatts to our power business. Each of these projects is backed by their long-term contracts or their ship-or-pay like contracts. Or their additional cost of service kind of models. As a result, the earnings cash flow that we expect to generate from each of these assets, we believe, is predictable and will be sustainable for a number of decades to come.

As I said, Alex and Karl will provide you with some detail in each of these projects. But as you can see, they're diversified over all 3 of our core businesses. And obviously, a capital program of that scale does not come together overnight. The process of filing regulatory applications, receiving the necessary approvals, constructing and commissioning the facilities, and finally, placing those assets into commercial service takes years for these large-scale things, which are multibillion-dollar initiatives across many jurisdictions. But as I said, that's what this company has been doing for the last 60 years, is advancing large-scale, complex projects, and that's what we intend to do going forward. These are priorities for next year in terms of how we're going to advance our capital program. We expect to complete and place into service about $3.5 billion of new assets next year. They include the Gulf Coast Project, which, as I said, is coming to completion, various NGTL expansions, the Tamazunchale expansion in Mexico. And we should bring in the 6 remaining Ontario Solar products we currently have underway. Each of those projects is expected to generate increased earnings and cash flow as we move through 2014.

Secondly, our focus in 2014 is about advancing about $7.5 billion of projects that are currently in the process of regulatory application and moving through those regulatory processes and getting them ready for construction. They include various oil pipeline initiatives in Alberta, which include Grand Rapids, which is underway; the Hardisty Terminals; the Heartland and TC Terminals project; as well as the Northern Courier project that we're doing with Fort Hills, and that is moving forward, and Alex will give you an update on that in a second; as well as expansions of the NGTL System that we need to tie in new gas and various natural gas pipelines in Mexico that we have underway. Currently, we'll advance those. As well, we'll move the Napanee project closer to construction.

Third, after more than 5 years of work with the Department of State, we hope to receive, as I said, regulatory approval for the Keystone XL Pipeline early next year, and we hope to get it under construction in 2014 as well.

Fourth, we intend to file an application for Energy East this year. Hopefully, we'll file that application in the first half of 2014, and we're working hard to meet that timeline.

And finally, we'll continue to seek regulatory approvals for the 2 West Coast LNG projects, which in total about $10 billion, in advance of what we call final investment decision. Those projects, the final call is made by the project sponsors after we get regulatory approval. And we expect that to occur sometime in late 2014 or early 2015. So we've got a big job ahead of us, but we break it down into its component parts, and we got to work on the component parts of moving that portfolio forward.

In summary, our goal over the remainder of the decade is to complete that $38 billion of capital projects and put them into service. While we'll face challenges along the way, I'm 100% confident that once these critical energy infrastructure projects are in service, they will create significant shareholder value and they will transform this company in the process. You can see by that map what we'll look like in 2020. This slide gives you a pretty good idea of what -- that we will look like a leading North American energy infrastructure company. Total assets will nearly double to about approximately $80 billion. The scale and scope of those assets will rise with more diversification that provides us with more revenue certainty given their contracted nature. And they'll give us a larger platform for continued growth going forward.

Overall, the natural gas business will continue to be a large portion of the business at about 40% of the portfolio. As well, you can see that our Oil Pipeline business will also be about 40% of the portfolio, up from about 22% today. More importantly, our backlog [ph] for the crude oil system will extend to 11,000 kilometers and it will connect the most prolific and growing basins in North America, being Western Canada and the Bakken basins, to the very best markets in North America that are currently importing oil today. We'll have about 2.5 billion -- 2.5 million barrels a day of long-haul capacity, of which we have contracts for about 2 million barrels a day. So you just have to think about what 2 million barrels a day at $5, $6, $7 a barrel for 20 years looks like from a revenue standpoint. It's extremely large and I think it's a huge commitment from the industry and confidence in our company to build these things going forward. That will be -- at that point in time, we'll be removing roughly 20% -- or 50% of all the supply that moves in Western Canada.

And finally, from an energy perspective, it will account for about 20% of our portfolio. Most of it will be contracted, will include about 11,000 megawatts of generation, which is enough power to supply about 12 million homes in North America.

From an EBITDA perspective, on a consolidated basis, EBITDA will more than double from about $4.2 billion to approximately $9.5 billion by 2020. And while that growth won't be linear, obviously, because projects tend to be lumpy, what we know is that once we get it done, it will deliver stable and steady returns going forward. The growth rate, if you took a look at it on an annualized basis, it's about 10% for the remainder of the decade. But I think this is important as the magnitude of the growth, in my view, as I've mentioned earlier, is the predictability and sustainability of that growth based on being sort of fully contracted. We expect that about 95% of the consolidated EBITDA would come from cost of service or ship-or-pay-like contracts. Also highlighted on this slide, it will come from a diverse set of assets, as I mentioned earlier.

As you can see from an EBITDA perspective, it's equivalent to the assets, about 40% coming from each of our gas and oil businesses and the remaining 15% to 20% coming from our energy business. This, in turn, will result in significantly increasing cash flow on an annual basis, leaving us with the ability to continue to make substantial investments in our 3 core businesses. There will continue to be opportunities, which I'll talk about in a second. But as well, we continue to invest in a strong and growing dividend for our shareholders for decades to come.

We do recognize the value that our shareholders place on our strong, secure and growing dividend. Our goal is to continue to grow dividends in conjunction with visible and sustainable increases in cash flow and in earnings. Over the last 13 years, we have raised the dividend from about $0.80 to $1.84 that we have today on an annual basis. That equates to a growth rate of about 6.5%. And our outlook that I've just shared with you for continued growth in earnings cash flow, I would hope, will enable our Board of Directors to continue to raise the dividends for many years yet to come.

So looking forward, where we're going, the fundamentals, I think, are expected to create tremendous opportunities in each of our 3 core businesses as we move forward. For example, North American natural gas supply is expected to grow by about 30 billion cubic feet per day. We haven't seen that kind of growth ever in our history. And that's between now and 2025. That's nearly a decade. And we want to see that kind of growth in the gas. Much of that supply is going to used to fuel natural gas-fired generation. But as well, what we're seeing is renaissance in industrial demand in North America, chemical manufacturing, fertilizer manufacturing moving back to North America because this is the lowest cost gas supply in the world.

On the oil front, North American production is expected to continue to grow. The IEA forecast recently came out and said North America will be a leader in oil growth going forward, primarily driven by both Western Canada and the Bakken. Today, the U.S. consumes about 15 million barrels a day and imports about 7 million to 8 million. The IEA is still forecasting they're going to need to import 4 million to 5 million, 6 million barrels a day going forward. And what we're doing is linking North America's supply with the key North American markets. And what we're seeing is opportunity continue to come to us as a result of that 11,000 kilometers of backbone that I talked about.

On the power front, the generation we needed to meet growing demand, as well as replacing aging infrastructure. Renewables, obviously, are going to play a role in that, and we're positioned to participate as renewable portfolio standards are put in place and future GHG reduction policies are implemented. But given the abundant supply of competitively priced natural gas, I think it's obvious that the gas-fired generation is going to play a significant role in the development of new power generation going forward.

So the fundamentals bode well for each of our core businesses, our Gas Pipeline business, our Oil Pipeline business and our Power Generation business. We see strong fundamentals in North America. I think, again, that's supported by the IEA, which has indicated that North America is going to need some $6 trillion of energy infrastructure between now and about 2030. So again, we're well positioned to capture our share of that growth going forward.

So in summary, I'd like to leave you with the following key messages, is that today, we're well on our way to being the leading North American energy infrastructure company. We have $50 billion of high-quality assets. We have more than 5,000 talented employees. And we're well positioned to take advantage of the unprecedented opportunities that lie ahead of us. And we're well positioned to deal with the challenges there that will ensue.

As we advance our $38 billion of commercially secured low-risk projects, we will enhance our competitive position in each of our 3 core businesses, and we'll deliver significant growth in cash flow, in earnings and in dividends for many years to come.

In addition, as evidenced by the fundamental outlook that I think we all share for North America for oil, gas and power, there will be significant opportunities for us to continue to invest our strong and growing cash flow in each of those businesses. We recognize that the environment in which we operate will become increasingly complex and pose these challenges, but we're prepared for those challenges. And we will continue to be a leader in setting new standards, as we always have, investing in technology, research and development, ensuring safety, reliability and environmental stewardship beyond people's expectations.

Obviously, my view is through a disciplined approach, which we've had for the last number of years, careful execution of our plans, I'm confident that we can achieve our vision of being the leading North American energy infrastructure company. And we will continue to generate superior risk-adjusted returns for our shareholders for many decades to come.

So that ends my prepared remarks here, David. My plan is to answer questions throughout the morning but as well as -- at the end of this morning because we're going to get through our presentations here first and get some of those questions answered. So I'll start by turning the podium over to Alex, and we'll start with an update of our growing Oil Pipelines business.

Alexander J. Pourbaix

Well, thanks so much for that, Russ, and I want to thank everybody for taking the time to come here today. And one thing I wanted to start off by saying is although I kind of have the responsibility as the talking head to talk to you about the oil business, I spend a lot of my time sitting in waiting rooms outside senators' offices and congressmen and women's offices and the day-to-day business. I'm incredibly lucky to have a really qualified team led by Paul Miller, a very distinguished gentleman in the back of the room. And they've done an extraordinary job in building this business. And if you haven't had an opportunity at the break, I encourage everyone to track down Paul and really get a feel for what the team is doing.

So first off, I wanted to start off by discussing the larger macro picture of oil supply and demand and how this fits into our overall strategy for our Oil Pipelines business. And just to put it in terms of oil supply, North American production is anticipated to increase by about 4 million barrels a day to 13 million barrels per day by 2020 compared to just around 9 million barrels a day in 2012. And as you can see from that chart on the right-hand side, the majority this growth is expected to come out of Western Canada and the U.S. Bakken. And if you take a look at what CAPP says, Western Canadian production is forecasted to increase by about 2 million barrels a day by the end of this decade with the bulk of that growth coming from the oil sands. This is roughly just about half of total estimated North American production growth. And along with expected growth out of the Bakken, total production increases by these -- from these 2 basins by about 3 million barrels per day by the end of the decade. And thus, the lion's share of growth in North America is expected to come from the 2 key regions in which we believe we're very well positioned to capture opportunities.

And I guess the next logical question is how is all this growth in oil supply going to get to market and which market is it likely to serve? Obviously, there are many markets for crude oil in North America that have a demand. Imported crude oil on this slide is shown in orange on those pies on the chart. So I think the simple way to look at this is anywhere there's a big orange slice, there's a potential market for Western Canadian and Bakken oil to displace imported crude oil.

And if you take a look at this, you can see that the largest opportunity for WCSB oil is refining market in the U.S. Gulf Coast, which we have targeted with our Keystone XL and Gulf Coast pipelines and which is home to many of the refineries that are configured to run heavy crudes like the Alberta crudes. In contrast, if you take a look at the U.S. Midwest, you can see, we really don't have a lot of orange on the pies, meaning that it's a fully saturated market. And if you take a look further east on the map, you can see that there's a compelling argument to be made that Eastern Canadian and U.S. markets would be the next logical place that could utilize a cheaper, reliably sourced crude oil versus imported Brent crude that these markets presently rely on.

So let's talk about how our oil strategy fits into this. Customers these days very much want to directly tie their production of the well head in the refinery markets. And this is obviously something that TransCanada can offer, and this is the basis for our pipeline strategy. And specifically, we're focused on connecting growing Western Canadian supply to key refining markets in the U.S. Midwest via-based Keystone, the PADD III market through Keystone XL and our Gulf Coast projects and Eastern Canadian refineries through the Energy East project.

Growth of oil sands is also going to require new infrastructure in Alberta to bring this oil to the 2 major market hubs in the province. And we've now secured over $3 billion of our Oil Pipeline projects to bring this supply to Edmonton and Hardisty. We remain very active pursuing additional opportunities to capture production growth in the province. We're also focused on connecting growing U.S. oil shale production, including the Bakken, to market.

And finally, we will continue to leverage our existing Natural Gas Pipeline footprint to minimize the environmental impact of routing new Oil Pipelines by following existing right of ways, and we will look at converting underutilized pipes, similar to what we did with base Keystone and our planned Energy East project to capitalize on this unprecedented growth in crude oil supply and to meet the demand for new infrastructure.

Next, I thought I would take your attention to pipeline takeaway capacity out of the WCSB when overlaid with forecasted growth in crude oil. And I think this is really important because this chart highlights the need for new infrastructure to handle Western Canadian producers' plans for growth. The white space under the Western Canada oil supply line in the 2013 to 2016 timeframe is the reason right now where we're seeing these big 30-plus dollar differentials occurring today. Without sufficient pipeline take away capacity, producers face lower netbacks for their oil. However, producers obviously are not standing still. With delays in getting our Presidential Permit, rail is increasingly filling the gap represented by the white space in the chart, and it will continue to do so until projects like Keystone XL are built.

By the end of 2015, just to put this in context, there will be over 800,000 barrels a day of rail loading capacity in Alberta, the full size of Keystone XL, compared to only 400,000 miles a day of rail capacity today. And at the same time, U.S. Gulf Coast rail unloading capacity will be over 900,000 barrels a day. The significant growth plans for rail takeaway capacity is proof that the oil sands are going to continue to get developed regardless of whether the pipelines are built. In addition, the recent announcement of oil sands projects sanctioning at Suncor's Fort Hills mine, Imperial's Kearl Phase II and Shell's Carmon Creek are further proof that production is going to still continue to be developed and is going to find its way to market.

While we view rail as a complementary short-term solution until more pipeline capacity is brought online, more rails terminals will be built to fill the capacity gap if Keystone XL is not approved. And I think it's going to be a real tragedy if this situation continues indefinitely as pipelines are obviously much more cost effective, they're statistically safer and more environmentally friendly way to transport oil. I think there's 2 other points that are worth mentioning here, and it's -- the first is a question I get asked a lot. The first is when Energy East is built, the chart shows that Western Canada will be overpiped. However, it isn't going to take very long until before the next large export line out of Alberta is going to be needed in that 2021 timeframe. And the second point, which I think is very important is that if there are any periods of overbuilt pipe out of Alberta, all of our pipelines are underpinned by long-term take-or-pay contracts, so our assets are not going to be the swing pipelines.

Before going into more detail on how we are executing on our growth strategy, I wanted to quickly remind everyone of our current Oil Pipeline business. We have firmly established ourselves with the premier oil transportation system with the startup in 2010 of base Keystone, which generates just over $700 million a year of EBITDA annually from its long-term contracts. And to date, that pipeline has safely transported over 500 million barrels a day of oil from Canada to the U.S. Midwest. Keystone offers very competitive tools to our large operational economies of scale, shorter transit times and less product degradation by connecting directly from the supply point to the end market.

As Russ talked about earlier, we have a very solid track record of being a safe and reliable operator. Our operations and major projects group are demonstrated world leaders in constructing and operating large-scale energy infrastructure. And if you haven't already, I would really encourage everybody at the break to visit with Greg Lohnes, Jim Baggs and Robert Jones at their Operations and Major Projects booth just outside the doors here if you're interested in learning more about this feature of our business.

I also wanted to recap how much we've accomplished since we just saw you. It seems very recent, but it's a full year. Our Gulf Coast Project is now nearing completion, and we'll be starting line fill this month. We've continued to advance Keystone XL throughout the year. And as many of you know, we are now awaiting the release of the Final Environmental Impact Statement from the Department of State. The biggest accomplishment for us, however, this year was securing overwhelming commercial support and the decision to proceed with the $12 billion Energy East project, which will be the largest capital project in our company's history. This a great achievement, and once built, it will have a significant impact on our company for decades to come.

We also announced another new $900 million investment in the Heartland pipeline and TC terminal projects in Alberta. And on the regulatory and permitting front, we have worked diligently to progress our existing inter-Alberta projects and have now submitted permit application to the Alberta energy regulator, for all of them. A lot of people do not realize, this has just been an extraordinary effort to get those permit applications completed, and it really speaks to the depth of our organization.

While we've accomplished a lot, our priorities, going forward, are largely continuations of our current progress to date. And they are very simply: Complete the Gulf Coast Project, secure a Presidential Permit for Keystone XL, file a regulatory application for Energy East and continue to progress our inter-Alberta pipeline projects.

Let's take a few minutes and look at each of those priorities. First, let's talk about the Gulf Coast Project. As I mentioned earlier, construction is almost complete on the $2.3 billion Gulf Coast Project from Cushing, Oklahoma, to Port Arthur, Texas, and line fill will commence very shortly. Until the end of the third quarter, we spent approximately $2 billion on this project. Transportation service is anticipated to begin near year-end. And the pipeline itself is going to have an initial capacity of about 700,000 barrels a day, with an ultimate capacity of 830,000 barrels a day when we've added complete horsepower to it. Based on the existing level of contracted volumes and our expectation of moving spot barrels, we would anticipated this project to generate roughly around $250 million of EBITDA on an annual basis, and we would expect to see initial flows between about 500,000 and 600,000 barrels a day. We recently launched another open season for the pipeline, to see if there is any additional interest in signing up firm capacity, which could add to these EBITDA numbers. In terms of the $300 million Houston Lateral component of the project, construction has recently begun, and we expect it to be in service in 2014.

So let's move to Keystone XL. Back in March the U.S. State Department issued its Draft Supplemental Environmental Impact Statement, and subsequently closed the public comment period on April 22. The latest draft came to the conclusion, that there would be no material impact on greenhouse gas emissions if the pipeline were to be permitted and went further -- went further to say that the oil sands would be developed regardless of Keystone XL. And it really is hard to imagine, with over 15,000 pages of study, that you can come to any other conclusion based on many of the reasons that I've highlighted earlier today.

Once we receive an EEIs, the project will enter up to a 90-day National Interest Determination period, where various government agencies, such as the Department of Transportation, Homeland Security, the EPA and others will weigh in. And that of the day, it is difficult to argue how increased energy security, significant economic stimulus and job creation are not in the national interest of the United States.

