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Enbridge, Inc. (NYSE:ENB)

October 03, 2012 8:00 am ET

Executives

J. L. Balko - Vice President of Human Resources & Administration

Al Monaco - Chief Executive Officer, President and Director

Arthur D. Meyer - Senior Vice President of Pipeline Integrity & Engineering

Byron C. Neiles - Senior Vice President of Major Projects

Stephen John Wuori - President of Liquids Pipelines & Major Projects

Leon A. Zupan - President of Gas Pipelines

D. Guy Jarvis - President of Gas Distribution

J. Richard Bird - Chief Financial Officer and Executive Vice President of Corporate Development

Analysts

Andrew M. Kuske - Crédit Suisse AG, Research Division

Linda Ezergailis - TD Securities Equity Research

Winfried Fruehauf - National Bank Financial, Inc., Research Division

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Juan Plessis - Canaccord Genuity, Research Division

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

Theodore Durbin - Goldman Sachs Group Inc., Research Division

Robert Kwan - RBC Capital Markets, LLC, Research Division

Chad Friess - UBS Investment Bank, Research Division

Maria Berlettano - J. Zechner Associates Inc.

Stephen Dafoe

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

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

Andrew John Kerr - SADIF-Investment Analytics S.A.

J. L. Balko

So hello, and good morning. My name is Jody Balko, and I'm Vice President of Investor Relations at Enbridge. Welcome to the 14th Annual Enbridge Day. It's an exciting time for us as we'll be hosting our investor conference for the first time in 11 years. We are kicking off the event with a strategic update from our new President and CEO, Al Monaco.

But before I turn the morning over to Al, I do have a few housekeeping items to go over with you. First, in the interest of safety, if there is a fire alarm, please proceed to the exits at the back of the room. Exit through those doors, and go down the stairs. At the bottom of the stairs, you'll be met by someone from the Toronto Board of Trade, and they will direct you over to the Sheraton and that is the meeting point.

Also, I'd like to remind you that this session today is being webcast. So if you do have questions, please wait for the microphone, and then state your name and firm that you're from, so that people listening to the webcast can follow along.

And this year, in lieu of the traditional thank you gift that we would normally give, we have elected to direct those dollars to the Enbridge Ride to Conquer Cancer. Our donation will be equally distributed across the 4 campaigns in British Columbia, Alberta, Ontario and Québec and will benefit the designated cancer foundations in those provinces.

The Enbridge Ride to Conquer Cancer is something that we are extremely proud of. Every year, there are more riders, and every year we raise more money. In fact, in 2012, there were close to 12,000 riders across the country, and collectively, they rose over $44 million, which is a staggering amount of money going towards a disease that impacts so many of us.

But don't worry, you will not go away empty handed. We have, if you hadn't seen them at the front, a 2012 Ride tuque. So please pick one up on your way out. They were a hit at all of the events last year and especially the -- a chilly Alberta Ride. So you never know when they may come in handy.

And the very last item that I'm going to go over for you is our forward-looking statements. Please take a moment to review the legal disclaimer regarding forward-looking statements as some of the comments this morning may fall into the category of forward-looking information.

And with that, I will pass it over to Al.

Al Monaco

Good morning, everyone. Before I begin, I'd like to acknowledge Pat Daniel, who led Enbridge as CEO for 12 years and retired just a few days ago. On behalf of all of us, I'd really like to thank Pat for his leadership and dedication to our company. We're very, very grateful for all of his contributions.

Today's session is very timely from a few perspectives. Since Pat announced his retirement a few months ago, I and the rest of the management team have landed on the priorities that will extend our record of delivering superior returns. It also gives us a chance to discuss our strategic plan, which we recently finalized and was blessed by our Board of Directors. And we have some important new developments to talk about, in particular our light oil access initiative. Once sanctioned, that project will be additive to the Eastern Access program announced earlier this year and, of course, our Gulf Coast Access projects.

With that, as part of our revised capital program, we'll be talking about an even more robust growth outlook than last year's Enbridge Day. That program totals $35 billion, which translates to an increase in our EPS growth rate from a baseline of 10% to 12%-plus on average over the next 5 years, and there'll be more on that later, of course.

As you know, I've been part of the management team for a while. But given the transition in leadership, I'd like to spend a moment on the approach we'll take in the years to come. In a nutshell, don't expect to see any major shift in strategy. Our value proposition has delivered excellent returns, and the leadership and -- team and I plan to stick with the strategy.

Enbridge has an embedded culture of investment discipline. We put more capital into the ground than any other company in our sector, so it's critical that we continue to get that right. So what does investment discipline mean exactly? Essentially, it's the rigor by which we ensure project returns exceed the cost of capital. Returns are looking better than ever these days, and we're benefiting from lower funding costs as well.

Second, given our plethora of opportunities, we're focused on organic growth as opposed to large-scale transforming acquisitions. That only makes sense, given that we can invest organically at 4 to 7x EBITDA, in our crown jewel Liquids Pipelines business as one example. I think we're having a bit of -- oh there it goes. Good.

So the next point is we are mindful of preserving financial strength and flexibility. We completed a record investment program through the depths of the global financial crisis a few years back. And we hope we don't face another one of those, but we will be ready for it if it happens.

We'll be focused on developing management talent, and part of that is rotation. Now this bears fruit in our view by having people at the decision-making table that have held senior-level positions across the company and across disciplines.

Over the long-term, our goal is to have a reasonable balance, not necessarily 50-50, between liquids assets and natural gas. In the next 5 years though, we're going to become even more weighted towards liquids, over 70% if you look at earnings, simply because of the massive opportunities that we have in our business on that side. So the point is we're not going to forsake excellent opportunities today just to achieve a greater balance.

Given recent events, we are also ramping up attention to operational excellence. Over the years, we've been known as the best operator in the business, and our plan is to ensure we are the industry leader. You'll see that theme running through today's discussions. So overall, we'll continue that approach that has stood us in good stead over the years.

Our executive team remains largely unchanged since the last Enbridge Day. Leon Zupan now leads Gas Pipelines and Processing. Leon previously held the position of looking after Liquids Pipelines operations. He knows our systems better than just about anyone. You will also see 2 new faces here today, Art Meyer and Byron Neiles. Art is the COO of Liquids Pipelines, and he will be speaking to our focus on operations. And Byron leads Major Projects, and he'll discuss our progress on major projects execution.

So with that context, I'll take you now through our strategic overview, and more detail will come on the strategy through the morning. Now as pipeliners, we're not usually prone to putting up photos like this one here. But every once in a while, we step out of our comfort zone, and our creative side comes out. And this is it. This is the extent of it. I used to say that we'd like to have a photo like this because it captures the theme of our strategic plan very well, which is all about getting to the horizon and then beyond.

It really illustrates the 2 main groups of priorities that we have. The first set is geared to achieving our 5-year objectives, ending in 2016. So that's the horizon year of the plan. The second group of priorities positions us for growth beyond 2016. So essentially, we've got one eye on achieving medium-term growth objectives and the other trained on extending that growth rate beyond the horizon. By the end of the morning, you'll see how we plan to achieve exceptionally strong and transparent earnings growth that get us to 2016 and then the momentum that carries us on into the latter part of the decade.

So what I'll do now is highlight what's driving our strategies, outline our 3 key priorities and then take you through how all of that translates into a very robust growth outlook. Now each of the businesses is going to drill down into their own fundamentals, but let me just describe how we see the big picture energy landscape here.

A confluence of factors is leading to the need for major new oil infrastructure development, which actually bodes very well for our future. First, global oil and natural gas demand will grow strongly through the next 2 decades. But that growth, as you know, is not going to be driven by North America nor Europe. It will be driven by emerging markets, particularly India and China. So the GDP growth, as you know, 2%, at best, in North America and likely over 8% or beyond in the emerging markets.