One thing that we've been saying is, without a clear sense of timing on receiving a permit, we stop trying to gauge exactly when it might come and when the project might be brought into service. I think sort of the simple shorthand, I would say is, we know it's going to take about 2 years of construction once we receive the permit. Project cost, right now, we haven't updated them for quite some time. I think we have a number out there about $5.4 billion, that's well over a year old now. And until we get better visibility on permit timing, it's difficult to be any more precise with this estimate. To date, we spent about $2 billion. And I would say, all of our shippers remain fully supportive, and the entire system is effectively fully-contracted after considering spot and operational reserve requirements. Cost sharing mechanisms also remain in place, which provide protection to our project economics. Both our Gulf Coast Project and Keystone XL projects are critical to alleviating the current pipeline bottlenecks. But as I said earlier, more takeaway capacity is needed. Energy East will complement Keystone XL as another tangible, efficient and safe means of transporting Western Canadian production to new markets. The project will entail converting one of our underutilized Canadian Mainline gas pipeline, highlighted here in yellow, and 1,500 kilometers of new build, highlighted on your slide in green, much of which will follow existing right-of-ways, both in Alberta and the TQM gas pipeline in Québec. I often get asked about no longer being able to serve gas customers if we convert this pipeline to oil, and I think this map is really helpful to explain how we will continue to meet the needs of our gas customers. Our Canadian Mainline used to have 6 parallel pipelines crossing the prairies. We converted the first of those lines to oil service with a Keystone project. Today the mainline consists of 5 lines across the prairies, 3 over the top of Northern Ontario, and 2 across the Eastern Triangle. Converting just one of these lines to oil service doesn't mean we no longer can serve gas customers. In fact, we remain absolutely committed to meeting their needs. The $12 billion cost estimate, which excludes the transfer value of the mainline gas assets, includes the cost for converting the gas pipeline to oil, close to 70 pump stations, 17 million to 18 million barrels of storage and 2 Marine Terminals. Energy East will be capable of transporting 1.1 million barrels a day of crude oil to delivery points in Montréal, Québec City and Saint John. There will be 2 export terminals located in Québec near Cacouna and another in Saint John. During the open season that we ran earlier this year, we were able to secure approximately 900,000 barrels a day, a firm, long-term commitments that are predominately 20 years in term. Eastern Canadian refineries consume approximately 700,000 barrels a day. Much of that is higher-priced, imported foreign oil. Energy East will enable these refiners to access a cheaper, more reliable source of feedstock. It will also allow Canada to become truly energy independent, and enable Western Canadian producers to access other export markets outside of the United States.

So I think it's clear that the benefits of Energy East extend well beyond energy security. A project of this scale and scope will create a massive amount of wealth for all of Canada. In September, Deloitte & Touche issued an independent report that solely focused on the economic benefits of this $12 billion project. Using standard StatsCan modeling formulas, the report found Energy East would create $35 billion in additional gross domestic product for Canada; $10 billion during the construction of the pipeline and another $25 billion during operations. And as you can see from this map, every project that the pipeline traverses will benefit. The breakdown by province of this $35 billion is shown in the green boxes. And as you can see, over half of this GDP creation comes in the provinces of Ontario and Québec. Ontario has the most to gain from this project, with $13 billion of GDP growth over the span of the entire life of this project, and that's just due to the simple fact that the majority of the kilometers of this pipeline are in that province. Québec and New Brunswick, on the other hand, benefit disproportionately from the development and construction phase of the project, given that the majority of the new construction is going to occur in those 2 provinces.

And just in terms of tax revenue, this one project is estimated to generate $10 billion of additional tax income across all levels of government over the life of the project; property tax revenue for municipal governments, and income tax revenue for provincial and federal governments. It's also going to create 10,000 jobs during the development and construction phase, and another 1,000 jobs once the pipeline is operational. And Deloitte the report did not factor in any possible secondary economic benefits or spinoffs that could occur in the refinery sectors in Québec and New Brunswick or other industries.

And as I think everybody knows, today, these Canadian refineries largely process light oil. With access to cheaper heavy oil feedstock through Energy East, these refineries have the opportunity to potentially make future capital investments in order to process heavy oil, which would further translate into significant job creation beyond just sustaining jobs at those refineries today, once again, creating additional revenues for provincial governments.

I thought I would now move for a few minutes to discuss our growth initiatives that we're moving forward with in Alberta. Over the course of the past 1.5 years, we've been able to leverage our presence in the oil pipeline business to capture $3.4 billion of investments. We will become a significant platform to attract growing production volumes in Alberta. Our ability to compete for this new business stems from our existing gas pipeline presence in Alberta, our familiarity with the business and regulatory environment, and our existing relationships with stakeholders.

I thought it would be worthwhile spending a few minutes to review each of these projects in more detail. And I'll start with Grand Rapids. This $3 billion project is a 50-50 joint venture with Brion, a subsidiary of PetroChina. The pipeline will be operated by TransCanada, who will transport crude oil and diluent between Northern Alberta and the Edmonton/Heartland region. In addition to their 50% equity stake, Brion has also signed a long-term contract to ship crude oil and diluent on the pipeline to underpin the investment. The pipeline system will be the first to serve the growing oil sands region west of the Athabasca River, and is unique in being able to move crude oil south and diluent north, directly to the production sites. As development in the region grows, we expect to be able to add new contracted volumes onto the system, as the only other transportation method today to bring this oil to market is by trucking it. We are planning on placing the project in-service in multiple stages, with initial crude oil service starting at mid-2015. The full system is expected to be fully operational in 2017, and we have the capacity to move up to 900,000 barrels a day of crude oil and 330,000 barrels a day of diluent.

Our $900 million Heartland pipeline in TC terminal project includes a 200-kilometer crude oil pipeline, connecting the Edmonton region to facilities in Hardisty, Alberta, along with an oil storage terminal in the Heartland area, north of Edmonton. This pipeline will be capable of moving approximately 900,000 barrels a day and will have up to 1.9 million barrels of crude oil storage at the terminal. These facilities are expected to be operational during the second half of 2015.

Our Northern Courier project received some very positive news from Suncor at the end of October, when they announced the sanctioning of the Fort Hills oil sands mine. It is expected to begin producing oil as early as late 2017. The $660 million Northern Courier project is expected to be completed in 2017, and will transport crude oil from the Fort Hills Mine site to Suncor's East tank farm facilities, north of Fort McMurray.

Moving a bit further downstream is our $275 million Keystone Hardisty tank terminal project, which provides new infrastructure for producers to gain improved access to the Keystone Pipeline System. This terminal will have about 2.6 million barrels of storage capacity, and will have a throughput capacity of about 650,000 barrels a day, and is largely contracted. The in-service of this project will be closely tied to the timing of Keystone XL. In terms of status on these projects, Keystone Hardisty tank terminal is permitted. Permit applications have been submitted for the remainder, and we expect to receive permits for these projects sometime next year.

The success we've had securing $3.4 billion of new investments in the region creates a great platform we believe we can leverage off to attract new volumes as production grows in the region. The attractiveness of our system is it allows shippers to directly connect their production into our pipeline network, and create a direct link to various export markets above via Keystone, Keystone XL or Energy East. And combined, our long-haul pipelines are capable of moving approximately 2.5 million barrels a day out of Alberta. This current platform will enable us to secure additional investment opportunities in the region.

Now that I've gone through a fairly exhaustive list of our capital projects, I thought it would be helpful to provide everybody with our vision of what things will look like when this capital program is completed. In 2012, we had approximately $10 billion worth of oil assets, split between our operating Keystone Pipeline, along with construction assets in the Gulf Coast project and Keystone XL Project. Our vision once all of our projects are fully built, is to see us have over $30 billion worth of assets by 2020, all backed by long-term contracts. We will have also grown our asset base to over 11,000 kilometers or 7,000 miles of pipelines and roughly 2.5 million barrels a day of long-term takeaway capacity, which will be capable of moving close to 50% of all forecasted Western Canadian production to various refining markets. It will also include 29 million barrels of storage and 2 marine terminals. And once again, just for emphasis, I would point out that the TransCanada team was able to do this in just a little bit over 10 years, so pretty phenomenal performance. The $28 billion worth of assets translate into approximately $4 billion of EBITDA by 2020, up from roughly $700 million from Keystone in 2012. The significant increase in EBITDA is driven by the $23 billion of commercially-secured projects that I've just discussed. Keystone, Keystone XL and the Gulf Coast Project will contribute approximately 46% of our oil pipelines' EBITDA. Energy East will also be a very significant contributor of our growth, with approximately $1.7 billion of EBITDA, while our regional oil business in Alberta will add approximately $400 million to $500 million a year. Combined, our list of commercially-secured oil pipeline projects will significantly transform this company by contributing approximately 40% of consolidated EBITDA by the end of the decade, up from $700 million or 17% of consolidated EBITDA in 2012.

So in closing, I'd like to leave you with just a couple of key takeaways. We truly no longer are just a gas pipeline and energy company. We are developing preeminent position in the oil transportation business that will be capable of moving close to 50% of Western Canadian production out of Alberta to key refining markets outside the province by the end of the decade, all under long-term contracts. Pretty remarkable statistic if you can consider it will take us approximately 10 years to do so. We are experiencing an unprecedented opportunity in terms of growth in crude oil supply, both in the oil sands and in various shale plays across Canada and the U.S. The increase in forecasted oil supply has the potential to enable North America to become energy sufficient -- self-sufficient, but we need new infrastructure in order for us to make this a reality. We currently have over $23 billion in commercially-secured projects, $13 billion of which are projects we've announced in the past year alone, that will lead to significant growth in earnings and cash flow. The opportunity set that we have in front of us, truly, is tremendous, and we believe that we are developing a solid foundation with our current set of commercially-secured projects that will create significant platform for future growth, not just in Alberta but all across North America. So that's the end of my prepared remarks. If anyone has any questions, I'd be pleased to take them.

Question-and-Answer Session

David Moneta

Just for -- in the interest of ensuring that people via webcast can hear your questions, Lian Rhonda [ph] will have microphones, so if you could just raise your hand, and one will be on its way. Andrew?

Andrew M. Kuske - Crédit Suisse AG, Research Division

Andrew Kuske, Credit Suisse. Alex, can you just give us some context on the regulatory environment, how it's changed? You started off your comments by saying how much time you spent sitting in the waiting rooms for Senators and Congressmen and other government officials. So just give us some color on how it's changed from when you started in the role, to what it is now, and then what you expect it to be in the future as you to build out this network?

Alexander J. Pourbaix

Sure. I guess you can kind of put this in perspective. Just after I joined the group, we had just successfully permitted the base Keystone project from start to finish. That permitting process, which included the full Presidential Permit, took about 21 months from start to finish. I think Enbridge, with their Clipper project, took about 24 months. We are -- I think, we're now at 61 months and counting. So And there's been an absolutely extraordinary change in how you work through this regulatory process. I'd like to say we're kind of at a low point, and I expect to see significant improvements. I think it is just realistic to assume, to some degree, that the situation we're in is going to prevail, at least for the short to medium term. The implications on TransCanada, and you've probably heard me talk about it, Russ talked about it, we -- it's made a number of changes. I mean, going forward, for example, really simple change. I don't think you'll ever see a situation again where TransCanada is willing to make the commitments that we made on Keystone XL in terms of capital commitments and development costs prior to projects being approved. We're increasingly seeking to share or place a lot of that cost on our shippers because the costs are just too big, and the timeline is such that we think it's reasonable to share those costs. I certainly -- from our team, I like to think we continue to learn by experience. And a lot of the things we're doing on Energy East, for example, have benefited from our experience with Keystone XL, our key stakeholder work. I cannot tell you how active our team is in getting into these local communities. We spent a lot of time listening, a lot less time talking, and we go at it in a very humble manner, and I'm -- I think that a lot of those initiatives that we've really modified or changed a bit, over time, are helping us with the support that we're seeing so far. But make no mistake about it, it's a challenging -- a challenging world for -- especially linear energy infrastructure, because I think our opposition have realized they don't have to fight you at every single community, they just have to pick 1 or 2, and they can make it very challenging. So we have to be out there in great numbers and getting the truth out.

Andrew M. Kuske - Crédit Suisse AG, Research Division

And then just -- if I may as a follow-up, given the regulatory environment and just the effort that goes into that process, and then does your capital cost that you base on some of these projects, does that really narrow down the competitive framework to really less than a handful of players. We could name 2 or 3 in addition to yourselves, but really that's the audience that you're competing against now.

Alexander J. Pourbaix

Yes, it's a good question, and Russ kind of alluded to it in his initial statements. I -- when I got into this business -- I mean, and it wasn't that many years ago, it really was, all that our counterparties were looking for was cost, tolls and everything was, you're just competing on a dollar-per-barrel basis. I would argue now that that's -- I mean, it's not outside of their consideration, but they are exceedingly focused on their view of a developer's ability and track record in getting these projects done. And the kind of -- you heard Russ give that comment about one of our shippers, I'm hearing that constantly. So I think we are getting to a point where it's becoming a very, very small world of developers who can actually compete, particularly for these large scale, billion-dollar-plus projects.

Russell K. Girling

Andrew, I'd just to add to the -- Alex's comment, not to underestimate the challenges that are in front of us, but I think if you look at where most of our new capital investment is intended to go, the bulk of it is in Alberta and in Canada. I think there is strong recognition across the political spectrum of the cost to the economy of not allowing market access in an efficient way. We've seen an increase in rail movement, which has put the public safety at risk as well. So, I think there's a strong recognition across all political stripes in Canada, that we need market access for these products, primarily crude. It appears that across the political spectrum, moving oil from Western Canada to Eastern Canada to displace foreign oil seems to make sense in terms of the interest of Canada. And with the advancement of new legislation here in Canada, with respect to the regulatory process and the regulator being accountable for timeframes, I think will bode well for us not being in a situation where we were in the Mackenzie Valley, for example, or in the case of the Keystone project. I think you can foresee that there will be an environment. It will be rigorous, but it's not going to take as long as we've seen these projects takes in the past. I mean, obviously, our Energy East will probably be the first large project to go through the new Bill C-38 process. But I think that across-the-board, from a political standpoint, they want to see these things done in a faster rate. The impacts on the Canadian economy, I mean, have been discussed across-the-board, and they're huge, so we have to get these things done.

Alexander J. Pourbaix

Matthew.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Matthew Akman, Scotiabank. Question on Keystone XL. You actually have a -- I guess, a $5.4 billion budget, that was the last update. And obviously you can't get real specific about how much it's going to cost until you know -- when you have the Presidential Permit. But if you were to get a Presidential Permit sooner than later, can you just talk order of magnitude how much of that cost might have shifted at all?

Alexander J. Pourbaix

We're -- I think at this point, we're -- it -- so much depends on timing. So, I am a little eerie of speculating. I think what I can say, from a helpful perspective, is that all of our shippers are fully aware of -- we discuss where capital is and where it could go, depending on timing, and our shippers remain very supportive. So I think we're comfortable we continue to have a very economic project with very economic tolls.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

And just a follow-up on that. The bar chart show that Keystone would be contributing a significant portion -- you have a number in terms of EBITDA. I guess that would grow if the cost goes up because a lot of that is pushed back to shippers, is that correct?

Alexander J. Pourbaix

That's correct.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Final question on diluent price. You talked about Grand Rapids and having 330,000 barrels a day of capacity. Just want to know, how much you plan to compete in that realm. There's been other projects announced, Enbridge's Norlite, and of course, there's [indiscernible] is the room on that attract third parties, and how interested is TransCanada in attracting third parties to the diluent part of that? And is it expandable even to attract more above 330,000 barrels a day?

Alexander J. Pourbaix

I mean, at the present configuration, I think 330,000 is about what we can handle with that project. But we do have room, and we are actively out, marketing diluent opportunities to our customers in that region.

David Moneta

There's a question over here from Carl.

Carl L. Kirst - BMO Capital Markets U.S.

Carl Kirst from BMO. Over here. You guys have got a lot on your plate. Not to kind of continue to be looking forward, but I am curious about your comments, and you even made this on the earings call as far as -- potentially for converting more gas pipeline. And obviously, that would, like Energy East, kill 2 birds with one stone. So, as we look though at potential hypotheticals, one, I didn't know if you could kind of tell us where you might be in that process as far as how much that's baking. But even maybe going a step forward, and I'll just going to throw at a hypothetical here, that if we were to be looking at something like converting and reversing a part of ANR from the Gulf of Mexico, is that hinged on getting additional volumes through Keystone and XL, i.e., the Presidential Permit, through? Or would that potentially be levering greater U.S. shale volumes to move additional Bakken, et cetera, such that, that opportunity is out there, regardless of what happens with XL?

Alexander J. Pourbaix

So I think how I would answer that is, in terms of our processes, to how do we look at these existing potentially-underutilized gas assets, what I would tell you is we have a team that is working, like everyday, looking at these assets and seeing if there is potentially a higher value use for those existing pipelines. So I would tell you, I mean, we're obviously not in a position to announce anything, but we are spreading a significant amount of time and we see a lot of opportunity in repurposing those gas assets, so we're pretty confident about that. In terms of, are they dependent -- or in any way, driven off the success of the permit for Keystone XL, I would tell you the opportunity so the team is bringing to me are opportunities, both with Canadian volumes and with solely U.S. volumes. So I think we're going to have opportunities regardless of where we end up with XL.

Carl L. Kirst - BMO Capital Markets U.S.

Okay. And maybe one quick follow-up. Just as you look -- as you look at the oil the sands and you're creating a larger platform there, and we talk about rail kind of filling the gap, there has been discussion over this year about railing pure bitumen, right, and then the savings that you'd get versus dilbit, and I'm curious if you're, in your conversations, you're getting any of that from producers, and how, maybe, you might see the actual competitive threat from rail on pure bitumen versus the dilbit?

Alexander J. Pourbaix

Sure. It is a fact, if you are of a view that you were never going to be able to build a pipe, then you could put in the facilities and the tankers to rail, pure bitumen, and there are some cost savings. From the numbers that I've seen, pipe continues to retain a material advantage, even in that scenario. I've had the benefit, over the past year, I've been in probably 2 -- on 2 or 3 panels with executives from the rail business. And it's interesting when they're asked that question, they continue to be of a view that the largest opportunity for rail is almost in this interim role of moving smaller volumes over shorter terms, while they wait for the pipeline infrastructure to be developed. So, I do think there is potentially an opportunity to rail pure bitumen, but it is a very significant capital investment. And so far we've heard a lot of talk, we haven't seen a lot of it being done.

David Moneta

Alex, just to your right, Robert?

Robert Kwan - RBC Capital Markets, LLC, Research Division

Robert Kwan, RBC. First question here. You mentioned initially you expect the Gulf Coast Project to move 500,000 and 600,0000 barrels a day. Can you just talk about what the delivery today in existing Keystone system are into Cushing? And do you expect material diversions away from the Wood River lateral?

Alexander J. Pourbaix

We do expect some. We've been -- at this point, we haven't gone kind of public with our views as exactly where that's going to shake out, and a lot of that depends on our customers, but we are planning for some diversion.

Robert Kwan - RBC Capital Markets, LLC, Research Division

So Keystone XL cost, I know you don't want to get into the magnitude, but can you just talk about what the split or the majority might be between real cost increases and what it's carrying cost?

Alexander J. Pourbaix

David, do you have any of that?

David Moneta

No. Again, I think to some degree, we'd be speculating on where the cost would go, Robert. So I think we'd rather shy away from that at this point. I think as Alex highlighted before, the customer grew continues to be quite supportive overall, and as he's highlighted, we continue to expect that it would obviously provide an economic ability -- the economics would be there for people to continue to move their oil. You think further to Matthew's comment, the numbers you're seeing in here, with regards to EBITDA, are based on the $5.4 billion. To the extent we've got cost sharing, that number could rise.

Robert Kwan - RBC Capital Markets, LLC, Research Division

Are you seeing material realtime pressure there?

Alexander J. Pourbaix

Yes. I think one thing I would say is -- and we're not just seeing this in Keystone, we're seeing this in every single project that we're working on. It is a hot market right now for pipeline construction in North America. So we are generally seeing cost pressures across the industry, and I don't think Keystone is really unique in any way. It would be facing the same kind of cost pressures we'd see on any of the other projects we're building in North America.

David Moneta

Just give us one -- okay. Sorry -- go ahead, Linda?

Linda Ezergailis - TD Securities Equity Research

Linda Ezergailis, TD Securities. I realize cost is only one consideration of many for your customers looking to procure new projects, but ability to execute, obviously very key. And you talk about the constraints and approximate market in North America for construction. What is TransCanada doing in terms of locking in contractors, capacity, et cetera, without unduly exposing yourself to the risk of, maybe, never building a large pipeline. Again, not that I'm saying that would happen, but how are you balancing that uncertainty around the scale and scope of what you're doing versus needing to lock that in, so you actually can execute.

Alexander J. Pourbaix

I think, Linda, you quite rightly make the point that it's a very complex equation to do that. From our perspective, once we get these permits, we want to be able to start construction immediately. We don't want to get the permit and then say, "Okay, now we're going to wait 3 years while we fabricate pipes and pumps for the project." So -- I mean, we are finding ways to continue going ahead, and I think a large part of that is going to be found in the cost-sharing arrangements that we've entered into with our shippers. And we go into these arrangements, our shippers understand the cost that we'll be taking on, the timing, and we all get on site with it, and that allows us to go forward with some comfort, that if we do run into a delay, TransCanada is not going to be stuck with the bill for everything. But it is a pretty complex dance because there's obviously huge amount of capital that we do need -- or significant amount of capital that we need to spend upfront in order to be ready to go forward when the permit comes.

Linda Ezergailis - TD Securities Equity Research

Just a follow-up question, if I can, and a follow-on to Kuske's question about crude by rail competitor. What about it creating a little bit of an opportunity, and I realize it might not be of large enough scale for you, but an opportunity to provide a more fulsome service to some of your customers, either as a compliment or a temporary substitute to some of your larger-pipeline solutions?

Alexander J. Pourbaix

Yes -- no, once again, it's a very good question. What I would tell you is in our -- and I've been very clear when I talk publicly. We really do believe that rail is complementary to pipeline site. I think my comment is when you need to move large volumes of oil over a large distance for a long time, you start seeing the very clear benefits of pipelines. But at an interim stage, and advance the pipeline to our -- or working with pipelines, we think there's a lot of opportunity. We are a ways from announcing anything, but what I would tell is we have really ramped up our business development activities, working with rail companies. And we're looking at a number of opportunities in that regard. Go ahead, Ted.

Theodore Durbin - Goldman Sachs Group Inc., Research Division

It's Ted Durbin with Goldman Sachs. First question, the $250 million of EBITDA on the Gulf Coast project, how much of that is actually contracted, versus how much of it is volume sensitive? In other words, if you do 500,000, or let's say, 400,000 a day, versus the 700,000 a day, how should we think about the flex on EBITDA?

Alexander J. Pourbaix

So in advance of Keystone XL, approval of our sort of estimation of how much oil we're going to move, which we talked about, the overwhelming lion share, that would be underpinned by contract.

Theodore Durbin - Goldman Sachs Group Inc., Research Division

Okay, great. And then on the Energy East as well, the $1.7 billion of EBITDA, that is just of the contacted volumes, or is there any assumption on spot volumes as well?

Alexander J. Pourbaix

That will include a modest contingent of spot, but once again, very largely contracted.

David Moneta

We have time for one more question. Steve?

Steven I. Paget - FirstEnergy Capital Corp., Research Division

Steven Paget, First Energy. Alex, on Grand Rapids, what's your sort of catchment area for tie-ins? Are competing for all new oil sands transportation contracts coming out of the greater Fort McMurray area, or the projects on the western side of the oil sands development where your pipeline is?

Alexander J. Pourbaix

I think we're -- the short answer is, is we're going to be looking to compete all over the region. But I think practically, we view that we have a very strong competitive product offering, west of the Athabasca River. And particularly, because of the larger size of our pipeline and the diluent component versus our competitors, we think we got a lot of economies of scale that will allow us to compete pretty strongly.

Steven I. Paget - FirstEnergy Capital Corp., Research Division

Could you fill sort of a northern hub where a storage hub, where pipelines sort of come together, and then merge in the Grand Rapids going south?

Alexander J. Pourbaix

Well, that would clearly be a world away which we would like to see, and we're certainly working at it from that perspective of really making Grand Rapids into trunk line that is gathering oils from -- as I said, particularly that greater west of Athabasca region.

David Moneta

Okay. Thanks, Alex. Again, as Alex highlighted and we've highlighted, that to the extent you have any further questions for Alex and/or Paul Miller, please feel free to seek them out on the oil front. They'll be around all morning, obviously, and happy to help you on that front. I turn it now over -- the podium over to Karl Johannson. Karl is President of our Natural Gas Pipelines business, and he's going to provide you with an update on his area.

Karl R. Johannson

Thanks well at that. Good morning, everybody. It's nice to be here again after a year. It's been my first full-year in this role, and I have to say that it's been real adventure this year. I think we've made some great -- bigger process in the gas pipeline business, and I look forward to talking to you a little bit about it today. This first slide, I think I showed it to you last year, and there's -- it's really that strategy of the natural gas business, so what we'd be concentrating on. I think the first I want to point out is that little box down in the corner, on the supply/demand forecast that we have for this business. I think Russ touched on this a little bit when he was up giving his remarks. And I want to emphasize this. The old adage that the solution to low prices is low prices, I think works in this case. We are seeing significant, not only increases of supply, but we're seeing significant increases in market and the demand for the product as well, coming on our systems, not only from LNG, which everybody is talking about, but from specialty chemicals, from chemicals, from power demand, and from industrial uses. So it has -- we're predicting -- the industry is predicting significant increase in this market over the next 10 years or so. And I think that -- that is really the cornerstone of what the upside is in this market over the next little while.

Secondly, if you take a look slide, you can see kind of the essence of what we've been doing. Our strategy in this business is really twofold. Number one, is to maintain the competitive position of our assets. When you take a look at the blue boxes here, we really have been working a lot on our NGTL System. How that interfaces with the LNG that's going of the west coast of B.C., and how the market picture, both the supply and demand in the WCSB, it interacts with the NGTL System. We also spent a lot of time adapting to the changes in the U.S. I'm going to talk a little bit about in -- on Great Lakes, and what we've been doing there. People ask me -- have been asking me a lot, have we seen bottom in those U.S. assets, and I guess the answer to that is, we're probably about to see bottom there, but we see lots of daylight at end of that tunnel. We're seeing lots of good new story coming out of there, and we're quite pleased with what we see coming out of there. And you can see with other assets here, we now have assets to take us to the West Coast, down with Gulf Coast, and now to the East Coast. We've also had opportunities to repurpose on these assets, so I think it's been a very good news story over the last year on the strategy of the gas pipelines.

I'd like to show this graph for a couple of reasons. Number one, it is -- it really demonstrates the platform that we have to work with here. This is the -- this best, is still, is one of the top natural gas pipelines businesses in North America. It is -- the existing natural gas business is not only one of the biggest, but it serves the -- 1 in 5 customers in North America touch our system. There's lots of good -- there's lot's -- obviously lots of opportunities still in the system. We access -- we touch our access gas in virtually every basin, and North American as well, including now the Marcellus, probably the fastest-growing basin in North America. We now access Marcellus, through both our Canadian Mainline and the ANR system in the U.S., so we have a very good position coming out of Marcellus, and we expect that position to grow over time.

The past year, we've seen significant progress in a number of areas. This time last year, I will admit we had some uncertainty as we're awaiting regulatory decisions, settlement outcomes with our customers and so forth. I think we -- I'm pleased to report here, today, and now our goals have a detail, shortly here, that we have actually seen some progress on that, and I guess the theme of my discussion today is the progress that we have seen on that.

We're also spending a lot of time adapting to the changes in the U.S. I'm going to talk a little bit about ANR in Great Lakes and what we've been doing there. People ask me, have been asking me a lot, have we seen bottom in those U.S. assets. And I guess, the answer to that is we're probably, both to see bottom as we see lots of daylight at the end of that tunnel. We're seeing lots of good news stories coming out of there and we're quite pleased by what we see coming out of there. And you can see with our other assets here, we now have assets that take us to the West Coast, down to the Gulf Coast, and now, to the East Coast. And we've also had opportunities, we prepped for some of these assets, so I think it's been a very good news story over the last joint strategy of the gas pipelines.

I'd like to show this graph for a couple of reasons. Number one, it is -- it really demonstrates the platform that we have to work with here. This Beza [ph, it's one of the top natural gas pipeline businesses in North America. It is -- the existing natural gas business is, not only one of the biggest, but it serves about 1 in 5 customers in North America -- touch our system. There's lots of -- obviously, lots of opportunities still in the system. We access -- we touched your access gas from virtually every basin, and North American as well, including now, the Marcellus, probably the fastest growing basin in North America. We now access Marcellus to bolster our Canadian Mainline and the ANR system in the U.S., so we have a very good position coming out of Marcellus and we expect that position to grow over time.

The past year, we've seen significant progress in a number of areas that, at this time last year, I will admit, we had some uncertainty as we're waiting revelatory decisions, settlement outcomes with our customers and so forth. I think the -- I'm pleased to report here, today, and I'll go over the details in the chart right here, that we've actually seen some progress on that and, I guess, the theme of my discussion, today, is the progress that we have seen on that.

I'm also very optimistic that we'll continue to progress. I think that graph that you saw on the last Slide with the growth and supply and demand of the systems sets up well for a system like this going forward.

What has our progress been? Well, let's start with Canadian Mainline. We received a decision on our restructuring proposal application in March, which was implemented by July 1. So we've received that decision from the NEB, which, really, gave us fixed prices, 5-year fixed-price deal on the mainline with market based short-term or discretionary revenues. As a result of that, we've seen an initial 1.3 Bcf a day, contracted on our system, on the mainline, coming out of Empress. That about doubles the contracts we had on our system. So I think, although, I'm not happy with all aspects of that NEB decision, I do think that, at least, the discretionary pricing flexibility that we have, has given as a tool that actually track and retain firm service on our pipeline. And so, I am pleased with at the -- our ability to turn that decision and make some progress on the mainline system. But I have to admit, I'm still very concerned over lots of the parts of that decision.

Our revenues for 2013 and '14 on the mainline are expected to be very close to our revenue requirement, including recovery of the 11.5% ROE on 40% equity thickness. So I think it's been a very significant year for the mainline up perspective. And we're expecting our revenues to be very close to our revenue requirement for both 2013 and 2014. So we've been able to parlay this flexibility the NEB has given us, and some pretty good outcomes.

We've also recently reached an agreement with local distribution companies in Eastern Canada that, subject to the NEB approval, we'll provide an economic framework to advance future infrastructure needs in Eastern Canada, and a reasonable opportunity for TransCanada to recover, both as cost of existing infrastructure and any new infrastructure that we put in to de-bottleneck and shore up these as part of our system.

We've also reached a revenue requirement settlement with NGTL during this period of time, where we've been able to increase our ROE to 10.1% on 40% thickness and we have achieved increased rates of depreciation, or amortization, coming back to us. In addition, we've been able to secure one more LNG project.

Early Last year, we announced the Prince Rupert LNG pipeline by Progress Energy and Petronas. Again, another very credible LNG proponent, so that leaves us 2, with our close to gasoline with Shell as the proponent and the Prince Rupert LNG pipeline with Petronas and Progress Energy, as the proponent.

In the U.S., we have, again achieved a rate settlement with our shippers, this year, on began to achieve a rate settlement with our shippers, this year, on the Great Lakes system. The settlement has been filed with -- it has been actually approved by FERC, has been filed and approved by FERC. The financial impact of the settlement is not that great about great this year, but we did achieve a 21% increase in our default rates and, I think, once we start seeing this -- the demand come back to the system and the transportation spread in the system improve, we'll be able to see the fruits from that labor of that settlement.

We've also, recently, completed open season on the ANR system, trying to track the Marcellus and Utica shale gas. As I talked a little bit earlier, we're very successful in doing this. We have attracted over 350 million a day onto the ANR system and that amounts to organic revenue about $20 million to $25 million a year. More importantly, we have a backlog of interest coming on that system, so we have some non-firm interest coming on that system, which we're working on right now, to see if we can accommodate. And again, importantly, this volume, by coming on our system, means it doesn't go on to other competing systems in the region. So I think it's a very good that we tracked it, we're able to track Utica and Marcellus in our systems. I think that there's opportunities for more in the ANR system, and I think it just goes to show the ANR, the diversity of the supplies of ANR system, continues to grow.

Finally, in July, we closed another drop down to the LP, just a little over $1 billion for an additional 45% of Bison and TGN. And I'll talk a little bit about the LP, in a minute.

What are our priorities coming up over the next year? Well, this has been a busy year in the gas to pipeline business and I think, you and I, talked about our priorities, I think I got to talk about the execution, both execution of our commercial activities and, execution of our projects themselves. On the commercial activities, we have to get the LBC settlement on the mainline 10:36 PM through the regulatory process over the next year. We'll be -- we're right now, stakeholder consultations on that. We expect -- we do not expect that settlement to go to the NEB, unopposed. But we do expect that we're going to get the vast majority of the revenue payers on our system supporting us on that settlement. So we will be filing for that settlement before the end of this year and it is our hope that we can get to them through the process by mid-year, next year, to get it approved by the NEB.

The second commercial initiative that we have to execute on, really, is our U.S. pipes. We need to take the success we've had with the Utica and Marcellus gas coming off the U.S. pipes, and we need to see how we can grow that, we need to see how we can de-bottleneck the Lebanon lateral, which is coming in plumb, and we need to see if we can grab that other additional supplies. Right now, waiting on the wings, the expressions of interest we've had on it are probably equal to 350 million a day we've already contracted for, so there's a very big prize there. We also have to execute on our cost initiatives on the U.S. pipes. All right, this year, we expecting to reduce our cost of the U.S. pipes for about 15% and that about a $50 million a year savings and cost on that system. So we're, probably -- I would suggest we're halfway through that cost initiative right now and right now, it's the execution, we've got the finish that off. Secondly, execution means furthering our new projects. We have significant projects, not only on LNG, with the cost of gas range and Prince Rupert. But we have projects in the NGTL System, both our regular projects and the new expansion that we have in the North Montney for Petronas. So the key to that, is furthering the permitting. Virtually, all these are in some sort of permitting stage and that's going to be our concentration, over this next year is to get through the permitting stage. Get through the final investment decisions on our LNG and projects. As well as important, another important project that we have, that we're supporting, really, is the Energy East. Moving this gas, this uncontracted for and surplus capacity from our gas pipeline system into the oil project, I think is critical for the long-term sustainability for the mainline system. As well as execution commercial, we have to bring our existing construction projects to fruition. We have the Tamazunchale Extension right now, we're still planning to be in service, some time, first part of next year on the Tamazunchale Extension in Mexico, and we have several NGTL projects that are in the midst of construction. Aside from execution priorities, we -- and our competitive initiatives, we are also pursuing additional growth strategies.

As I talked a little bit earlier, this business, with the increase in demand and the increases in supply, really, has opportunity for growth and TransCanada is keenly aware of that. We're spending business development effort rights now on that growth. The mainline, now has gross to have tourists in the Eastern triangle section. Due to this LDC settlement, we can now start de-bottlenecking that decision, so you'll actually see some additional growth on the mainline, just on the Eastern portion of that system as this LDC settlement gets approved by the NEB as well. And of course, we're very optimistic of the Mexican business. The Mexican business is, I think still in a very infancy stage. I expect more business to come out of that, and I think that we've got ourselves a very good position in Mexico as a preferred supplier of pipeline services.