U.S. crude demand will be muted as economic growth will be offset by fuel efficiency and increase in biofuels and fewer vehicles and miles driven. Now the newest game changer is an unprecedented increase in North American crude oil supply. In fact, new sources of crude have the potential to displace overseas imports.

The location and nature of that supply is also changing very rapidly. Nobody predicted, we believe, the light barrel growth that we would see occurring in just the space of the last 3 years. The same holds true for gas with massive shale reserves, and with that, comes increasing NGL supply.

An important factor affecting North American dynamics is that Canada's resources are landlocked with access to only one market, and that makes us a price taker here in Canada. It's these factors that are resulting in transportation bottlenecks between growing North American supply and continental and global consuming markets. Those bottlenecks result in significant North American price disparities that drive our strategies.

And let me just emphasize that with this next chart. Our business is mostly about connecting supply to market demand, and the need for new infrastructure is signaled by price differences between markets that you see here that exceed the cost of transportation. This chart illustrates the value that's available for capture for producers and consumers. That value is most prominent in moving heavy crude from Western Canada to the U.S. Gulf Coast and, ultimately, to Asia; light crude to Eastern markets; and then natural gas to Pacific markets.

Since the beginning of the year, the discount between heavy crude price at the U.S. Gulf and Hardisty has averaged $27 a barrel. That compares to the physical transportation cost of about $8 a barrel. Western Canada and Bakken light crude has been heavily discounted as well, relative to both the U.S. Gulf and the Eastern markets. If you just look at the Bakken-LLS Brent differential here, it's about $24. So if you are a Bakken producer, you have not been very happy over the last year. And of course, the differentials to Asian markets are even more pronounced.

So the situation that you see here on this chart is untenable for producers who don't have downstream refining capability and for refiners who only have access to Brent-based barrels, like Eastern Canadian and PADD I refineries. So it's these price dislocations that you see here that underpin and drive our infrastructure plans as we aim to capture its value for the customer.

So today, what comes out of all that, North America is in the process of being repiped, both in terms of additional capacity required and the flow and direction of crude and natural gas. Enbridge is right in the middle of that transformation. Our Liquids Pipelines market access initiatives began a few years back with the need to address heavy crude disparities. But as a result of the light oil supply outlook, we've been working very hard to develop new initiatives on that front, and that's the new and very exciting game for us.

The deep discounting of crude and gas prices relative to world prices can be solved by simply expediting new infrastructure. Sounds pretty straightforward. The problem is this need comes at a time when we're seeing significant opposition to every kind of energy development. Now oil, gas, nuclear, even wind and solar attracts opposition. It used to be, frankly, that, I think I mentioned it earlier this morning, nobody cared that much about pipelines. But because we are critical enablers of development these days, we and our sector are the point of attack.

Because of that, the energy industry has recognized, I think, an important new reality. And that reality is that the economic benefits alone are not enough to support development of energy projects. The public wants resource development to happen in a sustainable way. On the other hand, I do think oil sands producers are making very good progress in addressing environmental issues, whether it's through lower emissions per unit, progress on reclamation, lower water use and even sharing technology, which is a big change in the oil industry these days.

Gas producers are also minimizing their footprint. Our Cabin Gas Plant is a great case in point, where producers agreed that a central facility would minimize the environmental impact for everyone.

In our case, this reality means that we need to be flexible as pipeline companies with respect to design and begin regulatory and landowner consultation much earlier. And frankly, we need to better explain the benefits of these projects to the communities in a lot more detail. So our business priority in a nutshell is to anticipate, allow for and respond constructively to these challenges that we're seeing.

So along with those high-level fundamentals, it's really this chart that sets the stage for our 3 priorities. There are a number of noteworthy topics that we're going to cover today but none more exciting than this picture, which shows the progression of our commercially secured project.

So last year, at Enbridge Day, we had a pretty impressive $9 billion of enterprise-wide secured investments. So investments that we actually have commercially underpinned. Since that time, we've steadily nailed down commercial support for many more projects, and it's nice to see that very few have gotten away.

The result is a backlog of commercially secured projects, $18 billion at this point in time, with more to come. These projects are highly strategic, and the returns are consistent with our historical criteria and supported by good commercial underpinning and strong fundamentals on supply and demand.

These secured projects, by themselves, should generate 10% EPS growth through the middle of the decade, even if we don't secure another commercial opportunity. These projects also support continued growth in the latter half of this decade. So again, the chart shows the progression since last year. I'll talk later on about how that $18 billion is going to grow.

So these are the 3 priorities that underpin the plan I was talking about. The first is to focus on operations. That's basically the safety, reliability and environmental protection of our systems. We're an operating company, and that's what differentiates us from financial players. So we need to be the best.

Second is to execute our massive slate of growth projects on time and on budget. If we can do that well, we will, and we will, we will generate 10% EPS growth rate and, quite likely, 12% plus. The 3 parts of that priority are major projects execution, having sufficient capital and liquidity and environmental sustainability.

So with a well-bedded down growth rate for the medium term, our third priority is to extend the growth rate beyond 2016.

So I'll cover those now. On the first priority, which is to focus hard on operations, over the last few months, there's been a lot of discussion about our safety record. And this slide shows that record compared to industry. As you can see, it pretty much confirms what we've intuitively thought, which is Enbridge is a solid operator. Our spill frequency record over the last decade, that's the left-hand side here, is 1/4 of that of industry, and the volume is about half of industry if you exclude Marshall.

Our annual safety delivery rate is actually very good at 99.9996%, and 2011 was actually the lowest spill frequency on record. But I have to say, this is not something that we are bragging about as a company. Frankly, we're not happy -- we can't be happy with either chart, particularly the right-hand side, but it does help to put things in context.

As you've seen, Enbridge attracts a lot of attention relative to the industry peers. That has a lot to do with the size of our system and our role, our important role of moving crude oil in North America. So if you have an incident, it surely gets noticed. We also serve the U.S. Midwest refining market, so any interruption can affect gasoline prices. So that, as well, elevates the profile.

We run a huge network, and despite our best efforts and, frankly, the efforts of industry generally, mechanical failures do happen. That being said, as a pipeline operator, our customers and the public put trust in us. So we take accountability for every incident, no excuses and no questions. Instead, we need to focus our energy on getting better.

In fact, the whole thrust of our focus on operations priority is to drive down our incident frequency, not just to the historical better-than-industry level, but as close to 0 as we can get. This isn't just an operational goal that we have, it's really a strategic imperative.

So how are we going to do that? Well, as the largest operator, crude operator in the world, we've developed some pretty good skills and experience, processes, technology and so forth. But when you experience an incident like Marshall, you need to make changes so it -- to make sure it doesn't happen again. That's what we've been doing for the last 2 years, and that's what we're going to continue to do.

The objective is pretty straightforward, to achieve top quartile performance, if not best in class, along several safety and integrity dimensions. And we're measuring that performance and -- along industry levels. We have executive oversight through our Operations and Integrity Committee. That actually is now our most important committee in the company. We've redefined accountabilities, set performance targets and expanded technical staff.

We've also established an Operational Risk Management Plan that we refer to as ORM, which sits right alongside our strategic plan. So it's just as important. The ORM, essentially, is a roadmap of programs that are required to sustain an industry-leading position. We'll get independent verification of our performance, and the results are going to be monitored by our Board of Directors.

To align with that goal, we've increased maintenance and integrity spending over the last 2 years. I can assure you, there's no one putting more effort into this today, including inspection of systems and so forth. So Art Meyer is going to speak to the specifics of our ORM Plan in a few minutes.

As you saw, we have a huge backlog of commercially secured projects. But we do have to get those in place. So our second priority is to execute the capital program very well. The key aspect of execution for us is design and construction, and that's managed by our Major Projects group under Byron Neiles. Byron has a staff of around 1,200 to execute this current slate of projects, and he has an experienced management team that works with him.