I'd like to talk for a minute about some of the specific areas of the gas business, start with the mainline. Let me first say that the mainline had a great year. I know we've had been up here in the stage several times over the past couple of years, talking about the troubles of the mainline. I think I could would say that we've seen a real turnaround this year, not only with the NEB decision and the parts of the NEB decision that helped us solidify and new service coming out of the LDC settlement. I think we've seen the mainline, now, start to get on a path where we're going to see it stabilize and we're going to see it start looking better for the long-term. During this last year, just for an example, we had about 2.2 Bcf a day of constant flows on it. It peaked about 3.5 Bcf and we still had deliveries of over 4 Bcf a day out of the system, mainly out of the Eastern Triangle, other systems. So it's still very, very substantial, by North American standards, it's very, very substantial pipeline system and I think the progress we've made this year, with the NEB decision, and with the LDC settlement has really put it in different financial footing going forward. That being said , mainline is being used differently. As a result, significant changes of crude natural gas markets and, I think, we have to be aware of that. We did try and adjust to these changes with the NEB restructuring proposal, we put in 2011 and litigated it over the last couple of years. As you know, the NEB did create a new model for it, which we're following now and I did say earlier that although we've been able to use some of the tools they have given us, to increase that effect of increase in the firm specially the long-haul frontiers of the system, we're still quite some concern over some of the comments and some of the decision parameters in that NEB decision. So we've be working with them as best we can. I think we've seen some results, but I think it really did behoove us to go out if we see if we could restructure, somehow, with our customers on the system, which we did with the LDC settlement.

I don't think I need to say anything more about the LDC settlement on the Eastern Triangle. It is, in essence, this settlement provides a vehicle by which TransCanada can invest in the Eastern Triangle of the system, and the shippers in the Eastern Triangle system of will start paying their own cost of service rates, including roll-in of any investments in the triangle. The shippers in the Eastern is part of our system, too. Especially the LDCs, we'll guarantee a push in the long haul for a period of time, up to 2020. And that happens to coincide with the period of time when the Northern Ontario line has fully depreciated and that's why we picked 2020 on that. So the Eastern shippers are going to support the long haul for that period of time till Northern Ontario line is fully depreciated and they will accept cost of service rates with full roll-in of overall new capital. What do they get for this? Well, the shippers in the Eastern Canada want diversity of their supply and their receive options. They want to bring more Marcellus and Utica production into their system. What does TransCanada get out of that? We can now -- TransCanada can now invest in that triangle, so we can now enable that diversity supply, without harming our overall system, by not getting our revenues that we need to maintain our revenue requirement. So the Eastern shippers will be able to get more access to Marcellus, more access to Utica and they will also support a long haul system until it's -- until, at least, the Northern Ontario line is fully depreciated. And after that, we're going to end up really with 2 different utilities. We're going to end up with the Western utility, that's going to be mostly depreciated and we're going to have an Asian triangle, that's still going to be growing, and we're going to putting lots of capital in on our cost of service and roll-in. Again, as I talked about earlier, we've been involved in the stakeholder consultations on this. We will have that done shortly. We have just really issued the contract on that settlement, so we're still in laws of discussion with our stakeholders trying to gain as much consensus as we can. Also point out that with this change, we have adjusted the ROE expectations coming out of this business, the ROE now with incentives, contributions by TransCanada will range between 8.7 and 11.5%, with a target of around 10.1%, which is consistent with some of the other pipelines that we have, and that just reflects a lower risk profile that we're seeing on this business now, if we get the LDC settlement through.

I also deferred one, this slide, I want to say a few words about the Energy East, before I move on here. One of the issues that we got to do next year is to support the Energy East repurposing, the moving of this surplus and uncontracted capacity out of gas service into oil service. I think that's very important for long run, in the mainline to rationalize our capacity. We cannot continue to operate with so much surplus and uncontracted capacity. We have to rationalize it, we have to get capacity work out loosely match the management system.

We are -- just to be very clear on this, we are -- with this transfer, we are going to be able -- unequivocally be able to honor all existing FT contracts we have on our system. All existing firm contracts on our system we'll being on Al existing from conscious in our system will be able to honor. There will be a big benefit for those contracts, because we're going to take capacity out of the system, we'll build to honor. a big benefit for those of FD contracts holders because we're going to take capacity under the system but will still be honored those contracts. It's not lost on us with our gas systems that some of our customers are serving from loads without contracts. We know that. We expected that. In our opinion, they should have contracts, but they didn't win. We know that. People are coming to us, saying what am I going to do? I need the capacity and I don't have the contract? TransCanada is absolutely we're not leaving the gas business, whatsoever. This is an exercise rationalizing our capacity closer to our demand. We will accommodate people that don't have contracts now that need contracts. Bill Beedle prodded me that. We have to made a commitment day before anything gets transferred are the system, a people needle contracts, they could come to us, we're going to have an open season and we will commented for new contacts so before everything is up, we'll make sure that all the gas is taken accounted for. We are gas supply company -- transportation company. We do not intend to exit that industry at all. We do intend to serve our customers, we're just intending to rationalize a capacity of this is a model that as well. I would also say, to, just able adjusted. The cost of doing it is not that is a significant at all producers because a matter fact, we're expecting the cost of our producers even when we add more capacity in for these customers that may need capacity that don't have contracts right now. We expect our cost of running our system to actually decline. At worse, we're expecting it to be both even with the cost of the system as it is today even with replacements of pit rousing gas for people that don't currently have contracts. So is not going to be that the rationalization of fixed capacity huge benefits and certainly, anybody who need capacity of the gas does have a contact today we'll be able to accommodate and I think we'll be able to accommodate on a fairly economical basis. As I said before, we're expecting the cost to be even lower than today because we're capital are taken out of the system and lower, we're not expecting it to exceed the cost of running the systems today at all even with the new capacity we've had to add in. On the no, 2013 has been very porting year for the mainline and we're looking forward to executing and getting not always LDC settlement for us but the energy East forward. The energy NGTL System, our strategy really on this is to continue to preeminent position in the basin than that it has. It really -- this system runs about 75% of WCSB gas onto it. It's been very, very -- there's volumes on it that have been very consistent. We keep -- it's been a very important conduit for the LNG projects going forward as you can see with our North Montney expansion that we announced with Petronas. It is the system of choice for LNG and a system of choice because it gives them such flexibility, not only physically board and in take that much gas or pick that much gas on the system but has got the markets surrounding it, that is almost second to none in North America. When you look at the trading and financial market around NGTL the net system mid-system, the transfer system, it's still it trades on a daily basis of about 6x as average volume, so we're still at 60 Bcf a trade on a daily basis coming out of this system and that is very important for LNG players. We need to maybe blah the system the short online on system that there'll probably their plans. So this is Bruno very critical system for us and our efforts on the LNG system as we get the NGTL integrated with the services with it. Also it is -- the NGTL is a system that we continue to be very confident in its future. It turned out to be a very important advantage for the LNG. We just recently had a settlement with our shippers that both increase the rate return on it to 10.1 on 40% and an increase of depreciation rate coming out of that system. Our depreciation comps, depreciation rates last year, for example, was about 2.71% and we've increased that in 2013, 2014, we increased that to 3.05% and 3.12% for the conversation -- composite depreciation rate. So it was -- we have seen some progress with our settlements there. We have -- the settlement will go through the end of 2014, and there will be discussions with our customers again.

Move onto our LNG investments. Coastal GasLink, I think we talked about this last year, a $4 billion investment underpinned by long-term take-or-pay contracts. The sponsors of this project are very, very seasonal LNG players. Shell has the lead there, they're both in the upstream and downstream and LNG and, of course, their partners are committed LNG buyers. We're very confident in this project. We think we have could we have a good sponsorship group on this project and, right now, we working through the environmental permits. Diligently, we're looking for a final investment date, in sometime 2015. So it is, again, it is -- we consider this along with our other LNG projects to be very high probability projects. The one that we've announced earlier this year, the Prince Rupert Gas Transmission project. It is -- our second LNG project, this $5 billion Prince Rupert Gas Transmission project will serve the Pacific Northwest LNG facility proposed by Progress Energy and Petronas. Again, internationally recognized LNG players was just progress. The facility being relocated in Prince Rupert, in West Coast, B. C. and, again, we're working on securing the environmental permits on this particular project. Final investment decision date is sometime late 2014 on it. The main point to take away from these 2 approaches is that we're partnered with 2 very strong groups of companies with business experience in LNG and gas exploration experience.

Our ability to connect the gas into our liquid hub at NIT, or the NGTL system, in the interim period between the drilling commences and prior to commercial and service of the LNG facilities provide strong economic benefits for these companies to align with TransCanada, AMI and the NGTL system.

U.S. Natural Gas Pipelines. Well, I think, as you're aware of the -- it's been particularly ANR and Great Lakes systems have been under great pressure in the last years on the revenue. Both on storage spreads when it comes to ANR which has been very, very low and on transportation spreads on these systems. We're working hard to address this decline and we're making progress in a number of areas. As I said earlier, people have asked me, have I seen the bottom? As I said earlier, you were to ask me have I seen the bottom, I guess my answer always as well we may not be there yet at bottom, but I'm certainly starting to see a lot of light at the end of the tunnel. We start to see some progress in it and TransCanada has been working very diligently on trying to turn this around and get stabilize revenues, everything from the discussion that you just had with, Alex as repurposing opportunities, to nurse services on the lines and to rate cases on the line. As I talked to earlier, Great Lakes just had a FERC approved settlement, 21% increase in its deep well rates. That's not going to flow through a huge amount of revenue this first year, but certainly set us up well with the future as we start recovery. The ANR system, the Lebanon Lateral, open season for the Utica and Marcellus is, I think, it's really icing on the cake for that system. It's been systems access is virtually every Mid-Continent shale play in the U.S. and now, it's Marcellus and Utica is accessing. Lebanon Lateral, by the way, used to be kind of an export conduit to put it out to gas in the market so we've reversed it and we're bringing it in to the ANR systems into the going Chicago area, Wisconsin area and then down, so that's going to be a very attractive market for the surplus Marcellus. We're also working very hard to connect new industrial demand, a longer pipeline route and approach our generation LNG supply. LNG in Gulf Coast that some of the permits that the U.S. is giving right now, we expect to see some of that volume. There won't be a large construction for that LNG because the facility is already there but we do expect to participate in that market.

Other developments include the completion of regulatory hearings, seeking market-based rates for our ANR storage company and the restructuring of our ANR offshore assets into its own company, which really has been a very good story as well. We've taken offshore assets out of ANR, put it in its own company and are now toiling those independently and we've been able to add $15 million a year in new revenue from that initiative alone. So it's going to be key -- the restructuring of the U.S. assets is going to be a key area, key execution priority for TransCanada over the next little while and something that we're going to continue to working on.

Well Let's just talk briefly about the U.S., the TC PipeLines, LP. As you can see from the chart here, this is our sponsored LP. It is an important part of our U.S. pipeline [indiscernible] because it owns or has interest in 6 of our FERC-regulated Natural Gas Pipelines. The pie chart -- slide illustrates it's very highly contracted, both mid-90s of the revenue are from contracts in the system, so it is a very reliable vehicle. It's access include 46% [indiscernible] of Great Lakes, 50% interest in Northern Border, 100% interest Tuscarora and North Baha systems, and a 70% interest in both Bison and GTN. This entity has been an important source of financing for our current development portfolio. I think Don will talk a little bit about it later as to how it fits in for financing that development portfolio. We did complete 1 drop down last year and as our development portfolio firms out, I think the plan would be that we will be looking to drop all of our assets in the U.S. into the LP over the time as our development program gets -- we see more visibility on it and it starts getting -- it starts firming up. So it is something that we intend to continue using in the future. And as I said, our plan would be -- and our expectation would be that as our development program at TransCanada gets more and more defined, we'll be looking to put more of our assets or all of our assets ultimately into this vehicle, depending upon on how the development portfolio turns out at TransCanada.

Mexico Natural Gas Pipeline. Since last year, I want to talk about on the businesses. As I've said before, that this year it contains a variety of significant growth. We have -- when every -- when all the construction is done in this area, we'll have like $2.5 billion worth of assets in there. Right now, we have 2 operating pipelines at Guadalajara and Tamazunchale. We're just in the final stages of the construction of the Tamazunchale extension. We're looking to be in service around the first half of next year. When you get an opportunity to go on and take a look at the some of the booths we sent up here, you might want to take a look at the some of the construction photos of the Tamazunchale. It's really interesting. It's going to a very mountainous terrain. It goes to why TransCanada gets these deals, not only in Mexico but also in the LNG. We get a look at the train that we're building through. These modest trains, they're normal for us. There's something that we do all the time but there's not many people that can handle building through the mountains. So you'll notice on those photographs, we're [indiscernible] top off the mountains and put the pipelines on them and it's something that -- when people come to TransCanada, little [ph] that they know that they -- that we could be successful and we have experience doing this. So I'd encourage you to take a look at some of the photos and Robert will gladly tell you about some of the interesting parts of mountaintop. pipelining. But it is, again, it's good visual as to why people pick us. Now, we -- not only that Tamazunchale extension coming on. We recently turn the soil to start construction on Topolobampo pipeline and we're going to be starting construction on Mazatlan very soon here. So we have full construction going on in Mexico. We have a new office, we have our office established here in Mexico City. I transferred a new Country Manager down there this year, Brandon Ashton. Unfortunately, he wasn't able to join us today, but I transferred a new country manager down there and we're very serious with this business. And we're quite optimistic in the future of this business. So there's big plans in Mexico, not only with the electricity that we're working with right now, but the energy reforms that are going on in Mexico, if they are successful in getting this reforms through, we believe there'll be more upstream activity, which means more infrastructure needs in Mexico.

Just to kind of summarize up here, realizing our vision on -- what does gas pipeline going to look like at the end of 2020, if we get all these? And I want to plan [ph] out that this is not bad for a mature business. A gas business that people are concerned about a few years ago. When you take a look at some of where we take this business over the next 7 or 8 years, specially with just existing commercially supported projects that we have right now, it's quite remarkable. We're going to see, literally, a $10 billion increase, a net increase in assets, but more importantly, I think, when you look at that, when you look at that mixture now, it will be far more diversified, at least far more abreast to it. And I would add that, financially, I think it will be more solid business, too where a lot of these new projects we have negotiated rates, negotiated returns, negotiated cash coming out of these projects. They're not at -- the return on equity is set to negotiation. It is not at the discretion of a regulator to come and change it every few years when we have a hearing. So you'll see it not only diversified and geographic in type of business LNG or utility, but you'll see it diversified and how we bring our return on the systems as well.

The -- again, going to our EBITDA. Same real story. When you look at it, if we're able to bring all these projects pass final investment decision and bring them on 2020, we're going to see, not quite a doubling, but it will be a very substantial -- a very substantial increase in the EBITDA of this system. Again, from just under $3 billion to over $4 billion a year. Again, not bad for a mature business. And again, these were only using the -- we're only using the projects that we have currently on the plate when we do up with these numbers. And I think when you look at that graph in the supply and demand, coming up over the next 10 years, I think there's going to be more opportunity as well. What are the key takeaways? Well, again, I say this several times in every year but large network of essential infrastructure. The reason we're able to get the LNG project is because of our work in NGTL. The reason we're able to get the Mexico Project is because of the confidence of the Mexican government in the electric utility have and our ability to construct in difficult terrain and that comes from working on NGTL, that comes from working in other parts of our system. And so it is a very -- the large network of essential infrastructure really does give us good competitive advantage here. Commercial projects. The -- we have seen a lot of progress this year. I'm very pleased with it. I do recognize, last year, we came with lots of uncertainties around the NEB settlement in the mainline with the U.S. and I think this year, we are able to have significant progress on attending to those issues. And I think that this coming up year, I think, we'll put some of them to bed for quite a long time. And $13 billion of commercially secured projects, future growth and of course, it all with reliability and safety. If we don't deliver our products in a safely and reliable manner, we won't be in business very long. So it's a very important for us, and especially given the amount of gas that we do move. If we're not very reliable, 1 out of 5 households are going to feel it. So I'm -- So I appreciate your attention. I think that sums up my remarks this morning. I would be prepared to take some questions, if anybody has questions right now.

David Moneta

[Operator Instructions]

Juan Plessis - Canaccord Genuity, Research Division

Juan Plessis, Canaccord Genuity. Karl, with respect to West Coast LNG infrastructure, would TransCanada limit its involvement in NGL or -- at the LNG infrastructure to Natural Gas Pipeline transportation service, or could we potentially see investments in other areas of the LNG value chain, such as direct investment in the LNG terminals themselves?

Karl R. Johannson

Well, I guess the way I could answer that right now is, we're concentrating on being the Pipeline infrastructure provider to these projects. We haven't really gone seeking any investment in the LNG facilities themselves. Would we change our mind sometime in the future? It's hard for me to speculate on that right now. I do know where -- we have a roll on this that I think it's something that's within our distinctive confidence doing something that we can do very well. Will we branch out over time? You can never say never, but really, right now, it's not our strategy to go after the investments and the liquefaction terminals of the cells.

Juan Plessis - Canaccord Genuity, Research Division

As a follow-up, on the mainline, you've contracted an additional 1.3 BCF per day of Firm Transportation service. You're now at around 2.5 BCF per day. Do you think there's opportunity for additional FT contracts? Or is 2.5 BCF a day pretty much all you're expecting?

Karl R. Johannson

Yes, I guess. I would say there's opportunity for more FT contracts. Are there opportunities for another 1.3 BCF a day contract? Probably not. But we're still getting new FT on the system all the time. I think the majority, we see the big bump from the NEB decision but it is -- that's not last. We'll see more. But certainly, we won't see another BCF coming in the system, we'll be putting it on a measured pace gone going forward.

Andrew M. Kuske - Crédit Suisse AG, Research Division

Karl, it's Andrew Kuske from Crédit Suisse. Could you talk a little bit about the interplay on growth opportunities in the Alberta power market and the Ontario power market as there's a greater transition towards natural gas usage, in particular in Alberta over the next decade? And just from a pipeline perspective, what that means to your business?

Karl R. Johannson

Well, I think that -- especially in Canada -- let me talk about a little bit broader than just Alberta and Ontario. I think in the U.S., the growth in the gas power and the potential change from coal to gas in the U.S. is something that's got our interest in the U.S. as well. And I think, this is all good for the gas infrastructures system. One of the things that I didn't really talk about when I would talk to an NGTL. But NGTL right now, just talk about Alberta with the demand in Alberta, it has load on our market on NGTL alone of about 3 -- it averages about 3.5 BCF a day, it peaks about 5.5 BCF a day. That is the size, if not greater, than the Eastern Canada load in our system, just to give you an idea in Alberta. So if you put more electric on and more gas, probably electrical, and we're going to see more of that coming in the future. We're going to see more gas, more drawing of gas, more production in gas in Alberta, and that's good. Some would argue that maybe that drags it -- drags the gas out of the mainline system, I don't accept that argument. There's more reserves in Alberta than we've ever seen. New demand in Alberta is good for our system and so. Out East, obviously, the Ontario government has made it our priority to replace coal with gas. They're going to be doing some nuclear refurbishments as well, but certainly gas is going to play a big role there. I think unlike about the East is, they are further down our system, they do tend to buy FT contracts -- the power generators there. So I think it's -- again, the power generation there, typically, they run short-haul service but they do contracts, so I think it's very positive for the system. And of course, in the U.S., the growth of gas-fired power and the concern over coal and maybe the transformation of coal, I think, is going to be a big win for our U.S. infrastructure. We're working that hard right now. We have people on the ground talking to the coal producers right now on their plans for conversion. So it's -- I think, again, it goes to that chart on the first slide I put with the growth in demand for other product. I think gas can compete now and electricity. I think the industry is doing a better job of convincing the policymakers that gas is a reliable fuel for power generation. I think for a little while, gas has suffered a little bit because they built all the gas generation and the gas price doubled. Earlier in the decade or late last decade, the gas price doubled but I think the policymakers and the electricity producers are starting to get comfortable with gas and I look forward that to be a very major growth area for us.

Andrew M. Kuske - Crédit Suisse AG, Research Division

Do you have any quantification of the opportunity for Canada, U.S.?

Karl R. Johannson

On the top of my head, I don't. I guess, we have done some strategic thinking over what the total might be. I don't know if I'm ready to talk about that in the public right now, but it could be substantial. If you take a look -- when you take a look at that first graph there and you see the power wins, that's over all quantification of the opportunity in North America. What piece of that will TransCanada get? It's hard to tell, but if you just put a 20% of that, which will be maintaining our normal market share will be substantial to this business.

Paul Lechem - CIBC World Markets Inc., Research Division

Paul Lechem, CIBC. Just some clarification on the L.P. You talked about the intent to drop down for the U.S. assets in the LP. You're talking about just the gas assets or could Keystone -- existing Keystone, the Gulf Coast projects, could those the assets to be drop down? And also, some sorts on the pace of the drop down, are you talking about a measured pace every year or could we see a large drop down similar to what's Spectra did with their LP?

Karl R. Johannson

I think, first of all, I think I'm just talking about the gas assets, which is what I'm talking about. And secondly, I think, the optimal word with what I said was our plan. Really, it really goes towards how our development portfolio firms up coming out of the TransCanada and we will adjust the pace according to how that portfolio firms up. And I'll leave it to Don to talk about specific timing. He would be in charge of the timing and our need for capital. But it still is, and we still view the LP as a great source of financing for TransCanada and it would be our plan to announce this as this development firms up that we would use it substantially. I can't really talk about a plan -- a part of the plan right now is to when each drop down would come because I just don't know if our development program has been firmed up enough to talk about that.

Donald R. Marchand

Just to add to Karl's comment, obviously what ventures to us is cash. When we have cash needs, we'll be dropping down. We don't have any interest in taking back paper so it's not along the lines to what some of our peers have done in the industry. For us, the vehicle has always been, 1 for financing and as we see our financing needs develop here over the coming months, as our projects solidify, we need cash and that will be sort of dictate the timeframe for dropping things down.

Paul Lechem - CIBC World Markets Inc., Research Division

Okay, just a follow-up, if I can, on the LNG pipeline to the West Coast. The numbers -- the dollar amounts are still the same as when you announced them. There's been some commentary recently, some articles about already rerouting some of the pipeline surrounded by environmentally sensitive areas. If you move through the process, just wondering, what confident you have with those numbers that you put out there in terms of the dollar counts and what potential could there be for those numbers to increase over time?

Karl R. Johannson

Those are good questions. Our [indiscernible] those numbers are quite high right now, but I will say that we do have some changes both coming in these projects as well permitting and that's kind of normal way when we expected it. So is that price, that cost going to change going forward? Probably,it will change but I don't see our cost escalating because the costs was inappropriately forecasted. I'm seeing, maybe there's some cost escalating because there's been some changes go up to the project. So we're not in the position right now to come out and say what that is. We're really in the process of determining the root, determining what change scopes are and then we'll do the math and bring the cost out of that time.

Donald R. Marchand

I would add that, this is completely -- the change scope, the change of route and whatnot was completely anticipated when we did these deals with our customers and these are the types of cost increase that will flow right through at our customers because it was completely anticipated them once we got into, we would have to change the scope ultimately on the root.

Linda Ezergailis - TD Securities Equity Research

Linda Ezergailis, TD Securities. Your -- the book ends of your potential returns for the mainline on the LDC settlement are quite live, ranging between 8.7% to 11.5%. Obviously, the expectation would be 10.1%. But what would the world have to look like and what would be the key variables that will move around to get you to the lower end of that range versus the top end of that range?

Karl R. Johannson

Well, the way the incentive program really works. Our leasing settlement is that, we set basically a 10.1% days of our return on equity on 40%. TransCanada has made a contribution out of its own pocket to have $20 million after-tax to get to facilitate in our skin of the game so-to-speak of the settlement. And then we have an incentive program of a net revenue requirement. So we're quite comfortable under that program that for exceed our net revenue firm, which has forecast, which will actually -- filed upfront. If we saw a more discretionary or more firm tools in that incentive program, then we're going to -- we're going to be share some of that. The keys that may drive it down further is that if that those sales aren't there. If you take a look at our $20 million contribution, up from 10.1%, it takes it about 9.3%, so I'd say we can't get anything over our net revenue, that's kind of where we're at this case, so that will be a case where we just mash our net revenue and we weren't able to hit any additional sales. So we're quite comfortable with the way it has been set up. It's a pretty classic share in mechanism, that revenue and anything in excess we share with. And we're pretty comfortable we'll be able to get the 10.1%. Will be able to get to 11.5%? We'll see. It is a very long settlement, there's going to be some years where I think we would put enough on it for upside. Other years, we can get much lower than 9.3%, which is our 10.1% lesser contribution. While we have a floor already 0.7%, so you can't go much lower than that. It really does to henge on our ability to keep the FTM system and get discretionary revenues.

David Moneta

Any other questions for Karl?

Steven I. Paget - FirstEnergy Capital Corp., Research Division

Steven Padgett, First Energy. Karl, is gas, with some have proposed is exported from an terminal in Southern Oregon. Is there an opportunity to grow TCM?[ph]

Karl R. Johannson

Well, I am not sure, the answer is yes. I think any demand on that side of the system is going to draw extra gas from that system. Will we be able to expand it? I would see a major expansion of it but maybe some of it may be de-bottlenecking of that system but I think yes, directionally any exports coming out of Oregon is going to, regardless of the fact, they end up on GD and itself or in the other pipelines in the area. I think it's directionally very good for supplying that region, at always, region at GT will get a share of.

Patrick Kenny - National Bank Financial, Inc., Research Division

My second question. Is there I guess, gas liquidity or gas transmission between may be called the Northeast Section of ANR and the Eastern triangle, So let gas in the ANR system get to the Eastern Triangle or could TransCanada build something new to increase that liquidity?

Karl R. Johannson

Yes. Well, the way that gas gets may in the ANR to the Eastern Triangles, it kind of an indirect route. It would be something that maybe we would look at reinforcing. Some gas kind of getting -- our main conduit in that area is Great Lakes into St. Claire. but the Utica and Marcellus, I think when they come into our system, probably, will commence to Niagara and ship first. I am excepting longer-term where we'll see Marcellus commence plus there is some projects now that put Marcellus into the air crow [ph] system. And I expect air crow [ph] ultimately lead to the opportunity to bring some gas into the system. Well -- it make into and in our ANR and we'll be working to bring in -- bring as much as we can to Great Lakes and then into our system as well on that one, too. So I guess that's another route, but I think, if people really want to get they'll on the triangle, they probably come in to go Niagara and especially with our LDC settlement now, where we're we are committing to de-bottleneck that bottom part of the triangle, I think you'll see lots more large part of Niagara great in imports system. That Niagara system, really when it was on export, it was over 1 BCF a day, so it's -- there's quite a lot capacity still there for Marcellus and Utica.

Okay. Thanks, Karl. I think at this point, we will head for about a 20-minute mid morning that. If I could ask people to be back here at about 25 to 11:00, that would be great. Again, I'd highlight, Karl, as well as Dean Ferguson and Steve Clark, who work with Karl on the natural gas pipeline side of our business will be available for Q&A through the remainder of the morning. Thank you.

[Break]

David Moneta

Sorry, if I could just ask everybody to maybe take their seats so we can just resume here. Okay, Alex, I guess I'd ask Alex Pourbaix to join us again here at the podium. Alex is going to -- you heard from Alex earlier this morning obviously on oil. He's going to spend about the next half and hour or so giving you an overview what's going on in our Energy business and then as highlighted earlier today, that will be followed by Don Marchand, our CFO, who will provide a finance update. And with that, I'll turn it over to Alex.

Alexander J. Pourbaix

Thanks, David. Good morning, again. I imagine, you're all reeling, I know I am reeling from my comprehensive oil talk. I'll try to be a little briefer this time. I thought I'd start up first just talking a little bit about energy strategy. And this energy strategy is really -- it's been in place for a number of years and that is very simply growing the stable power business with assets that are underpinned by long-term contracts, combined with thoughtful investment and assets that sit low on the cost curve in their market. And before going into further detail, I thought it be worthwhile to quickly highlight the overall macro picture for power demand growth in the North America.

Demand, I think, generally, you see most commentators expecting demand to grow for power at a rate of just over 1% per annum. But I think more importantly, we see the majority of this growth being fueled by new gas-fired generation and renewables. These 2 fuel types are both areas where we have a strong expertise and where we see a significant potential for continued capital investment.

Within our overall strategy, there are 2 key principles that we follow. Number one, we are focused on developing low-risk greenfield projects backed by long-term contracts with high-quality counter-parties or acquiring low-cost base-load generation assets in key power markets; and number two, we sell forward certain amounts of our merchant capacity, which helps to reduce volatility and protects us against the downside to our future revenue streams. We also manage all elements of our business by actively participating in regulatory developments and policy changes.

And with those principles in mind, our strategy is focused specifically on capturing new opportunities in Alberta, from growing power demand and also longer-term from coal retirements that have now been legislated by the Canadian government. We're pursuing growth from the ship to gas-fired and renewable generation in North America, and for us, North America includes Mexico. We'll also be focused on future opportunities stemming from nuclear refurbishments in Bruce and some -- I'll spend a little more time directly on that in a few minutes.

And finally and most importantly, we are always striving to maximize the value of our existing assets and we have very much found that focusing on asset optimization is by far the best way to capture increased earnings and cash flow without further capital investment.

So let's take a look at our portfolio. Today, our portfolio consists of 20 power plants, just under about 11,000 megawatts, making us, as Russ said, the largest private-sector power company in Canada. And I think for just about all of our assets, they're very much considered critical infrastructure in the markets that they serve. Our portfolio consists of low-cost base-load generation and facilities backed by long-term power purchase agreements with strong credit-worthy counter-parties. Bulk of our assets, about 52% are gas-fired, 15% are our coal entitlements and the remainder of approximately 1/3 is made of a mix of emission-free energy sources, which includes nuclear, hydro, wind and solar, and in addition to the power business, the Energy business is also responsible for owning and operating 156 Bcf unregulated natural gas storage in Alberta.

While our energy segment hasn’t received the same amount of attention as our oil and natural gas pipeline segments over the past year, I think there are several accomplishments that have occurred which are going to contribute to the company's bottom line for years to come. First, with the restart of units 1 and 2 and the completion of the life extension at units 3 and 4 at Bruce. We returned that site to an 8-unit site in April, the first time in over 2 decades that, that has been the case. The past year, we also added to our portfolio of emission-free energy with the acquisition of the first 3 of our Ontario Solar facility, total -- a combined 26 megawatts. All of these under 20 year PPAs.

Last December, we finalized the PPA for Napanee with the Ontario Power Authority and if you recall, this is a replacement contract for the Oakville power plant that was canceled, and since then, we've continued to work on the planning and permitting of this new 900-megawatt plant. The 2 Sundance A coal units have recently returned to service. Unit 1 came back in September and unit 2 came back in early October. Obviously, this capacity is going to meet growing power demand in Alberta with -- and finally getting us back to 560 megawatts that we are entitled to under the terms of our PPA. We also acquired the remaining 40% interest of the CrossAlta gas storage facility from BP late last year. And finally, we continue to improve the operational performance at Ravenswood. Continuous enhancements in our maintenance program have led to reduced [indiscernible] and improved the overall plant performance.

So let's talk for a second about the priorities in energy going forward. Our first priority is going to be to continue to maximize the value of our existing assets much like the work I just talked about at Ravenswood. Safety and reliability are key to our operations. And operations and our engineering group are continuously looking to improve the availability performance across our entire fleet, and our commercial teams are always looking for opportunities to maximize revenues within acceptable risk tolerance. Second, integrating the remaining Ontario Solar projects into our portfolio. Third, we're focused on bringing the Napanee facility into service on time and on budget. And lastly, we continue to pursue additional development and acquisition opportunities in our core markets. I'll touch more in the last point later, but now I think I'll spend a couple of minutes talking about Bruce.

So I said today, the Bruce Power complex is operating all 8 reactors, capable of producing 6,200 megawatts of clean and reliable energy into Ontario's power grid. It represents about 30% of Ontario's electricity demand by megawatt and significantly more that in terms of actual power produced. All of the power produced at Bruce is sold under long-term contract with the Ontario Power Authority. And while the restarts of units 1 and 2 took longer to return in service than we had hoped, we are now starting to reap the benefits of this investment.

And if you recall, units 3 and 4 also underwent prolonged life extension outages last year and the work on the last unit finally wrapped up this past April. With Unit 4's return, as I said, we now have an 8-unit site that is capable of generating power until close to the end of the decade. As result of having 8 operational reactors, Bruce's equity income is forecast to far exceed levels we have seen in recent years. And outside of regularly scheduled maintenance events, this increased financial performance trend is expected to continue. Bruce is also a vital part of Ontario's energy future and an essentially part of Ontario's plan to phase out coal-fired generation.

We believe that the Ontario government's recent announcement that their long-term energy plan will no longer include new nuclear builds, positions Bruce very well for future refurbishment opportunities in the latter half of the decade at compelling cost for this energy compared to other alternatives. Nuclear refurbishments at Bruce are a longer-term opportunity and the focus right now will be to maximize the cash flow and earnings from this investment. We have learned a lot from the refurbishment and the restart of units 1 and 2, but having said that, we would look to alternative commercial arrangements on any future refurbishments and we would also need to be compensated for the loss of the cash flow in the event that refurbishment of these units occurs before the end of the useful lives.

So let's take a look at the production outlook for Bruce over the next 5 years. Our share of Bruce Power's generation in 2013 is expected to be close to 18 terawatt-hours, well in excess of the 12.7 terawatt-hours produced in 2012. Production is expected to be slightly higher in 2014. Before that -- before the facility undergoes a vacuum building outage for Bruce A in 2015 and 2016 for Bruce B, these outages are necessary for the overall support systems for Bruce A and B and they will each consist of outages of 4 units at a time for roughly 30 days. After 2016, production is expected to rise back in 2017 to approximately 20 terawatt-hours. As you can with the production outlook, we expect to generate significant earnings and cash flow from our investment in Bruce Power for years to come.

Sticking in Ontario for the moment, we also continue to progress our $470 million acquisition of 9 Ontario Solar projects, and as I mentioned earlier, we've now acquired 3 projects so far this year from Canadian Solar. The remaining 6 projects are expected to be acquired in various stages between late this year and 2014, and just to remind everybody, the purchase of each project occurs after they begin commercial operation and each of them are subject to significant milestones and performance tests. All of the output under these facilities are sold under 20-year PPAs with the Ontario Power Authority.

Let's turn to Napanee, our other major growth prospects in Ontario for a brief update. As I said last December, we finalized the 20-year PPA with the Ontario Power Authority for this 900-megawatt facility. It's a $1 billion project. It's going to be sited at OPG's existing Lennox site, which is situated close to both natural gas and electric grids and will be a great addition to our portfolio of long-term contracted assets once completed. Work on the facility design, stakeholder engagement and permitting activities are progressing and we expect to receive our construction permits in the fall of next year. Moving into next year, we'll need to make some decisions before receiving our permits on when to order some of the long-lead time equipment like the steam generator, and depending on this decision, we are presently looking at a 2017 or 2018 in service date for the facility.

I want to move to Alberta. Alberta is very much a core market for our business and as you can see from this supply and demand outlook, it is probably the fastest growing demand region in North America. Oil and gas development, particularly the oil sands, are driving economic and power demand growth in the province. The Alberta Electricity System Operator is forecasting peak demand to grow at an annual rate in the province in excess of 3%. This is roughly equivalent to adding about 450 megawatts each year of demand for the system. The AESO is also forecasting that Alberta will fall below a 15% reserve margin in 2016 and new generation is going to be required even with the Shepard facility being built and the recent return of the Sundance A units. And just for those who don't specialize in this business, the reserve margin is the ratio of installed capacity to peak load and it's a critical measure to ensure the electrical system can meet peak demand load, and over the years, 15% has kind of -- come to be recognized as kind of the lower safe level that you want that reserve margin to sit at.

We remain very well positioned with our large Alberta power market exposure to take advantage of market conditions which are likely to create more volatility as supply becomes tight. In the medium to longer term, the new Canadian federal government policies on coal plant retirements means we'll also see the first wave of retirements starting to occur around 2020. As over 800 megawatts of coal plants start to reach the end of their life in the 2020 timeframe, we believe these facilities are likely to become less reliable as it will be uneconomic for their respective owners to spend new capital to maintain them due to the federally mandated shutdowns, something that we think we've really been seeing a lot of over the past couple of years in Alberta. This situation is likely going to create opportunities for new generation investments and we also believe it's going to create increasing pricing volatility from unplanned outages from an aging coal fleet in Alberta's energy-only market.