One of the biggest challenges in our business is estimating cost and schedule under, what is, compressed time frames, and the reason it's time compressed is because of the previous chart on those price disparities. So you can imagine producers and refiners are anxious to move quickly. MP, Major Projects, has a disciplined process for cost and schedule estimates, and then they manage to those goal posts. Our executive meets every month with Byron and his senior staff to review the status of every project and to ensure that he has the -- enough resources to carry out his job.

Of the 24 projects we currently have in execution, as shown by the chart here, 23 are on schedule and either at or below budget. This actually looks pretty straightforward when you look at it on a slide like this, but there's a huge effort that goes into this, particularly in light of the increasing challenging environment that we're facing. And because project execution is a key to delivering the 10% growth rate and then beyond the 10%, Byron will be expanding on this topic in just a few minutes.

An equally critical part of execution is ensuring that we have enough funding to make these projects happen. The Finance group, led by Richard, has been all over this, raising $4 billion so far this year, and that includes about $2 billion on the equity side of the balance sheet. It's going to be important that we retain strong investment-grade ratings. We've also built up about $11 billion in credit backstopping Enbridge-wide. Yes, that's a lot of backstopping, but it is cost-effective insurance that will ensure that we can execute the capital program in the event of market disruptions. Our access to capital is very strong with effective funding costs, which stems from our solid business model and our strategic position.

In a moment, I'm going to highlight our revised investment program, which is going to require additional funding, but we have accounted for that in our plan that Richard will review in some detail. Our actions to date position us very well to meet our equity requirements through 2016. We have ample capacity for further press shares and for sponsored vehicle drop-downs to augment the building up of equity from internal cash flow and our DRIP program.

The last element of execution is to focus on environmental sustainability. Now this isn't just a nice to have these days. It's part of our business environment. We've actually been building on this for a number of years. We're the second highest ranked of only 6 Canadian companies to make the 2012 Global 100 Most Sustainable Corporations index. We're part of the -- part of the Dow Jones Sustainability Index, and we recently were added to the FTSE4Good Index.

Now I've listed out some of the index criteria here to illustrate that these are challenging and meaningful requirements. And as you can see, not only are we on the indices, we've made some excellent strides in reducing our own emissions. We've put a lot of effort into making meaningful improvements in this area, and these indices here really represent a bit of a scorecard for us on our progress.

So as you've seen, we're in excellent position now to deliver leading earnings growth in the industry, which should translate to strong dividends and significant share price appreciation over the next 5 years. There's a very high transparency to that happening on the strength of the dominant position in the Liquids Pipelines business and good execution.

So that brings me to the third priority, which is to extend the growth rate beyond 2016. So now we're focusing on beyond the horizon. Based on where we sit today, we're confident in extending that growth rate to the latter half of this decade.

There are a few reasons for that confidence. By 2015, we'll have over $8 billion of new capital invested in projects, which will be immediately accretive to initial returns in the high-single digits, but which will have upward tilted return profiles. Second, we have another $5 billion plus in 2015, '16, which could contribute to earnings in the latter half of the decade. And finally, we expect to see increasing contribution from new growth platforms, that being Canadian midstream, electric power and international.

Just a quick note on those 3 areas. Building these new platforms does diversify our sources of earnings growth in businesses that fit very well with our existing investment proposition, but they also provide optionality for the future. And by optionality, I mean identifying potential growth that may not necessarily be transparent today. And a great example of that is our North Dakota system, which we acquired many years back with no idea, frankly, that we would see the light oil increase in the Bakken. So sometimes, you can't predict the growth, but it always makes sense to hold infrastructure in key areas.

So all of that bodes well for our ability to extend our exceptional growth rate in earnings and dividends well beyond 2016.

So before I review our 5-year financial outlook that comes out of all that, let me spend a few minutes on project Gateway. As you know, this project is receiving a disproportionate amount of attention these days, primarily related to concerns over safety, environment, and there's a number of other issues that we're all aware of that are affecting people's views on the project. But let me address one thing right off the bat on safety and environment. Gateway is going to be a world-class project. That includes numerous marine safety enhancements and measures that go beyond regulatory requirements given the nature of this project. So we're talking about extra thick wall pipe, more valve locations and increasing the frequency of inspections on the line. We made several changes to the alignment along the right of way in response to community advice, and we take that advice and use it in ensuring that we can mitigate risks even further. And we will be co-owners of this project with First Nations.

Next, there are vocal opponents to the project, but the fact is there have been many challenges to other nation-building projects, pipelines, railways and other projects. And that's why we have a regulatory process that is intended to address and listen to all points of view, and it really determines whether or not the project is going to be in the public interest. The bottom line on Gateway, I think, is this: it's a highly strategic project to Canada, and there's general agreement that accessing the Asian market is in our interest. Canada has the third-largest reserves on crude in the world. We have the skills and technology to develop those reserves, and we have proximity to half the world's population off of the West Coast. So as a resource-driven economy, there's no question that Canada needs access to tidewater. And the project is going to generate billions in terms of spinoffs, thousands of jobs and benefits to communities. Our funding sponsors and many other stakeholders are very keen on Gateway proceeding. We made a call a while ago that we were the best positioned company to take this project on, and that continues to be our view. That said, until this project is approved and we move to execution, our investment in the regulatory phase is modest with funding support from oil sands producers. Given that we're in the middle of a hearing process right now, that's all we plan to say about Gateway, but obviously, we'll try and respond to questions that you have.

So let me wrap up by highlighting our financial outlook, beginning with our enterprise-wide capital growth program over the 5 years. The headline capital program is $35 billion, and here's how that $35 billion breaks down. As I covered earlier, and this is on the bottom part of the stacked bar, we'll have $18 billion of secured projects, and that has increased nicely over the last year. Next, we have another $12 billion, that's the middle part of that stacked bar, in what we call the highly certain but yet to be secured category. These projects aren't quite in the bag but will likely proceed on a time line, which would have them in service by 2016 or before. These are going to be covered specifically by Steve, Leon and Guy. Included in this newest category this year is the light oil market access initiative to move barrels from Western Canada and the Bakken to Eastern markets. Steve is going to outline this project in a few minutes.

So taking together this commercially secured and highly certain number of projects totaling $30 billion, pack a very powerful punch in terms of earnings growth. To put that $30 billion in perspective, it represents about 70% of our current assets.

Lastly, we've allowed for another category, $5 billion of risk capital. Those are projects that have been identified and represent a whole host of them, but they have been probability weighted for success. We may get more, we may get less. It's possible that some of those projects could be in service as well by 2016, but we've included no contribution from that category in our 5-year EPS outlook. By the way though, we have included funding for that amount of capital in the program funding that Richard will talk about.

So as you can see here, our plate is very full. And any way you look at it, this activity will drive industry-leading growth, which is the subject of the following slide where this story comes together in one spot. The exceptional array of interactive investments, coupled with our access to low-cost capital, supports an unparalleled growth outlook in our view. We're very confident that we'll extend the 10% average EPS growth rate to 2016 purely on the strength of the $18 billion of opportunities already secured. And that's the dark blue part of these bars here. The $12 billion in highly probable category should boost the growth rate into the 12%-plus range even with no contribution from the risk opportunities. And that's represented by the light blue part of that bar on the right. As for the latter half of the decade, our plan is considerable momentum building by 2016, which should sustain a very healthy growth rate well beyond that horizon. That confidence stems from embedded back-end weighted return profiles on projects that are in execution right now, projects that generate earnings after 2016 and contributions from new platforms namely Canadian Midstream, Electric Power and International.

One other opportunity that provides further support for the outlook is potential drop-downs to our sponsored vehicles, Enbridge Income Fund and Enbridge Energy Partners. This is a powerful tool to both release capital from Enbridge Inc. and drive further improvement in our return on capital, along with growth within those vehicles. Richard, again, will talk about the mechanics of that and the significant inventory that we have in potential drop-down opportunities.

So that exceptional earnings growth picture comes with ample scope for continued dividend growth. Over the last 10 years, we've delivered an average growth rate of 11%. And in fact, over the last 3 years, it's been accelerated to 15% growth. So an 11% growth rate through 2016 should pretty much be the floor with potential for continuation of increases above that rate. And the important thing about that is we can achieve it without pushing beyond our policy range of 60% to 70% of earnings.

So I'm going to take questions now. Then I'll ask Art Meyer to elaborate on behalf of all of the business units on his focus on operations discussion. That is going to be followed by Byron Neiles, who will cover our major projects execution picture. So let's move on to Q&A. Yes, Andrew.

Question-and-Answer Session

Andrew M. Kuske - Crédit Suisse AG, Research Division

Andrew Kuske, Crédit Suisse. Al, just on the tilting returns, so going from high-single digits to low-double digits over a period of time, could you just give us a little bit of commentary around the competitive dynamics you face and really that tilt. So do you have lower returns in the front end just because of increased competition? Or do you have a view that you're more willing to take on volume risk than you have been in the past?

Al Monaco

Okay. So basically, the tilted return profile was effectively established when we entered into those very large projects. And a couple of them are the Gulf Coast initiative, as well as the East Coast initiative. And as well, Cabin enters into that equation as well. So when we entered into the projects, we had a view on what the initial profile would look like, and effectively, we established the tariffs based on the volume profile that we thought was there. And with that volume profile, there's more back-end weighted returns. So let's think of it as, Andrew, taking a little bit of a less return upfront in order to ensure that we were competitive. And then really, the juice or additional return comes at the back end as volumes move up. And in the case of Cabin, that is more prescribed in that the volume profile in take or pay are very specific and identified.

Andrew M. Kuske - Crédit Suisse AG, Research Division

So is it fair to say, just as a follow-up, that you're really willing to take a lower return in the front end to get the steel in the ground or just to build the plants, whatever the case may be, to preempt others, so you stake your claim and then you get an accelerated return over a period of time?

Al Monaco

Somewhat. Although I'd modify that by emphasizing that the initial returns are still very high-single digits, which would exceed our cost of capital. So that's always a premise. We're not simply going to buy the business. So we need to be careful to make sure that projects are accretive upfront, at least in the high-single digits for very strategic assets, with, obviously, double-digit returns over the longer term. So really, it's the same double-digit mantra that we've always had with a slight bit of tilt on the back end. And the position we're in today, the projects can be accretive upfront, which is the key driver.

Linda Ezergailis - TD Securities Equity Research

Linda Ezergailis, TD Securities. Al, I know that the growth outlook that you've presented comes organically from your existing businesses, especially the Liquids business. But would you see some value in looking at, perhaps, corporate transactions, even on a very small scale, to either purchase some long-term optionality, maybe in some strategic long-term, smaller platforms or geographies that you're not in right now or even opportunistically, perhaps, if there's some value out there, for example, on the international arena where you're not currently operating?

Al Monaco

Okay. Well, let me maybe start with referring to the comment I made earlier about large transformative acquisitions and the fact that we've got so much going on, we're not likely to focus on those, and just to kind of fill out the answer. We've got such an attractive growth rate right now. Every time we look at a large M&A possibility, and by the way, we do look at all of them, we find that the targets usually result in dilution to our own growth rate. And the last thing we want to do is destroy the organic potential that we have in the earnings and cash flow that come from that with a dilution of the growth rate. So that's the bigger picture. But yes, we would consider smaller-scale acquisitions that wouldn't have that same outcome and where we can essentially replicate the type of growth and optionality that we currently have in our business. So yes, where we can round out our strategy by taking on a smaller acquisition, we would certainly consider that.

Winfried Fruehauf - National Bank Financial, Inc., Research Division

Last night, I received no answer to my question about the future of Canada's petroleum industry if Western Access fails. I'll modify my question slightly this morning. What is Enbridge's plan B if Northern Gateway does not proceed?

Al Monaco

Boy, I'm not sure that I have much of a different answer than what you heard last night, Win. I mean, the project, or more generally access to the West Coast is simply an imperative for the country. The reason for that is because the alternative means further discounting in prices for producers. And I don't think that's a tenable situation in the longer term. So access to the West Coast, I think, is an imperative. We will continue to develop markets in the United States. That's going to continue to be a very large and important market. In fact, if you look at the projects that we talked about here, at least in summary form, most of that is in the United States and in Canada to ensure that we're connecting the growing supply to the market. So in terms of our plan A, we're really focused on making sure that happens within the next 5 years. Gateway, of course, is a longer-term opportunity, and we do think it's important for the country. It's strategic, certainly, for a producer point of view. But our plan A is being effected right now. So that's what I would say.

Winfried Fruehauf - National Bank Financial, Inc., Research Division

Follow-up if I may. It does not seem that Canada has a fan club of supporters of the Northern Gateway Project if one trusts the press. Suppose these non-fans prevail initially and pursue their objectives in the courts, where is plan B for Enbridge under those conditions?

Al Monaco

Sorry, you're referring to what happens if there's successful opposition, in other words the project doesn't get approved? Well, that's a long ways off, Win. The regulatory application and the process concludes at the end of 2013. I prefer to wait and see what the regulatory decision is before I speculate too much further. We have a good feeling that based on the application and the strength of the project and the support on many fronts that the project will receive regulatory approval. So until we get to that point, I wouldn't want to speculate on what we do after that.

Winfried Fruehauf - National Bank Financial, Inc., Research Division

But my question goes beyond regulatory approval. The real fight and the real problem starts after you receive regulatory approval, if you do.

Al Monaco

You're referring to...

Winfried Fruehauf - National Bank Financial, Inc., Research Division

Court challenges, wide-scale protests and so on.

Al Monaco

Well, once again, the first priority is to ensure that we get regulatory approval. I think it's way too early to speculate on anything that might happen after that. But we'll have to work through that at the time.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

My question is back to the growth aspect that you've talked about, and my specific question is what is in the plus, I guess, next to the 10% or 12% plus? And I'm sure Richard will speak to this, but just generically, in the past, you've talked about the plus being the volume growth, for example, in CTS or potential for drop-downs in EEP or ENF. I'm just wondering if those things are the plus? Or are they in the baseline number? Or what is in the plus?

Al Monaco

The plus covers the degree of capital success that we have beyond what's in the secured. And it relates somewhat to volumes but I would say primarily has to do with the number of projects that we can secure. So it's really the 2 elements, volume growth out of Western Canada and places like the Bakken and additional growth from projects. And remember that, as I said, the $5 billion that we have out in 2015, '16, captures a number of potential opportunities. So the actual projects that we're working on in that category is actually much larger. We've effectively risked that down to $5 billion plus. So volumes, additional capital projects.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Okay. And just one follow-up, which is on the business mix. I mean, historically, Enbridge has been mostly oil pipeline and infrastructure, which has served the company well. I think in the last -- there was a period over the last 5 years where we saw a little more diversification, green power and more on the gas front and midstream, and now we're moving just because of the organic growth where it is more, as you mentioned in your comments, a focus of mostly oil pipeline and oil infrastructure, which again has been good in the past. But as the new CEO, how do you feel about the business mix long term? Are you comfortable with Enbridge going back towards more oil pipeline and oil infrastructure? Or do you want to keep it a little more balanced with other types of infrastructure over the next 5 years?

Al Monaco

I think over the next 5 years, we're very comfortable on taking all of these liquids opportunities that we have off the table and executing those well. That's simply the main growth driver that we need to prosecute because that's what's going to deliver a lot of value in the next 5 years and actually beyond. Having said that, we do look favorably upon the fundamentals of natural gas long term. So in the long term, I could see us bringing that 70-plus percent earnings contribution from liquids down a bit, maybe not all the way down to 50% but certainly in that direction. The nice position that we're in, Matthew, is that we've got all these potential growth platforms that will diversify the earnings stream. But really, there's no panic. Because we have very strong near-term growth potential in earnings per share of 10% at minimum, likely 12% plus, we feel pretty comfortable that we're in good shape for quite a while. So if you look at Canadian Midstream or International, Electric Power, we can build those new platforms over time without really going too far out and being too aggressive quickly. So we're in good position that way.