I though I would just talk about New York Zone J capacity for a second. New York capacity market is where our 2,500-megawatt Ravenswood facility captures a significant portion of its earnings. You might recall, last November, the Astoria II facility failed the new mitigation exemption test that the FERC ordered the New York ISO to redo. The outcome of this event and last May's change to higher locational capacity requirements led to higher capacity prices which averaged just over about $16 a kilowatt-month this past summer. The most recent November spot auction, which is the first month of the 2013, '14 winter season, saw capacity action clearing at $10 a kilowatt-month, which is also very encouraging.

Heading into the summer of 2014, we expect capacity prices are going to be impacted by the results of the demand curve reset. The update process includes New York ISO filing new parameters with FERC later this year, and I think I would say, it's unclear at this point where the actual market and price impacts will be until the new demand curve parameters are filed. In addition to the new demand curve reset, there is a 660-megawatt Hudson cable project, we believe is ultimately going to enter the Zone J capacity market. It will also be mitigated -- and it's going to enter once various transmission upgrades for the PJM market are completed and delivery rights into the New York ISO are established. There's also, I think from tempering said, it's art about potential for the return of maybe 100 to 200 megawatts recently mothballed capacity. That capacity is probably looking pretty attractive given the recent run-up in capacity payments. And finally, I would say there's still some uncertainty around the net effect of these factors. Generally, we believe that capacity prices for Ravenswood heading into 2014 will remain constructive but they're-- and they're very unlikely to return to the prices we were seeing before 2013.

Turning now quickly to the storage business. Obviously, as people are aware, Karl talked about it a little bit, natural gas spreads are currently experiencing cyclical lows. As you can see from the chart on this slide, we're currently seeing 2014 forward summer-winter spreads in the high $0.20 range for GJ, which are significantly below the averages seen so far in 2013 and well below the spread range levels that we see is necessary to support the economics of new storage built in Alberta. Despite the lower spread, these assets are still providing a very good return with approximately $600 million of net book value, our storage assets continue to provide good return on our investments. We see very little downside to spreads from where there are today, and we fundamentally like the long-term value of storage has been a critical piece of necessary infrastructure in order to balance future growth and demand for natural gas, as well as potential for the export of LNG, both in the U.S. and from the West Coast and Canada.

So much like our other presentations you've seen this morning, and I'd now like to share with you the outlook for our Energy business in 2020. With just over 11,000 megawatts of capacity coming from 20 plants, EBITDA is expected to grow from about $900 million in 2012 to approximately $1.5 billion by the end of the decade. Growth in contracted EBITDA is expected to increase over 50% by 2020 from 2012 levels. We have already begun seeing some of the increases here from the restart of units 1 and 2.

Other future growth in contracted EBITDA comes from the projects I spoke about earlier, namely Ontario Solar and Napanee. These long-term contracted assets will help reduce the amount of variability in EBITDA and increase the predictability of our Energy business in the future. I think it's important to note that the numbers behind this chart include capacity prices of around $12 per kilowatt-month in Zone J, which are comparable to prices today. It also assumes the low $60 power prices in Alberta and also reflects the termination of the Sundance A PPA at the end of 2017.

Of course, as broken EBITDA is not near the levels expected from our oil and gas pipeline segments, so let me spend a quick minute where we see future growth opportunities coming from. We've always had excellent power development opportunities both on the greenfield and acquisition fronts. I just personally believe we happen to be in a certain point in the cycle where we've been able to capture more attractive investment opportunities or maybe even more to the point, more immediately strategic opportunities from oil and gas pipeline projects. Our focus right now is to continue to cultivate a portfolio of development opportunities as we see opportunity to add solid investments to our current capital program.

We believe that a lot of these opportunities are likely to come from growth in natural-fired gas and renewables. And over the long term, we're also going to focus on nuclear refurbishments at Bruce, as well as interest in -- that we've indicated in entering the power transmission business. We also see opportunities for M&A and as usual, and for us, we're going to be opportunistic and disciplined when it comes to future acquisitions.

So I thought I'd wrap it by just leaving you with a couple of few takeaways. First, we continue to build a stable power business by adding new assets that are underpinned by long-term contracts or that are extremely competitive in their markets.

Our focus right now is to continue to cultivate a portfolio of development opportunities as we see it, opportunity to add solid investments to our current capital program. We believe that a lot of these opportunities are likely to come from growth and natural-fired gas and renewables. Over the long term, we're also going to focus on nuclear refurbishment at Bruce, as well as interest in -- that we've indicated in entering the power transmission business. We also see opportunities for M&A, and as usual, and for us, we're going to be opportunistic and disciplined when it comes to future acquisitions.

So I thought I'd wrap it up by just leaving you with a couple of few takeaways. First, we continue to build a stable power business by adding new assets that are underpinned by long-term contracts or that are extremely competitive in their markets. Our strategy of building a strong asset base with stable and predictable earnings will continue with $1.5 billion of new assets coming into service with the remaining Ontario Solar projects in Napanee. Our Energy portfolio is further augmented with the recent return of the Sundance A Units, which adds over 500 megawatts of capacity back into the Alberta market. And finally, we remain well positioned to capture future growth opportunities, and we see no opportunities -- no shortage of investment opportunities.

So thank you very much. That's my prepared remarks. I hope I got through it a lot quicker than the oil side. If anyone has any questions, I'd be happy to take them on. Yes?

Unknown Analyst

Yes, gas prices can be very volatile [indiscernible]. Gas prices can be very volatile. I'm just wondering, is TRP exposed the margins to jump in gas prices from the power business to get long-term contracts and move up the buying side?

Alexander J. Pourbaix

So the long-term contract stuff would be immune from any of that risk. And on our merchant assets, because -- particularly the coal assets in Alberta and the merchant gas assets stand at a very efficient deep rate and the coal, obviously, is not tied to gas. So generally, when we see an increase in gas prices, we actually see an increase in profitability from our unit. So that would work -- that would be the case in Alberta and the case in New York. So generally, a rising gas prices for the power business usually corresponds with an increase in profitability.

David Moneta

Go ahead, Paul.

Paul Lechem - CIBC World Markets Inc., Research Division

Paul Lechem, CIBC. Just want to try to understand what the message is around your slide about the dynamics in Alberta showing seemingly positive dynamics towards the end of the decade, but then kind of square it away with your comments that you'll would look for contracted assets given the structure of the Alberta markets. How are you looking to play this potentially positive opportunity there?

Alexander J. Pourbaix

Yes. Well, Alberta is kind of a -- I think the general view, it is fair to say, that our interest are, for the most part, looking at contracted assets. I think Alberta is a bit of a special case situation. We've developed this very significant position in the market, a lot of market expertise, and we have built this very attractive business. It is a merchant market. I don't believe there's much of likelihood that it's going to turn into a contracted or in capacity market in the near future. So I think we're going to have to think hard about how we can participate. And then maybe, ultimately, this company has some appetite for merchant assets in a market like Alberta, which we understand so deeply and we have such ability to influence the way the market ultimately goes. But I think it is unlikely we're going to see a significant market design change in the next, sort of, 3 to 4 years.

Paul Lechem - CIBC World Markets Inc., Research Division

Okay. And then just one quick follow-up in Alberta. You have -- on one the last slides you say you have interest in power transmission. There's obviously transmission assets in play in Alberta right now. What's your level of interest in that and participating in, more broadly, in Western transmission?

Alexander J. Pourbaix

We have been looking a way to enter the transmission business for many years. I would say this, we have found that it is relatively difficult to enter as new entrant. It gets tough to displace incumbents in the transmission business. We are looking at the competitive tendered processes. We obviously looked hard at Ontario, Alberta has a similar project going forward. The asset you were talking about, it's up for sale. I think that's going to be a very competitive process, but at the same time, I think it's a very attractive asset. So I think we'll obviously take a very close look at it.

David Moneta

Go ahead, Andrew.

Andrew M. Kuske - Crédit Suisse AG, Research Division

Andrew Kuske, Credit Suisse. Alex, how do you think about your strategy for power in the U.S.? Do you want to remain very regionally focused and enhance the footprint in the Northeast, or you're looking for some other opportunities elsewhere? You talked a few years ago about the Desert Southwest, you've got Coolidge there. So how did you really look to build upon that and how much capital would you allocate to those businesses?

Alexander J. Pourbaix

I mean, I think I would say, in the U.S., we're always looking for opportunities in the Northeast around our existing assets. That haven't seen a lot of compelling opportunities there over the last -- a little while. We are very interested in the Desert Southwest. We still spent -- we're spending a lot of time there. I see that play for obvious reasons, being more of a renewable play. And a lot of kind of the opportunities we're seeing in the U.S., to be honest, are renewable-type opportunities and tend to be backed by long-term contracts. So that's a lot of what we've been focused on over the last couple of years.

Andrew M. Kuske - Crédit Suisse AG, Research Division

So I guess the argument would go, if you've got longer term contracts in place with utilities or other counterparties that you don't really need critical mass than anyone getting the market region because you've got contractual protection?

Alexander J. Pourbaix

Yes, but -- I think you could say that, from our own perspective, we don't like to be scattered over the entire 50 states and that's why, to this point, we have this sort of base of operations in the Northeast and then we Coolidge in the Southwest. We would very much like to be able to grow that business around Coolidge as kind of our initial ball in play in that market.

David Moneta

Carl?

Carl L. Kirst - BMO Capital Markets U.S.

Alex, Carl Kirst from BMO. I just wanted to focus back in on Bruce B for a second and wanted just a clarifying question, when you're giving the 2020 EBITDA, does that have any of the Bruce B units in them right now? Because I was unclear what the current useful life is when that falls off?

Alexander J. Pourbaix

Yes, the numbers that you're seeing up there, Carl, would include the Bruce B units, operating, of course, somewhere in 2020. Post 2020, they will start to reach the end of their useful life. So at this point, what you're seeing out there is an A unit site.

Carl L. Kirst - BMO Capital Markets U.S.

Great. And then, Alex, you'd made a commentary as far as relatively cheaper economics. Is that something you can roughly zip code an investment opportunity where the half of Bruce A or...

Alexander J. Pourbaix

Yes, here's -- Carl, here's kind of the way I would look at it. We believe that if we were to refurbish Units 3 through 8, knowing what we know and learning what we learned through the Bruce 1 and 2 refurbishment, we could probably do that at a significantly lower capital cost. But for the argument of -- or for the purpose of kind of calculating $1 per megawatt-hour, if we assume that the capital to refurb 3 through -- the Units 3 through 8 is the same as the capital for 1 and 2, and we apply kind of expected rate of return, which is not the one that we achieved with Units 1 and 2, but return we would expect to achieve for doing that kind of work, we're looking at kind of a power price in the mid to high $60 range coming out of those units. So we look at that, and that looks very, very competitive to any gas options, and it comes without any GHG, so we think it has a lot of attractiveness to the government. And on top of that, I think everybody would understand the nuclear industry is a pretty important industry to Ontario and it also has that benefit of continuing that industry in Ontario, which I think why we've seen the government still put a focus on refurbishments as the opportunity they're looking for.

Carl L. Kirst - BMO Capital Markets U.S.

And when do those conversations begin or have they already begun?

Alexander J. Pourbaix

We're always talking. I don't think we feel any need to immediately descend into negotiations. I think the first thing -- one thing that has been going on for the last, really, for the last year or more is we're going through a very exhaustive lessons-learned process at Bruce. We're pretty much through that in Bruce and we and our partners think we really kind of finalized the lessons learned. And then I would see, if you think about these units coming to the end of their life around the end of the decade. And then one of the challenges in Ontario is that a lot of these nuclear plants do then come to the end of their life around the same time. So there has to be some discussions that would take place, I don't know, within 2 or 3 years about sort of how you're going to phase them and are there deals that make sense to people. But we think we have a pretty nice runway where don't have to be fixated on this issue in the short-term.

David Moneta

Carl, I think you said [indiscernible] -- or sorry, Alex.

Unknown Analyst

Agency. Can you expand a bit what your potential Mexican plans? Obviously, you have a nice pipeline business. Obviously, you have the -- is this just part of the energy reform that they've announced? Are they -- at this conjunction, is this brownfield, is this new expansion?

Alexander J. Pourbaix

I think it is primarily greenfield. There has been some talk about brownfield opportunities. But I -- now that we have this significant position in Mexico, we are feeling a lot more comfortable about participating in the process. I would tell you, we took a very close look at Mexico about a decade ago, and at that time, we found that the returns that were being bid to these projects, we just felt we could deploy capital more profitably in the U.S. or Canada. And so we worked really into -- at that time we made the decision to just sit back on the power side. We're now seeing a lot of opportunities appear to be coming forward on the power side. And we think, with our very strong position and relationships in the country and our demonstrated expertise at building gas-fired power plants, we think there's a real opportunity there. And I would couple that kind of I think, over the next year to 2, we'll have -- I think everyone in this room will have a pretty good feel as to how successful we've been or not been in that business. But we're pretty optimistic.

David Moneta

Sorry. Go ahead, Robert?

Robert Kwan - RBC Capital Markets, LLC, Research Division

Robert Kwan, RBC. Alex, just going to Alberta power market or Alberta capacity development, the historical strategy has been to be at the low end of the cost curve, which, theoretically, when we did combined cycle or cogen. Just wondering though, it sounds like part of your long-term piece of that is with the aging coal fleet. Do you expect price spiking, which then lead to the [indiscernible]. Can you just talk about where you see your thoughts on development trends there?

Alexander J. Pourbaix

Sure. Yes, I think I was sort of a pretty clear in our views on that. We are reasonably concerned about the availability of Alberta's coal fleet over the coming decade. We -- I think our experience with the Sundance A arbitration really brought home that if these coal units come to the end of their lives, there is a bit of a perverse situation going on where the owners of these facilities, as they approach the end their life, they may not be incentive to put in the capital that's required to make sure they're running at top levels, given that they're coming to the end of their lives. So I just -- I think we've seen a bit of that at this point. We expect we'll probably see more of that. I would say, when it comes to technology we're looking at -- a few years ago, we were very much looking at combined cycle technology. We still think there's an opportunity for that. Lately, as I look at the market and we run the numbers, peakers actually look to be potentially very attractive units in the Alberta market. That's actually exacerbated with -- we're just getting this increasing market which is characterized by -- when everything's operating well, the wind is blowing and the temperature is moderate, we have pretty low prices in Alberta. But we have this massive spikes and we expect to see more of those as the market tightens, coal gets older, and peakers potentially might be the answer in that kind of a market going forward.

Robert Kwan - RBC Capital Markets, LLC, Research Division

I did the 2016 window and, call it, 2020-plus window. Just wondering where you think the development opportunities are going to follow suit?

Alexander J. Pourbaix

I -- the areas that the people in power are focused on -- we've agreed on a few strategic priorities in the short term. I think Mexico is a significant priority for the team over the next couple of years. As we get nearer to the term of the PPA is expiring in Alberta, certainly from my perspective, we have built up this incredible capability in the Alberta market, so it's very a priority that we find a way to be able to continue that business after the PPA has expired. And then just, I would say, on the renewable side, most jurisdictions, most utilities are still very interested in renewables. We haven't been very active for a few years, only because we didn't see the returns, people were bidding very low. We're seeing potential development opportunities and maybe, potentially, down the road, some M&A opportunities.

Robert Kwan - RBC Capital Markets, LLC, Research Division

Alberta, would your strategy be go alone, 100% ownership or looking for partners?

Alexander J. Pourbaix

Sorry, I didn't...

Robert Kwan - RBC Capital Markets, LLC, Research Division

Would you be looking for 100% ownership or would you be interested in a partnership?

Alexander J. Pourbaix

We've always been a company that has liked to own and operate our assets 100%. I think in a market like Alberta where they're very capable -- we have some very capable competitors and potential partners, I think we'd be open minded if there's an opportunity there to partner.

David Moneta

One more for Alex here, and then we'll turn it over to Don. Steven?

Steven I. Paget - FirstEnergy Capital Corp., Research Division

Alex, it's Steven Paget, FirstEnergy. You said you look at a stronger presence in the U.S. Desert Southwest and mostly in renewables, but could that include becoming a purchaser and reseller of supply like you are in the U.S. Northeast?

Alexander J. Pourbaix

The idea of just being a pure kind of marketing kind of player retail provider of power, that business is a standalone business. I don't think there's a lot of attractiveness to TransCanada. As an add-on to an asset-based business, we think it's great at adding profitability around the edges of that business. But, Steve, I think it's pretty unlikely we'd just get into that business from a purely marketing perspective.

Steven I. Paget - FirstEnergy Capital Corp., Research Division

So what does keep TransCanada in the power resale business? I mean, wouldn't -- I mean, assuming there's money to be made or buyers starting to contact sellers more directly, or you're not seeing that?

Alexander J. Pourbaix

It's interesting. In the Northeast, it's -- that wholesale business and actually been -- sort of that industrial commercial marketing business is actually -- it kind of ebbs and flows, but it's typically have been quite a -- we found that we've been able to add significant margin to our results by being in that business. I think the thing about that business is you have to be disciplined not to chase it. And over the past year, we've seen a bunch of marketers kind of jump in and try to take market share, and my advice to the team, and I don't really need to give any advice anyway, is we just have to be disciplined and let that business go when someone wants to buy it. So you see a bit of kind of coming and going. The good news is, we find when guys come in and buy the market, they tend to be gone a year or 2 later, and then we have the opportunity again. So it's just -- it's being -- it's knowing what your goals are and just being disciplined about it.

David Moneta

Okay. Thanks, Steve. Thanks, Alex, and we'll turn the podium now over to Don Marchand, our Chief Financial Officer. Don is going to provide you with an update on the finance.

Donald R. Marchand

Good morning, everyone. Pleasure to be here, as always. We'll spend the next 20, 30 minutes here, trying to pull all the numbers together and outline for you how we're going to tackle the financing of this tremendous opportunity set ahead of us here.