Unknown Attendee

You've talked a lot about growth plan 2016 and want to extend that past 2016. And if we just look at, say, extending it at that 10% EPS CAGR baseline, with all of the tilted return projects you have and some of the embedded tilted returns in the existing portfolio, have you looked at what type of growth rate could you generate by just baseline doing nothing, just letting the volumes grow as compared to what the 10% target might be?

Al Monaco

I'm not sure if you can specify that, Richard. My gut feel on that is certainly over 5% -- probably in the 5% to 8% range is my guess. But without really getting down and stripping out all of that capital and seeing what that does, which I don't have at my fingertips, I'd rather not speculate. But I'm pretty confident that it's somewhere in the 5% to 8% range.

Unknown Attendee

You're pretty well down the road. Adding new projects will get you at probably 10, 10-plus is looking fairly visible here?

Al Monaco

Yes. That's a great point, and it helps me reiterate once again that we feel very confident about the 10%. And in some ways, it's potentially a little bit conservative, but that's kind of why we've said 10% looks very solid and then with those highly probable projects. And by the way, we don't put projects in that category in too lightly. They're very specific, and we have to have marched down the road to some extent in terms of developing the commercial underpinning. So the $12 billion that you see is real, and that's why we've gone to the extent of putting that other arrow on the chart, which talks about the 12% plus.

Unknown Attendee

If I can just ask one follow-up. You've said in the past that you expect cash flows to grow faster than earnings. Is that still the case as part of the revised plan being presented today?

Al Monaco

Yes, I think so. I mean, if you look at the last few years, we've put in a lot of capital into the ground, so we're going to see the ramp-up. We're going to see another ramp-up now with all the new capital that's going in now over the next couple of years. So I think you're right. It does provide an additional opportunity for a slightly faster ramp-up and cash flow versus earnings, gives us a little bit more opportunity and flexibility around dividend growth. But we'll have to see what happens on the dividend side when we get there. Yes, Juan?

Juan Plessis - Canaccord Genuity, Research Division

Juan Plessis, Canaccord Genuity. With respect to new growth platforms, just a point of clarification, perhaps. Does Electric Power also include electric transmission opportunities? Or is this a platform that you're less optimistic about?

Al Monaco

It's including both. So we have made an initial step out in transmission, as you know, with the MATL line. And we are actually looking at a number of opportunities on the transmission side. So it does include both. What we like about transmission, actually, is that it does fit the value proposition very well in terms of the returns that you can get in that business. And we do feel we have some reasonable experience and application of our skill set to that kind of project. So it definitely includes transmission. In fact, we're seeing a lot of projects on that side of the fence, and we're being a little bit choosy right now on that.

Juan Plessis - Canaccord Genuity, Research Division

And as a follow-up, what fuel types of power generation would you be interested in pursuing at this point?

Al Monaco

The primary one -- well, historically, it's been on the renewables front, on the wind and the solar. But I think if we had our druthers we'd be probably developing more opportunities on the gas-fired side. And that goes back to what I said earlier about our comfort around gas fundamentals in North America. So gas-fired generation would be an area that we would like to have some exposure to. Okay. Other questions?

Okay. Great. So I am the official timekeeper, I guess. I've been given that job by Jody. And the way I see it here, I'm about a minute -- I got a minute to go. So we are in good shape. So now I'd like to call Art Meyer up to talk about our focus on operations.

Arthur D. Meyer

Well, thanks, Al, and good morning, everyone. I'm pleased to be here to focus on operations, and I should note that the operating -- or the opening slide shows the picture of our Edmonton Terminal, and that is the start of our mainline system. And as you may be aware, the liquid pipeline system encompasses about 25,000 kilometers of pipeline across North America. Now some will recall I returned to the operations group in late 2010, following several years in Major Projects. We've had a busy time over the past few years with a very strong emphasis on safety. And I'm fortunate to be supported by an outstanding team of over 2,000 men and women who bring deep expertise in pipeline control, operations, pipeline integrity, engineering and asset management. Now as we start today, I'd like to begin with an update on the Marshall incident.

As you recall, we couldn't speak to that incident earlier because the NTSB had not issued its report. But if we go back in time to 2005, I'll first note that we did complete an internal inspection of the pipeline then using the latest technology available at that time. The NTSB concluded in their report that the inspection vendor had mischaracterized the cracks in the pipe that failed. They also concluded that if not for that mischaracterization, the pipe would likely have been excavated by Enbridge based on the company's integrity standards.

Second, the NTSB said that Enbridge had assessed the features in the pipe based on the information provided from that inspection, and they noted that the engineering assessment indicated the pipe would be safe for a period well beyond the next scheduled inspection in 2010.

And third, the NTSB said that Enbridge met PHMSA regulations in its pipeline operations. My point in referring to those facts, as determined by the NTSB, is that the company was committed to safety and regulatory compliance then, and we remain committed to those same principles today. We have completed our own analysis of the incident. We've reviewed the NTSB recommendations, and we've made a number of changes to our systems and procedures. We've also been asked by regulators and industry to assist in advancing the state of integrity management, technology and safety to new levels, and that's a role that we embrace.

Now the control center has also been an understandable focus of attention. Our staff had difficulty detecting a leak during a scheduled shutdown when the pipeline naturally de-pressures. They had the honest, but erroneous belief, that a column separation had occurred. When the pipeline was started, it was operated beyond our specified 10-minute limit for conditions that are outside the norm. Now I want to assure you that we have taken steps to address those issues, and I'll speak to those shortly.

Last in this area, I do want to describe my recent visit to Marshall. As you're aware, the river is now open. When our Project Director and I were there last Thursday, we saw people kayaking, fishing and enjoying the river. We saw flocks of Canadian geese, swans and cranes using the waterway. The facilities that we put in along the river, including access points for canoeists, portages and recreational sites were being put to good use by local citizens and their families. We're pleased with the restoration, and we receive many positive comments, as you'll note on the slide. We still have work underway, although our workforce is down to 3% of that, which it was at peak activity. We have paid the fine from PHMSA, and we're waiting for any other possible claims that may follow, and as always, we'll keep you updated on progress and costs in our quarterly reports. I'd now like to talk to some of our efforts to strengthen and enhance key operational areas.

As Al pointed out earlier, we are focused on industry leadership across critical safety and integrity dimensions. These include integrity management, safety, environmental protection, control systems, leak detection and response. I'll cover 3 of those areas to give you a sense of our efforts and direction.

In pipeline integrity, we have a dedicated Vice President and a team of over 100 engineering technical professionals. Now one of our initiatives was the launch of a major reinspection program, which began in 2011, and is progressing through this year and next. And by the end of 2012, we will have inspected over 16,000 kilometers of pipeline for corrosion and nearly 12,000 kilometers for cracks. That means we will have inspected internally about 75% of our system with one of these technologies or others that are comparable, depending on the needs of that segment. The inspection percentages is higher on our tape-coated pipelines, which is slightly over 90%. Now we do use a variety of high-tech tools to inspect the pipeline, and I'll speak to one for a moment, GE's UltraScan Duo with Phased Array Ultrasound. That technology is similar to that which GE uses for medical imaging, and it incorporates hundreds of sensors around the perimeter of the tool. The angle of those sensors can be adjusted, so that any point on the pipe is seen between 6 and 20 times. Those hundreds of sensors fire or take a picture of the pipeline every 1/8 inch or 3 millimeters of movement down the pipeline. You can imagine the level of data that comes from that. There's onboard memory that will store the equivalent of 20 Blu-ray movies. This is one of the tools that we're using, and to be clear, there's only one tool of this nature in the world, and we secured it for use on our programs where required.

We've also ramped up our remediation programs and we've targeted about 2,500 sites to investigate in 2012. We're drawing on our expertise and background in major projects to do those programs, and we're leveraging contractors and external workforce that allows us to ramp up and down quickly as the need may require.

Now I'd like to shift gears for a moment to operating the pipeline. We've named a dedicated Vice President over the control center, which ranks among the largest in North America. We've moved our operators into a state-of-the-art control center that provides an optimal working environment. As an example, the timing and intensity of light is regulated to reflect research into shift worker biological cycles. Filters suppress white noise to minimize distraction. Operating consoles, like the one you see on the slide, can be raised or lowered at the press of a switch to accommodate standing or sitting over the course of a shift. Technical advisers have been added to each shift, who can provide immediate support in the control center on a 24/7 basis. A senior manager over technical services with expertise on pipeline hydraulics is located at the control center, along with a team of dedicated engineering staff. We've also enhanced operator training. We focused on fluid hydraulics, which discusses how pressures change and how fluids move under different conditions of the pipeline. We've also, as recommended by the NTSB, have added team training to ensure that people on shift have the tools to effectively work together and complement one another's skill sets.

Another area of focus has been procedural. We've established the golden rules, which must be followed. One of these reinforces the need to shut down the system if an abnormal operating condition cannot be resolved within 10 minutes. We've also enhanced our management escalation systems to ensure that our Director and VP are engaged when required, and another area of focus has been regulatory compliance, given that we need to meet or exceed applicable standards.

I'll also take a moment to outline a few of the improvements that we've made in leak detection systems and technology advancement. We have applied new techniques to tune our systems and improve detection sensitivity, and as an example, we look at about 28 segments across the system and in 2011, we improved over half that number. We're doing the same this year. We're investing $150 million in retrofitting older pipelines with additional sensing devices and flow meters, like the ultrasonic flow meter shown on the slide. Our control systems group is implementing dynamic alarm thresholds. Now Enbridge has its own group that focuses purely on our control systems, and what they are doing is tailoring alarms to meet specific operating conditions. That could be start-up, shutdown or stable operation in between. That change will enable operators to focus on key signals when transitioning from one operational state to another.

On the technology side, we've spent a lot of time looking at systems to detect leaks during a shutdown. One approach is to detect the negative pressure wave that occurs when you have a loss in containment, and that wave travels down the system and one can use high-pressure monitors to detect that, and then rapidly shut the system down. So we are trialing that now, and we've had success on a number of segments.

On another front, we're using acoustic technology carried by tools that move through the pipeline, and that relates to pinhole leaks, which are very difficult for any pipeline operator to detect.

While we haven't had any leaks of that nature, nor have we seen those 3D acoustic tools, I can tell you that they are so sensitive, that we have found pipe that was exposed -- or on areas where we had some pipe exposed during construction, we have picked up road noise, external to the pipe. And as an example, the sensitivity of those tools, if one was to take a larger diameter line, let's say, operating at about 20,000 barrels a day or 20,000 barrels an hour, I should say, that's equivalent to 3 million liters an hour, these tools will pick up a release of 6 liters per hour. So we're down into the very fine percentages of detection. We're also looking at temperature sensing cables and petroleum vapor sensing, and some of these we'll use at our stations, but certainly, they have broader potential, and we're working with our colleagues in other divisions to test these.

Now in summary, we've made a lot of progress in the last 2 years in key operational areas such as pipeline integrity, control center operation, leak detection capability. We're really taking that same approach in other areas, and I didn't cover them today, but these include safety, environmental protection and response. We remain committed to our goals of safe and reliable operation without incident.

So that sums up a bit of the focus on operations, and I'm certainly pleased to take any questions you might have.

Andrew M. Kuske - Crédit Suisse AG, Research Division

Andrew Kuske, Crédit Suisse. Just a question on what you're doing, I mean, the reality of this industry, it's highly complicated, putting fluid through pipes, then having to travel a thousand miles or more. There's a bifurcation that's happened in the industry that's there's 4 or 5 large players that dominate this infrastructure, and then there's a scattering of others, so that really is the bifurcation that's happened. Do you see, really, an opportunity or threat, the fact that the larger players are doing a lot of things you're doing and with increasing level of diligence? And do you find that there's this chasm that's developing, which becomes a risk for the industry that you could have a greater propensity of leaks on some of the smaller systems in the rush to build infrastructure?

Arthur D. Meyer

So there are 2 aspects to that. First, many of these smaller pipelines are members of the industry associations on which we all sit. So I think that very much helps address part of that issue because we do work together. We work collaboratively, and that would be true of the Canadian Energy Pipeline Association, the Association of Oil Pipelines and the Pipeline Research Council. We also share information broadly. There was recently the International Pipeline Conference, where I think about 300 papers were presented. Approximately 1 in every 10 papers was presented by Enbridge staff or co-authored by Enbridge staff. So we do share information broadly, and I know that our peers in some of the smaller pipelines do take that into account. On the other side of the coin are the regulators, and the regulators, of course, want to ensure that incidents do not occur on any size of pipeline, and they, in turn, work with us and with other large operators to look at trying to align regulatory direction with the trends in industry. So I'd say those are 2 fronts that, at least, we work with other members of industry to try and ensure that we are aligned.

Andrew M. Kuske - Crédit Suisse AG, Research Division

And then just as a follow-up if I may. To what degree do you feel that the regulators in both Canada and the U.S. have to be brought up to speed on some of the trends that are happening? Specifically, in a lot of industries, we see the industries race ahead and regulators always playing catch-up.

Arthur D. Meyer

Sure. I'd say that in the current environment, there has been a lot of focus on pipelines. So certainly, the regulators are very engaged and understanding where we're at and where other companies are at. In fact, I met with the senior management of both the U.S. and Canadian regulators last week. We do update them on where we're at, and I would say people are pretty much in tune on the regulatory side with the leading edge of pipeline technology. I think the translation into regulation will occur quite quickly. There's an interest in doing so, and I know in the U.S., they've talked about releasing their version 2.0 of the regulation. So I do think we are seeing that pace kept up on both sides.

Unknown Attendee

Since Marshall, what changes has Enbridge made to its spill response procedures?

Arthur D. Meyer

Sure. We've instituted an enterprise-wide team that is available should a response occur. So that is one thing. We, in fact, had an exercise in Houston last week, where we brought about 200 people together just to go through a trial exercise to ensure that people were up to speed on procedures and so forth. In addition, we've spent in the order of $50 million towards new equipment that will be installed across our systems and available should the need occur. And we are also working with local responders and communities to ensure that they are aware of our systems and that they can provide support as required. So those are at least 3 examples. Hopefully, that's helpful. If there's no further questions, I'll then call in my colleague, Byron Neiles, to speak to the Major Projects side.

Byron C. Neiles

Well, good morning, everyone. My purpose today is to update you on the execution program that underpins much of the growth that Al talked about earlier on, and I'll begin with a short review of Major Projects or MP, we like to call it, capabilities and the value that our approaches deliver for our customers, and then I'll provide 3 examples of that experience at work.

MP has executed over $11 billion in capital projects since MP was formed in 2008. Our team of over 1,100 employees and contractors today manage over 20 projects for all Enbridge business units and we're certainly scalable to handle more, and in the field today, on both sides of the border, we have another 3,500 workers constructing and commissioning assets, and then we're led by 5 senior managers, all of whom have decades of experience in engineering, project management and commercial experience, and all of them have been project directors with the Enbridge organization in the past.

So moving to capabilities. Our involvement starts in developing proposals for the company to help it secure new business. We do this by nailing scope very early versus evolving scope which can relate -- or result in higher costs and schedule delays. All of Enbridge's estimate processes are tied to Association for the Advancement of Cost Engineering or AACE best practice, and we benchmark all of our estimates, and we're constantly calibrating our tools with the most recent cost trends and experience. And then our front-end loading approach, our approach to design and execution at the front end, which is a key predictor of success at the end embeds land, regulatory and environmental subject matter experts at the outset alongside of our engineers, and this gives us much more confidence in our proposals going forward.