Looking back, it's been a tremendous year of progress. As you've heard over the course of the morning here, we've seen a number of assets come into service, namely, Bruce coming back, significant expansions on NGTL, as well as 3 solar projects. We have resolved some outstanding matters, and Sundance A is back. We have the mainline decision, the LDC settlements, as well as settlements on NGTL in Great Lakes. And we've landed $19 billion or $20 billion of extremely high-grade projects, which will complete over the course of the decade here. If I had one disappointment in the course of the last year, it's that no visionary banker has actually pitched a big coin transaction to us around. So we look forward to the inbox, going up on that later.

So looking into 2014, we do have a substantial amount of momentum. Again, we have -- and again, on the unit side Bruce, we have brought the volumes, so Sundance is back, constructive capacity market in New York, the Gulf Coast Project, the Tamaz extension, further expansion on NGTL, and 6 or more solar units coming on. We do have some uncertainty, as Karl alluded to earlier, on our U.S. gas pipeline business, which we hope to see stabilizing here shortly. And we are facing a comparative power price now in Alberta that probably has something like an $80 handle on it. But all in, it is a very positive sense of momentum.

Looking further out, highly confident in our $38 billion asset program here, and we believe we're very well-positioned to fund that going forward, and I'll spend the few minutes outlining that.

It's important to just go through the tenets of our financing strategy, which haven't fundamentally changed over the years. They're embedded in 2 corporate poles, one is longevity of our asset base and the capital that funds it. And secondly, the simplicity and understandability of our structure and our funding programs. Unless we see a clear reason otherwise, we are firm proponents of financing on balance sheet and from the center, and keeping things as simple as possible.

Looking down in the specific elements of the strategy here. We invest in long-term annuity streams, cost of service businesses. And where we have market risk, we keep that contained. It's generally low-cost baseload of power assets. And on top of that, we layer on the active hedging programs from more certainty of revenue.

We financed that with long-term capital, we have $20 billion of book equity. The average term of our debt is 12 years, and that gives us a high degree of visibility to the biggest input cost to our business, which is the cost of money. When you factor in high confidence or high visibility of revenue streams and your biggest cost item, you can lock in a margin and the goal is to repeat, repeat, repeat, over a growing asset base.

We never compromise our long-term prospects for -- due to short-term events. We try to preserve our ability to act on all points of the economic cycle. The lessons from the fall of 2008 remain with us, although we were one of the few corporates in North America that did not draw its bank lines and head for market access to that period. An important element to that is, obviously, the A grade credit rating. It allows us access, pretty much continues, in the markets. I mean, it minimizes our costs, allows us to issue across the terms of spectrum and for size, it differentiates us in times of economic stress. And I believe in dealing with counterparties, as we are doing now that are seeking a partner to do business with for 20, 30, 40 years into the future.

We're active managers of our FX exposures. We seek out natural hedges in terms of the U.S. dollar debt and have active programs on top of that. It would take about a $0.10 move in the Canadian-U.S. dollar to impact our earnings by $0.01 looking forward, over the rolling 12-month horizon. It's generally what we managed to. I'll talk a bit more about interest rate exposures a little later, but we are predominantly a fixed-rate funder. And counterparty risk management has been the core strength of the company for many, many years, and it's increasingly important as you see contract of nature of our portfolio.

So where we are today? Funding for this year is complete, and we've actually started pre-funding a portion of 2014. We completed a $4.75 billion of capital markets funding this year. In terms of our small- to medium-sized projects, we would categorized approximately $12 billion of them as being of that nature. We have extended just under $4 billion on that portfolio to date. The balance of the funding program is manageable and our funding levels are expected to remain attractive through the course of that built-out.

In terms of our large-scale projects, these are total $25 billion: Energy East, the 2 West Coast LNG lines in the balance of Keystone XL. I will walk you the funding levers for that little here on the presentation. Maturities for 2014 '15 are benign, they total about $2.4 billion. And in terms of the credit rating, we target A grade credit metrics, where it's predominantly cash flow rather than balance sheet in nature. We target a minimum 15% funds from operations to debt, minimum 3x funds from operations interest coverage. That's based on our current business risk, and I would pause that our business risk, actually, will improve over time here, as we complete the $38 billion program with large security revenue streams and increased diversity.

In 2013, we will spend approximately $5.3 billion over a diversed array of assets, the biggest ones being Gulf Coast, NGTL Mexico, Alberta oil projects and some solar acquisitions. Included in that number is about $275 million of capitalized interest. Funds from operations, after paying dividends and distributions, will amount to about $2.5 billion. As Karl mentioned earlier, we raised about $900 million of cash by dropping 45% of GT and the Bison into our LP back in midsummer.

We did a $600 million preferred share issue in early March -- I guess, early spring here, midwinter in Calgary. It's -- that was done at a rate of 4%. That was the largest preferred share deal in Canadian history at that point in time. We did redeem a $200 million issue at preferreds in October, which carried a dividend yield of 5.6%. So a net $400 million of pref issuance this year.

On the debt side, $3.25 billion of term debt, and we had about $850 million in maturity. So a net $2.4 billion of term debt funding this year. When you add all that up, it amounts to about $6.2 billion in, versus the $5.3 billion out. So we have started pre-funding a portion of 2014. And one of the reasons for that is that our maturity profile next year is front-end loaded with heavy maturities in January and February.

In terms of funding sources, currency-wise, about 70%, or $3.4 billion, was U.S. dollars denominated. We do have a bias to U.S. dollars as a natural hedge, all else being equal, primarily pricing. Our asset base in the U.S. is growing from about $3 billion when we acquired GTN, approximately 10 years ago, to $18 billion today and growing. So again, the bias remains to U.S. dollars. And I would note that our Mexican business is a U.S. dollar-denominated business in terms of revenue streams and its functional currency.

On the right-hand side, the diversity of funding is quite evident here. Aside from the currency, we tapped the institutional market on both sides of the boarder. The retail market in the U.S. through NLP offering, the retail marketing has the preferred shares, as well as the bank market for a portion of the LP drop-down funding. Product wise, again, senior debt preferred shares, floating-rate notes, LP unit, so a diverse of rates there. In terms of the $3.25 billion of senior debt raised last year, it was done for an average term of 13 years at an average coupon of 2.6% pretax.

Looking at the balance sheet on the left-hand side here, it remains strong. It's about $18 billion of common equity, including noncontrolled interests, a $1.8 billion of prefs and $1 billion of junior subordinated notes supporting the senior debt. We have no specific target on the balance sheet. It is really -- it really triangulates in the A credit rating cash flow metrics. So it gravitates to a 40% equity, 10% mezzanine, 50% senior debt structure by default. That also supports the 40% equity that we are accorded by Canadian regulators for our regulated assets here.

On the right-hand side, cash balances are healthy, and they were supplemented by $1.25 billion U.S. issue, completed in early October. It's the second day of the U.S. government shutdown, and the value of the A rating kind of showing through there. We had an order book of $7 billion within a few hours on that transaction.

Funds from operations remain robust. Last quarter, third quarter of this year, it's the first time we've had funds from operations exceed $1 billion in our history. The debt maturities that I mentioned are manageable. We make a conscious effort to avoid debt maturity towers, we try and spread out the maturities over time. $4 billion of committed bank lines with a blue-chip group, many of which have had relationships with us for -- going back several decades. This is something we would look to bolster as the build program gets bigger to support greater liquidity in the system here. We also have a $1 billion of demand lines on top of this.

Commercial paper remains a very attractive source of funding. We fund in Canada at [indiscernible] plus 10, or about 1.2%, and then the U.S. programs at LIBOR plus 10, or about a 0.4%. In terms of shelf, we have a $2 billion net shelf in Canada. We will soon be filing a USD $4 billion replenishment of our U.S. debt shelf, and we have a $1.4 billion remaining on our TransCanada Corp equity shelf. That is primarily designed to support the issuance of preferred shares, and it's something, again, we will be replenishing here over the coming quarter or so.

This is very topical right now, the exposure to interest rates. We acknowledge we don't control rates, but to the extent we can position ourselves commercially to buffer ourselves, that's what we're doing. The first major buffer is cash flow. It's predictable, is growing and it is not interest-rate sensitive. On top of that, our debt is very long duration and predominantly fixed rate. We have under 10% floating-rate debt in the system. And again, the average term of the debt is 12 years.

In terms of economics on future projects, we don't bake in these current historic low rates. We factor in something that's more of a midcycle rate when we are assessing our economics for new opportunities. Offsets and cushions within the company, a sizable portion of our debt is flow-through and are Canadian regulated pipelines, so that any incremental cost from rising interest rates is passed through there.

The ROEs on our regulated pipelines have historically been correlated quite closely with interest rates. So as they came down, interest rates, we would expect them to rise in interest rates. We do have commercial mechanisms in place on some of our new projects where we are cushioning somewhat if interest rates go up. And if rates go up accompanied by inflation, we do have a significant cost passthrough capability on many of our assets. We do have cost-sharing mechanisms in place for many of our new projects and we do have things like a CPI tracker at Bruce, where revenues would increase along with inflation.

So just looking at the overall portfolio projects here. In terms of the color scheme, I'm not sure you if you had caught on earlier that the brown, blue-green isn't the fish vegan, it's actually oil and gas energy. The scale of these projects is not quite exactly to scale here, but our indicative of the general size of these projects. The conveyor belt aspect to their completion it's not quite as linear because there are a lot of step change, large-scale projects to come on stream here. But when you layer up the $38 billion over the balance of the decade, this is the kind of profile that results from it.

A couple of observations here, I look back over our presentation of the past couple of years, and 2 years ago, Keystone XL was $7.8 billion of what was a $12 million growth portfolio at that point in time. Last year, it was $5.4 billion. We have split up the Gulf Coast Project of what was a $22 billion portfolio, and now it's $5.4 billion of a $38 billion portfolio. So -- well, an exceptional project that we fully expect to move ahead. It is not the only game in town, and is actually now dwarfed by the balance of the portfolio there.

So for the balance of the next few slides, here, I'm going to bifurcate this into 2 component parts. One is our portfolio of cost, small to medium-sized projects that more of a normal-course approval sanctioning element to them, and a very high degree of certainty as to our spend profile on them. And secondly, the megaprojects, the very large-scale projects that are all approaching key stage gates in the next few quarters and years here. It's difficult to precisely assign the spend profile by time bucket, so we'll talk about them more collectively over the course of the next several years.

So the -- we'll call it -- there's also the medium-scale projects, total about $12 billion. We have spent $3.7 billion to date on them, leaving us about $8.4 billion left to fund. You can see the list of them here. The revenue streams are very certain. The one that I would note is the Gulf Coast Project. As Alex mentioned, there are significant contracts on there. But there is an element of variability around the Gulf Coast based on spot volume movements and what we're able to charge to those going forward. But otherwise, very secure revenue streams. The counterparties, as you can see here, are very high quality and a very diversed group. And in terms of diversity, the profile of this is about $6 billion of oil projects, $4.5 billion of gas projects and $1.5 billion of Energy projects. And geographically, $7.5 billion in Canada, $2.5 billion in the U.S, and $2 billion in Mexico.

So we would spend approximately $10.7 billion over the next 3 years on this of slate of projects. Comprising that is GTL for about $3 billion; Alberta oil projects, $2.5 billion; just over $1 billion for Napanee and Ontario Solar plants; $1 billion in Mexico; and about $400 million to complete Gulf Coast; and some preservation spend -- momentum spend on XL, but primarily to complete the Houston Lateral on Gulf Coast.

In addition, maintenance capital amounts to about $425 million a year, so $1.2 billion, $1.3 billion. On here you will see about $800 million of development projects. These are costs we will capitalize to move forward some of our larger scale opportunities. And I would note that anything we spend on the West Coast LNG projects is fully recoverable or either through rate base or refundable if the projects do not move past that by IP.

In addition, on here is about $450 million of capitalized interest over the course of this period, and we are capitalizing interest for this purpose at a rate of about 5%. In terms of time buckets, there's spread of $4.5 billion in 2014, $3.9 billion in 2015 and about $2.25 billion in 2016.

One thing to note, there are 3 projects that come in, in post-2017, the second phase of Grand Rapids, Northern Courier, Napanee, and all but $0.5 billion for those projects will be expended within this timeframe here. Keystone XL is not included in these numbers. We do expect that it would be funded within this timeframe, and that will be $3.4 billion, which amount will go higher as was discussed earlier once we have greater clarity on timing on that and can firm up those numbers.

The funding program for these projects, again, the $10.7 billion will be funded by about 2/3 from internally-generated cash flow, just the $6.9 billion, $7 billion there. The balance of $3.8 billion or a 1/3 will come from external sources. This is aside from any refinancing maturities in this timeframe. I would note, we have no intention to issue common equity for the suite of projects. We do have a need, we'll call it, of equity equivalent of $1.5 billion to $2 billion. And that will come from 3 principal sources: preferred shares and hybrid securities, which we expect to attract about 50% equity credit for those products, and LP drop downs or any third-party equity that we issue in the form of units to -- from the LP to fund those, would attract dollar-for-dollar equity credit.

Senior debt needs over this time period are largely refinancing. Some elements of rate-based growth primarily for the NGTL System, and I would note that we have prefunded a portion of this by -- through our 2013 program.

Moving on to the large scale projects, the 2 marked key oil projects, Keystone XL and Energy East here. These numbers are incremental to the prior slides. Keystone XL, as noted, $5.4 billion was the latest cost estimate. That number will rise, and we'll firm that up as we have clarity on exact timing. We have expanded $2 billion of cash to date on that project. In terms of volumes, as Alex noted, in excess of 500,000 barrels a day for an average term of 18 years in Alberta to the Gulf Coast, and we have another 65,000 barrels a day at our Bakken on-ramp at Baker, Montana. We look at the world in terms of unlevered after-tax IRR, and both these oil projects are in the 7% to 9% range.

Energy East, $12 billion price tag, that excludes the transfer value of mainline assets. We have 900,000 barrels a day contracted for 20 years in that system, and we expect to file regulatory permits in the first half of 2014.

On the gas side, we believe we have the 2 premier LNG pipeline opportunities to the West Coast. They total $9 billion of spend. They are contracted systems, but they largely replicate cost of service Canadian regulated pipelines in terms of their commercial structures and their return profile. These assets will be fully depreciated over the life of their contracts, so there will be no tail and unrecovered capital at the end of the contract life on either of these systems. Each of them will take approximately $300 million to permit, to get our pipeline permits, and that will ultimately go into rate base or, as I noted, if the projects do not go past FID, that will be refunded to us, and the vast majority of the CapEx on these systems will occur post-FID.

So these 4 large scale projects total about $25 billion. In the funding side, as I've described, it's a very high class problem to have going forward, which we'll embrace given their very credit-supportive nature and their very strategic nature to us. So just work down the capital stack of how we see the world here. First and foremost, with the internally generated cash flow, as we get into the post 2016 timeframe, we would expect cash flow net of dividends and distributions in the $3.5 billion range and climbing as we bring new projects on. We'll issue senior debt within the balance of an A credit rating, again, 15% FFO to debt, 3x FFO to interest as the minimum metrics that we're targeting there. Historically, we have not pursued project financing with any vigor. We do have some debt at our U.S. FERC-regulated pipeline. That is more for rate-making purposes, as the regulatory channel looks to where the external capital is funded and establishing capital structure. Project financing generally brings with it increased cost, covenants and generally ends up back on credit if they are important to your business. That said, we will explore project financing in 2 specific instances here, whether the West Coast LNG export pipelines would qualify for ECA financing, export credit agency financing, we may be able to replicate balance sheet cost for that kind of debt there and will be a new source of debt funding for us.

Secondly, in Mexico, there is a finite amount of sovereign risk that we will take on in Mexico. We are not there yet, but that may be another opportunity where we would explore project financing to potentially contain that risk. Moving down to mezzanine capital, we would look to approximately 12% of our capital structure in the term -- in the preferred shares and hybrid securities. We're well established, in some cases, the Canadian pioneer of these products, and again, they attract generally 50% equity credit. We looked to the equity credit the cost, the size and the currency when we look at these specific instruments.

On portfolio management, Karl mentioned LP drop downs. We currently have about $3.5 billion net of debt book value of mature U.S. gas pipes that sit on our balance sheet right now. That is 100% of ANR, 56% of Great Lakes, 30% of GTN and Bison and their interests in Portland. As our portfolio moves forward, it would be our plan to bend this entire portfolio into the LP as a source of cash. So that is something that's stepping on the agenda here as we work through the suite of large scale projects.

In term of partners, it was mentioned earlier that we generally prefer 100% ownership. That said, we have brought in strategic and financial partners in the past, and I would note that this suite of assets, again, would be a prime investment opportunity for duration asset-seeking pension funds and infrastructure funds, and that's another thing that we would explore.

Right, asset sales, we're not emotionally tied to anything specifically in our portfolio. If there's a chance to high grade the portfolio as part of this, again, it's something that would be on the table.

Equity is last on the list here. The dividend reinvestment plan is something that we had going and something we would consider again in the future. At a 2% discount rate, we were capturing about 30% to 35% of the dividend back in cash investments. In the past, that would amount to about $400 million a year. That is the kind of funding that fits quite nicely with the multi-year large scale construction program. So again, something that would be explored. In terms of discrete common equity, I'll just tell you that the bond would be risked here and would be weighed against absolutely everything above it going forward.

So as we look out to 2020, you can see again the size of the company, the size of the balance sheet, the diversity of it. A couple of really pronounced things jump out of here, one is the size of the contracted -- largely contracted oil business and the fully contracted LNG business. And again, the small amount of variability in here, where almost 95% of this portfolio is either regulated assets or contracted.

So this a busy slide. It looks a lot like my daughter trying to explain her phone bill to me about a week ago. But this is a better new story. What we've done here is we've taken EBITDA in 2012. We layered on the $38 billion growth portfolio, and we made a couple of normalizing assumptions. and they would be primarily the inclusion of Sundance A, low 60s Albert power prices, New York City capacity prices in the $12 range, and a 10.1% return on equity for the Canadian regulated pipelines.

So starting left to right, EBITDA in 2012 was about $4.2 billion, and then that was a $64 Alberta power price, $8 capacity market in New York and some challenges in the U.S. pipeline business.