From a supply chain perspective, the way we manage our supply chain generates considerable value for our customers. Our pipe frame agreement, for example, has provided better-than-market pricing since 2006, and we recently extended reservation capacity through to 2016. So this guarantees a few years out that we know that we have the space. We know what it's going to be priced at, and that helps us to reduce contingency dollars in our estimates, hence, making us even more competitive. And certainly, we have other frame agreements as well for equipment and labor, and where we're dominant particularly in the Canadian pipeline or mainline contracting community, we're able to lock in supply in predictable terms.

From a controls perspective, our confidence starts by ensuring that all projects follow the same mature project-gating control, and this is supported by modern project cost schedule and project risk management practices, which allows us to track at any time where we're at and forecast where we're going relative to our baseline plan. And as Al mentioned, the executive team reviews all of the projects with my team on a monthly basis, and our Board of Directors requires a written report and an in-person report at all of their meetings. So there is very robust governance.

Construction has always been in Enbridge's DNA. Decades of experience has paid off in minimizing construction risk. And in the relationships that we have with our contractors, which allows us to name the teams who support us, and based on the size of our spend, we're able to keep those preferred teams busy on an ongoing basis, and the net result of that is that we're able to improve on an ongoing basis our safety, quality and productivity record.

From a opposition risk perspective, we're well aware that opposition to infrastructure in North America is challenging, and we've seen that firsthand several years ago, and have intensified our efforts over that time to reduce the risk opposition can have on project cost and schedule targets, and what this means is very detailed [indiscernible] outreach for dating specialists in environment and permitting, land, law and government relations to ensure that stakeholders are consulted very early about our proposals. And as I'll get to with some examples, we can show you how that approach reduces the likelihood of any delay in approvals.

Industry, at large, today is seeing regulators expanding the public comment period at the outset, as these regulators are anticipating that there are going to be certain opponents taking those regulators to court and challenging those permits. So this trend certainly reinforces our emphasis on early and widespread outreach. And then, in parallel, our construction leads develop contingency plans and build those into contracts in the event we have to adapt to some changing developments, and this is in use in Michigan today.

So with that, I want to move now to 3 projects and the approaches we've employed to advance them, starting with 6B. So construction is underway for the 2012, '13 maintenance and rehabilitation program. But despite having received the approval from the Michigan regulator and agreements with landowners, owning over 85% of the required land, a condemnation was required for the remainder, and courts have continued to award access rights to Enbridge for more than half of those tracks with the remaining landowners appealing, and some courts are awarding us possession, while others -- other courts are encouraging settlement. Land acquisition is a very common project challenge, and this week, the parties in Michigan are discussing settlement, which will clear the way for us to continue our work through the end of the year into early January. But equally important with this, we expect the settlement that we achieve to set the framework for land acquisition for replacement work in 2013, and mitigate the need for these kinds of legal proceedings, and then our next milestone is the November hearing in Michigan to confirm the need for Phase 2 replacement.

The billion-dollar Athabasca Pipeline Twinning is an example of what can be achieved through very focused and early planning. It started with a seasoned construction hand, walking the line and feeding his observations into the design and estimates, and detailed engineering will be complete in December. We'll soon select our pump station contractors, and pipe is on order for delivery, commencing next August, well in advance of our winter 2014 construction. Pipeline contractors have already been selected, and the rate's set through frame agreement. And the beauty of this is it enables contractors to not only plan construction, but also to secure the best possible labor and equipment much earlier than is traditional, and the benefit for Enbridge is that we have cost predictability much sooner. And all of this is happening in parallel to the regulatory and land-acquisition processes. We have 99% of the land secured, with only one landowner issue in settlement. And with this issue resolved, and we expect that to be resolved later this week, and having successfully engaged First Nations, the hearing scheduled for December will be canceled, enabling our people to proceed into execution.

The $2.8 billion Flanagan South project will connect our Flanagan and Cushing Terminals in 2014, and unlike the Athabasca terminal, the Flanagan South, the project crosses 4 states, each state having multiple state regulators and also the requirement for a number of federal approvals as well. For example, we filed 4 applications with the U.S. Corps of Engineers, respecting the impact to water bodies and wetlands one month ahead of schedule, and this is par for the course in the U.S., where Enbridge has decades of experience in demonstrating need and securing multiple permits, both in states and federally. Detailed design, as with the other project, will be done in December and with it, we'll be able to go to the market for station and mainline contractors, so they can prepare well in advance for an August construction start. And in the U.S., we see a much looser market for labor than we do in Canada. 320,000 tons of steel is already in production, and we've leveraged key frame agreements for other pieces of equipment. Flanagan South is similar though to Athabasca Twinning in that the line will run adjacent to our existing Spearhead line. So we're very familiar with the territory and the landowners, and in fact, we've already secured 50% of the right-of-way required. Furthermore, we've hosted 700 residents at open houses to explain the project and take their questions and answer and follow them up. And we've had 150 face-to-face meetings with government officials at all levels, making sure that they understand and can support the project, certainly making sure that politicians have the answers to questions prior to a call from a constituent, can go a long way. And as an example, the Governor of Missouri, Jay Nixon, is so supportive that he held his own news conference, and has designated a senior state official to coordinate all permits in that state, and we're seeing similar support in the other 3 states on this project.

So to sum up then, while our 2013, '14 project roster is proceeding very well, these 3 examples, as a proxy for that, over the next 12 weeks alone, we will have commissioned the Wood Buffalo and Woodland Pipelines, horsepower expansion of the Wapasu pipeline, 4 new tanks in Edmonton, 7 new tanks at Cushing and 75 turbines at Lac Alfred, $1.4 billion in capital, all told, on or ahead of budget and schedule, with another $600 million in the form of the Bakken and Berthold real expansion, following hot on the heels in early Q1 2013. So as these projects that I've talked about that are going into service wind down, our project teams will be redeployed to project site or in development or in execution, where they can help repeat this successful performance in 2013 and '14.

So with that very quick overview, we'd welcome your questions. Thank you.

Unknown Attendee

Regarding the Line 6 replacement, how will it be kept whole with respect to the estimated $2.4 billion cost?

Byron C. Neiles

That's cost of service, I understand, Richard. So it's a flow-through of cost of service treatment.

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

Steven Paget, First Energy. Could you comment -- and I know it's not a very significant project in the capital cost scheme of things, just on the delays on that MATL line and what's holding it up, I gather, it's landowner issues?

Byron C. Neiles

Two issues, one is that the company changed the design parameters on the conductors to allow for increased capacity, so not unlike, where the pipeline adding pump stations, it's the equivalent. So that request as well as the request for landowners for fewer poles, higher poles, so there were longer spans affecting their ground in Alberta, has taken longer than what had been expected. We had the last interrogatory from the AUC last week, and we understand that we will have a decision sometime in the next 2 weeks. We're very far ahead in Montana. All the land issues and regulatory issues are finished there. All the poles are in place and we're close to 70% strung with the wire. So it's our sense that with the AUC approval coming within the next 2 weeks, we'll be able to deliver on the Alberta side in the first quarter. Well, with that, thank you very much.