Moving right, Bruce Power and Ontario Solar should have $300 million as they come on stream. We've got $150 million increment in Western and U.S. Power, primarily from capacity prices moving to the $12 range in New York, the return of volumes at Sundance A, and the sensitivity on an unhedged basis, for every dollar power prices move in Alberta is about $10 million of EBITDA. And for every dollar capacity prices move in New York, it's about $26 million of EBITDA.

NGTL expansion and Mexican pipelines coming on, including a partial year of Topolobampo and Mazatlan in 2016 will add $350 million. And just for note, 1% change in ROE for the Canadian regulated pipelines impacts net income by about $25 million for both NGTL and the mainline at this point in time.

Gulf Coast will add $250 million, and the Alberta oil business will add about $200 million, and included in that is Hardisty Terminals, Heartlands, TC Terminals and the first phase of Grand Rapids.

If you get out to 2016, it's about $5.45 billion. On top of this, I've taken the liberty of layering on a full year impact of Keystone XL. We're not exactly sure when the timing of that is, but for illustrative purposes here, that will add about $850 million of EBITDA, bringing Gulf Coast and Keystone XL to about $1.1 billion combined at that point in time.

So from that $6.3 billion level in 2016, a full year of Topolobampo and Mazatlan adds $150 million, post that timeframe; another $250 million for Alberta oil pipes, which is the second phase of Grand Rapids and Northern Courier; $150 million from Napanee; Energy East, $1.7 billion; and the 2 West Coast LNG pipelines will add $950 million. That brings us to a total of about $9.5 billion in 2020. Again, you can see the diversity here, and the variability of that number really comes from 3 places. It's Alberta power prices, Northeast power prices, and spot movements, the ability to sell spot volumes on our oil pipelines.

Russ touched on this at the beginning, in terms of the dividend, it is a critical part of total shareholder return. Our job as management is to grow earnings on a sustainable basis to allow our board to increase the dividend in conjunction with that. Historically, we've been in an 80 -- 70% to 80% earnings payout range. That seems like the right place to be, that equates to about 1/3 of cash flow, and to us is a reasonable balance of the cash return to the investors as well as allowing us significant reinvestment capacity into our business. The DRIP to bolster that reinvestment capacity, we would be -- we believe it would be market to not constrain dividend growth to fund the program, but rather increase the dividend and allow the investors the opportunity of a choice whether to reinvest through a DRIP program. If we end up in a situation of surplus capital, if it's temporary, we'll store it. If it's more structural or permanent, we'll look to return that to the shareholder by either increasing its payout or shrinking the balance sheet proportionately in accordance with a great credit metrics.

So to wrap up, we've had a 15% total shareholder return annualized since 2000, so our track record speaks for itself. Our growth portfolio is unprecedented, and just as to the highest quality here, and we would relish the opportunity to fund the program of this caliber given the clear supportable use of proceeds, the compelling issuance levels that still exist right now, and then the many levers at our disposal.

So with that, we welcome the questions.

Unknown Attendee

Just a bit of a hypothetical question. And obviously, there's a lot of variables at play. But when you look over the next couple of years on various possible scenarios of your financing requirements, how do you think about prefunding versus just putting in permanent financing once the large project is in service? And just as importantly, how are your debt rating agencies, do you think, are thinking about that?

Donald R. Marchand

Yes, the prefunding side is expensive, and there are binary decision points here. So it is somewhat speculative to start prefunding something until you cross those points. I'd say great confidence in the quality of the projects that they will be able to attract funding. It's more the quantum rather than the specifics of the projects. So not assuming it away, but if these projects do get past the permitting stage and are moving forward, we're quite confident that we'll source capital just to finance it at that point in time. So we're not actively prefunding $25 billion or a portion of that right now.

Unknown Attendee

But what about during the construction phase?

Donald R. Marchand

Well, during construction, yes, we would -- these are generally 2 year -- 2 or 3-year build projects. So we would -- we'd actively be out there, a continuous issue over that timeframe. If you could get project financing for the LNG projects, that is something you would just -- you'd have it in place and then funded over the course of the build period.

David Moneta

Go ahead, Pierre.

Pierre Lacroix - Desjardins Securities Inc., Research Division

Pierre Lacroix from Desjardins Capital Markets. Don and Russ, I just want to get a sense of -- I'm looking at the growth over the 2014, 2015 period. And what is your prospect in terms of add-on to that growth, in 2015, let's say, that it's not going to be your biggest year for growth. But, I guess, you have a lot of projects on the table that you might look at. And what is your positioning versus your funding program versus Keystone XL to make a move to fill out that growth in 2015? And where it could come from?

Donald R. Marchand

Well, we're not closed for business, and there is clearly some great bolt-on opportunities or places to improve our competitive position. So we'll actively explore that. The opportunity set that's there right now, we want to secure this because it secures the company for decades to come. We have a lot of levers that are listed, as you saw there. So we're not feeling constrained financially with this program right now. Some of this spend is back-end loaded later in the decade, post 2016 timeframe. So just my view would be is that if there are opportunities in Mexico, Alberta oil or de-bottlenecking gas, that's something we would actively consider.

Russell K. Girling

Just maybe to add, Pierre, to that, is, of course, we'll look for incremental opportunities. And then they do arise, what we know is that there's always more opportunity than we have capital in the current marketplace. That's why we look to our base businesses, which you've heard today. Our U.S. pipe business, for example, being at cyclical lows. We're very focused on increasing revenues. Our open seasons on ANR, they've incrementally generated more revenue. We expect to hold more open seasons over 2014. I do expect that will result in increased revenues, certainly as it has, as Karl said, from a cost perspective, we look at all parts of our organization as to where we can get cost efficiencies. You mentioned about $50 million in our U.S. pipe business. We're just at the end stages of implementing an SAP system, which allow us to achieve fairly significant synergies in this company sort of post 2014 and into 2015. It's a major consolidation of all of our systems. So as I look to those things and enhancing availability of our power facilities, enhancing the throughput capabilities on Keystone, for example, with the drag agent reductions and those kinds of things, we will seek to eke out incremental revenue. And they come in $5 million, $10 million, $50 million chunks, within a portfolio our size, you start adding them together, and you can hit $100 million kind of chunks, and they're available to us. And that will be the focus of the bulk of our organization through that 2014, 2015 period is just to make sure that we're as efficient as possible and squeeze out the best earnings we can out of our base assets.

David Moneta

Okay. Matthew?

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Matthew Akman, Scotiabank. My question is on the MLP utilization, and it sounds from both what Russ said earlier and from what Don is saying that you guys have decided to use the MLP to raise cash for the growth -- for the organic growth program, as opposed to wholesale MLP-type conversion, like some of your competitors have done, or moving towards more of an asset manager role as opposed to an asset owner role. Maybe you could just confirm that, that is your thought and direction, and also how you arrived at that strategic direction, which is different from some of your peers. I don't know if the question is for Don or Russ or for both.

Donald R. Marchand

Yes, I'll start. Yes, that's correct. Your characterization is correct. It's more evolutionary than revolutionary. There was no specific date where we said we're going to do this. As we get greater confidence in this portfolio moving forward, this seems like a very logical place to get capital. The key here is cash, as Russ mentioned earlier. Bending all this in and taking paperback removes you one step from where the actual cash is generated to where it's actually needed. So our view is we would then, over time, pour cash into the LP, which is -- which would be a nice funding mechanism from a time perspective of a capital program of this nature. So it's something we'll begin acting on here in 2014. I'd also note that the cash that we would extract from this thing, there are capacity constraints. And as the LP grows in size, those constraints get smaller and smaller. So if we can grow this thing from a $4 billion or $5 billion vehicle to something in the high single digits, the ability to bend into that asset just grow with it.

David Moneta

Ted?

Theodore Durbin - Goldman Sachs Group Inc., Research Division

I just want to confirm a couple of things. I think when we talked about the math here, the EBITDA growth is sort of a 10% or 11% compound annual growth rate. Can you just translate that then into EPS growth? Maybe what kind of financing assumptions we should make? I mean, is sort of 7% to 8% reasonable, or kind of how we'd about on the EPS side?

Donald R. Marchand

Well, it's going to be lumpy is the first thing, over time here. But I'm not sure what the conversion rate that would be. In terms of the inputs to it, beyond the EBITDA, the I, we would see the interest -- I'll give you the component parts here. The I, you can see the funding mechanisms here and you can factor in whatever you expect for interest rates. Depreciation, these are generally 40 to 50-year assets that come on stream here. From a tax rate perspective, we're currently around the Canadian statutory rate, 25%, 26%. We would expect that to actually gravitate upward to the high 20s as the proportion of the U.S. dollar income grows in the company, the U.S. tax rate being higher than Canadian. So without giving you an exact answer here, those are the ingredients.

Theodore Durbin - Goldman Sachs Group Inc., Research Division

And then just on the Bruce, again, going back to Carl's question. Should we burden -- because it doesn't look like you have any delta here on the EBITDA for Bruce, in the EBITDA build, as we burden that with some capital, or how do we think about that?

Donald R. Marchand

Probably -- at this point, probably a post 2020 timeframe as they come to their lives. That would be our assumption at this point.

David Moneta

Carl?

Carl L. Kirst - BMO Capital Markets U.S.

Just a couple of questions, maybe one going back to the MLP, and I'm not really sure if this is meaningful. But just as you look at kind of pursuing that strategy versus a large drop, for instance, Spectra or Williams taking back the paper kind of thing. The fact that TCP's GP IDRs kind of max out at 25% versus 50% gives you a little bit different -- a different economic argument on that. Is that something that influences or informs kind of the strategy there? Is that something you would consider reviewing one way or the other, whether that's the MLP buying in the GP IDR. But just I'm wondering if that makes it actually easy or more difficult to pursue the drop-down strategy?

Donald R. Marchand

We've amended it before, and it's something we would look to again to make sure it's a win-win for both the LP and TransCanada at the end of the day. So, yes, it's something that would be on the table.

Carl L. Kirst - BMO Capital Markets U.S.

Okay. And just second question, and understanding this is now well, well beyond 2020. But Russ, you were actually mentioning last night that you thought Alaska was actually getting some traction. And I was just wondering if you could -- even if that's not until a 2025 event, I was just wondering if you could expound on that.

Russell K. Girling

Sure. On Alaska, I mean, it's still on the maps that you all saw today, and wasn't sort of the primary focus of the things that will be in 2020. But as we've always said, Alaska contains a significant resource. It produces about 7 billion to 8 billion cubic feet a day of gas associated with the oil production. At some point in time, that gas has to be redirected to market rather than being reinjected into the gas. The gas-to-oil ratio climbs, and it becomes uneconomic to continue producing oil on that basis. So the producers have always said that at some point in time, never telling us exactly when that point is, they would need to move that to market. The original plan was to move to lower 48. I think the changes in the lower 48 market have suggested that, that isn't the logical market in the next couple of decades. But there is an opportunity to move that, that resource to LNG markets. The group of producers, ConocoPhillips, ExxonMobil and BP, along with ourselves, spent about the last 12 or 18 months working on the feasibility of an LNG export terminal. We've come to a conclusion that, that makes some sense, and that the [indiscernible] is probably the most logical place. The conversations between the state and those producers have progressed. As I've always said, the major issue with respect to Alaska is the fiscal terms under which that gas would be produced going forward, and it appears that the foundation of that negotiation has been laid in discussions with -- between producers and the government. So it appears that there's a structure on the horizon that works for the state and works for the producers. So I think at this point in time, we're very optimistic for the first time in a long time, there appears to be alignment between those 3 producing companies, TransCanada as an independent pipeline company, and the state as to what direction they're going to go. So I would expect to see some significant announcements coming out of there in the coming months. And it probably looked like a project that is scheduled for something looks like about 2025, and what we would hope is that TransCanada would land a position similar to the kind of position that it's been able to put in place for the West Coast LNG projects in terms of being a large component of the gas delivery system, potentially part of the upstream, part of the system as well. Obviously, we'll see the producers, they've always wanted is to control some equity portion in the pipes. So I would see us having a minority position potentially and a position where we would have a strong role in the operations and in construction of the pipe. Timeframe-wise, our current thinking is somewhere between early '20s, '21, '22, '23, and 2025 as an in-service date. Again, a large project, lot's of water to go under the bridge. But at this point in time, as I mentioned last night, I think we're more optimistic than we've been in a long time about Alaska. And as I think about the go-forward beyond 2020, there's an opportunity for this company to put in place capital reinvestment opportunities that take us well into the next decade.

David Moneta

Andrew?

Andrew M. Kuske - Crédit Suisse AG, Research Division

Andrew Kuske, Credit Suisse. Don, I guess, if you look at your illustrative numbers, at 2020, you got $80 billion balance sheet. So roughly $50 billion of that is going to be in capital market, $9.5 billion EBITDA you're going to generate each year. So when you look at the funds you're going to redeploy and just the natural maturities, do you feel you're going to be too large for the debt markets at that point in time just in Canada and the U.S., or is there crowding out effect that'd happen?

Donald R. Marchand

I'm thinking, with the internal cash we have, that $50 billion is probably high, and the other levers there. I'm probably in the $30 million to $40 million range there. It's a big number still. We haven't hit any capacity constraints in North America. It doesn't feel like we're about to hit them at this point in time. Obviously, U.S. markets are deeper than the Canadian markets. The more U.S. dollar-denominated business you have, the better. We would absolutely explore other markets, even today, if it's cheaper cost than the diversification opportunity. What we found though is that the cost is actually generally equal to or higher and -- given the markets readily available to us right now. What you see through the capital stat we went through is the potential for looking at things like project financing and maximizing the LP. So there's a lot of levers here. But a long-winded way of saying that we're not hitting capacity constraints, it is in that '20, '21 timeframe. A lot of it is internally funded growth. $9.5 billion of EBITDA drives a lot of cash flow.

Andrew M. Kuske - Crédit Suisse AG, Research Division

And then also from just a footprint standpoint. If you don't hit capacity constraints, do you still have some incentives to look beyond North America and then sort of explore, really, international opportunities?

Donald R. Marchand

Yes. It's pretty big opportunity set right here at home right now. In terms of investment opportunities -- Russ, you can expand on this as well. What you find internationally is what is actually investable, what is actually large scale enough for a company of this size, let alone $80 billion to move the dial, and you run into, even where it is investable, you find there's entrenched incumbents. So the opportunity set is not necessarily massive out there but something that we've been there before and we consider it. But there's so much right here at home right now, it's not high in the list.

David Moneta

We'll take time for one more question from Robert.

Robert Kwan - RBC Capital Markets, LLC, Research Division

Don, you had a number of the myriad of different funding sources that you've highlighted for a while here, but largely, it's been a conventional, kind of plain vanilla structure on balance sheet, a little bit here on the MLP, looks like you're stepping up. Just wondering, can you talk about as you're looking at the CapEx plan building here, what's the desire, the likelihood to use some of these other structures, you've highlighted the pension fund side here, would you look at a new yield curve [ph] or as well material asset sales?

Donald R. Marchand

Yes, as was mentioned earlier, our preference is generally to hold 100% of everything in its simplest form, which is generally the cheapest form possible. So as we migrate away from that, capacity issues or strategic matters, we have partnered up on some assets, so PetroChina, ConocoPhillips in the past and the likes. So there may be strategic reasons to that. But if -- back to, I guess, Linda's question earlier too, if you have this huge funding obligation, this is an obvious place where -- and we do have a lot of inbound calls right now. There is co-investment opportunities, there may be a chance to enhance your return by getting some sort of remote structure there. But, generally, we default to these meat and potatoes, what we do is we build things and we keep it on balance sheet and finance it for the long term and capture that spread. So structure at some point adds cost and complexity, and it may be a zero-sum game at the end of the day.

Robert Kwan - RBC Capital Markets, LLC, Research Division

Just the last question here. You talked about on the dividend, the desire to continue it increasing, and then allow if you decide to turn on the DRIP, whether people want to [indiscernible] Just want to make sure, was that a comment on absolute dividend increases or is that something where you think you might want to start accelerating the pace given the $0.08 per year, which has been normal, becoming a pretty small percentage number?

Donald R. Marchand

I'd look more to the 70% to 80% earnings payout ratio, staying in that band rather than -- if we get a step change in earnings, we look to grow the earnings -- the dividend along with that at that point in time, as long as it's sustainable.

David Moneta

Great. Thanks. All right. I think, again, Don will be around for a while. So if people have further follow-up questions, feel free to approach him. I think with that, Russ says he promised earlier we'll just happy to take any final questions from people, and then we'll just close with 1 minute or 2 of final remarks. So if there's any questions for Russ, I'm sure he's happy to entertain them at this point.

Russell K. Girling

All right. It sounds like -- looks like everybody's hungry, which I would concur, so just to close, I mean, our intention today was to provide you with some insight with respect to both our challenges and the tremendous opportunity that exists in the years ahead for our company. We hope that you take away today the message that we are in a time of unprecedented growth for both the industry that we work in for our company and for each one of the individual businesses that we operate, and we are positioned to be a leader in each one of those core businesses in North America, which is our focus. And I think that's, for a company our size, what your expectations should be. We do recognize that the environment that we operate in has changed substantially, and that the bar for performance has risen and will continue to rise going forward. That will have implications for how we do our business, have implications for our costs, but at the same time, have implications throughout the competitive markets sorts itself out. And we're going to be a leader, and as a result, we will be able to use that to our advantage to continue to grow the company. We've always been a leader in technology and research and development. We'll continue down those paths. A leader in safety and reliability. And those will continue to be job one for this company as we move forward. We are up for the challenges, as I said. We have the asset position upon which to grow. We have the people and expertise to do it, and we have a visible portfolio of growth opportunities, all of which will allow us to continue to deliver shareholder value for decades to come. Our strategies, now that the playing field has been laid for us, you can see there's a linear path that, like Don showed you, what we know is that linear path will have its bumps in it. But our job is one around execution now, and that's what we're going to be focused on every day at this company. So again, thank you all for taking the time out of your schedules to join us today and continued support of the company. We do have a lunch that you're all invited to join us on -- join us with. There is several members of the management team here. If you haven't had a chance to interact with some specific person or specific area that you have a question, try to position yourself at the head of table and ask all the questions you want, again, thank you all very much, and we appreciate your support.

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