Stephen John Wuori

Well, thank you, Byron, for that rousing introduction. And good morning, everyone. It's good to be back this year. It's hard to believe another year has gone by. Before I talk about the fundamentals of the Liquids Pipeline business, I do want to acknowledge both the areas that Art talked about and that Byron talked about, because I stay very close to both of those. To me, the work that Art kind of gave an overview of is an enabler to everything else that we do. It sets the foundation, gives us the license to operate, and as you heard, not only I, but the entire executive team stays very close to exactly what's happening there. And our goal is to have no incidents at all, 0 incidents. And even though that may seem to be kind of unrealistic, we very much want that to be the focus of all of our staff and employees to say we are going to stubbornly say that we will have a goal of no incidents and never be cavalier about any one. So I think that's extremely important, the whole area of safety, system integrity and operations. And then thinking about major projects, the area that Byron talked about, it's amazing to me because just under 5 years ago, we formed the Major Projects Group, then under Al Monaco, because we had something like $5 billion or so worth of projects to prosecute, and we believed that we needed an in-house construction, EPC type of a team. I think in 2000, early 2008 when that was formed, we assumed that by 2012, Al would just be sitting around listening to the lights hum or something like that, because we saw a dramatic ramp-up in the need, and then we thought it would tail off in terms of capital projects. The irony is, if he wants to know, he could sit around and listen to the lights hum and point to the rest of us.

But the fact is that it has continued to grow and grow and grow. And I think that, that move 5 years ago was tremendously important in setting forth all of the budgeting and cost control, the processes, the procedures, the stage gating, the procurement practices and the procurement deals that we have made with various suppliers, construction management and making sure that we secure good contractors on both sides of the border, and final commissioning and staying close to the operating people that are going to receive the facilities that Byron's team is building. All of that now has had 5 years of solid development. And I think that gives even more confidence to the billions more that Byron and the team are going to be asked to move forward with over the coming years.

So in terms of the business of crude oil then, I would say that it's been absolutely amazing to see what has happened. I think we've always stood up and talked about the growth in the oil sands, that has been well known for quite a few years. And the growth certainly continues there in the heavy oil as I'll come to. But the big surprise has been the light oil, the light oil production growth all across North America and even, I would say, in Alberta itself, where the sleeper is the amount of light oil coming out of the Cardium, perhaps the Duvernay and other formations in Alberta, high-quality light crude oil, that needs to enter the market and compete with the likes of light synthetic that's been upgraded from the oil sands or Bakken crude or other crude. So that growth has really been amazing to see. And it's really changing the dynamic of the North American marketplace. We -- as we've always said, we sweat the fundamentals. We are -- I like to think we are slavishly devoted to understanding the fundamentals of the marketplace, production growth, demand growth, market access and things like that, and hopefully, we can demonstrate more of that as I go through.

But the patterns generally that we've spoken of before, incremental heavy crude needs to go South and then West in the continuum of time. Incremental light crude growth generally needs to go East. I think I remember last year talking about that and from a fundamentals perspective that's, I think, still absolutely true.

Just in terms of supply, taking a quick look, you can see that the explosive growth of light oil shown on the right-hand side has really changed the game. The oil sands, heavy oil forecast is more robust than ever at 190,000 barrels per day of growth per year. We've never seen a number like that. Last year we would have been dealing with a number of about 138,000 barrels per day per year of growth in the coming 5 years, and now it's at 190,000. So the heavy growth forecast is robust, but the light growth forecast is even more overwhelming than that, coming from places like Western Canada there, the thin slice under the other, the Bakken, 2 key focus areas for us, but also the Permian, the old West Texas fields that everybody thought were tired and old. They're old but they're certainly not tired.

And actually, the remarkable thing in the Permian is that the pay zone is very thick. And therefore, they aren't even having to use horizontal techniques there. They're able to use vertical wells which are cheaper and high-volume, high-pressure frac-ing as they are in many other areas. And so the Permian growth has been and is expected to be through 2020, very strong. The Eagle Ford in West -- Southwest Texas is also very strong. Very, very light crude, incidentally, the crude that comes out of there. Some of that may make its way north to Alberta, as diluents, as condensate to add to the diluent pool. The Bakken has a very high-quality light crude. The Niobrara appears to be that way and it's an open question as to how much the Niobrara is going to proliferate. I've talked about Western Canada and the other category could be things like the Utica Shale in Ohio, and it is yet to be fully determined as to how oily that play really is or whether it's more like the Eagle Ford in condensate.

But certainly, when we look at this picture, we think it's important to establish pathways that we will tread for many, many years to come. Last year, we announced the heavy oil pathway to the Gulf Coast, and I'll do an overview of that. Byron just talked about a part of that. And I think now what we are very much focused on is finding the right pathways, pipeline pathways for the light oil growth that is before us.

Taking a quick look at 2010 and snapshots through 2025, you can see the phenomenon that's emerging from a supply perspective in North America: Canadian supply growing rapidly, U.S. supply growing even more rapidly. I think by 2017, 2016, the United States will be the largest producer in the world of crude oil, and who would have thought that. Just a few years ago, we assumed that its future was more and more imports, but the U.S. production profile looks very high. There's also a wedge called the High Shale Forecast, which brings in things like the Utica and other things that are not yet fully commercial.

All against the backdrop of decreasing demand, and that is -- that should be highly concerning to any fundamental economist. Because if you have decreasing demand and rapidly increasing supply, inevitably, that means classically lower prices, unless you can unlock better markets. And so our focus, and I think back to Al's comment about what's plan A, plan A is to unlock the best markets along the Gulf Coast and the East Coast and Eastern PADD II of the United States and Eastern Canada. That's plan A, and that's what we're really pursuing. Because that is the only thing that can interrupt that otherwise fundamental economic theory, which is demand is decreasing and supply is increasing.

The other wild card here is you notice that we've very conveniently shown almost no more foreign imports, that being Middle Eastern, Norwegian, West African by the year somewhere between 2020 and 2025. I think it's an open question as to whether that's ever going to really happen. And I think that the answer is no. I think that there will always be the flexibility and the reality of bringing in more crude -- bringing in crudes from elsewhere. But there is no question that the trend in the meantime is sinking foreign imports as more and more North American supply tends to self-sustain itself.

The other thing that's interesting is that pipelines have always moved away from ports. Crude oil pipelines have always moved from ports to the inland areas. And now the phenomenon we're seeing is exactly the opposite. Pipelines wanting to get to ports, get to tidewater and that's something that I think is a real sea change, no pun intended, in the industry. So what this all means is opportunity, I think. And I think, as Al alluded to, we have over $13 billion of secured projects that are underway. We see opportunities for another $14 billion of potential projects in the not-too-distant future.

We should spend a minute on the next slide on the issue of differentials. And if you look at the odyssey that is before you there from January of 2010 through roughly July of 2012, you can see that life was simple back in January of 2010. Let's call it the good old days, when pretty much things hovered around WTI, pretty much the market behaved in a rational way and so on. And you see what's happened just in the last 2.5 years or so, the wild fluctuations in differentials. Much more than the cost of transportation, one of Al's comments was that generally, differentials should equal the cost of transportation between Point A and Point B and you can see that there's very wide dislocations. Another thing you notice is that in-land crudes are generally discounted relative to the world marker, and tidewater crudes, represented here by LLS on the top, Louisiana Light Sweet, are generally able to trade at a premium to the WTI marker. And so what that tells you fundamentally, is that access to tidewater is very important in the whole North American picture if one wants to secure the best pricing for crudes generally speaking. Most of these here are light. There is Western Canadian Select, the WCS, that's the heavy marker coming out of Western Canada.

So to us, sustained differentials mean pipeline opportunity. Generally, if the differentials are and are expected to remain greater than the cost of transportation, that's a great pipeline opportunity. Those are the ones that we're targeting. I will make a comment that pipelines can thrive at much lower differentials than can rail or virtually any other form of transport except water. And so that's something to keep in mind, too, as we watch the rail phenomenon unfolding all around us. And also differentials are very volatile, and I just want to reflect on that for a second before we leave this slide. I have pulled up the current situation for your interest and contrasted it against the July marker.

So the way it sits right now, starting with WTI to LLS or WTI to Brent, and LLS and Brent are more or less trading on top of each other generally within about $1. So the differential as of yesterday was $20 a barrel between WTI and LLS. That's very wide. In July, it was at $13 a barrel. And one would think that, that differential should be tightening in, but a couple of things are happening. First of all, very high Cushing supply from the Bakken, from Canada, from the Permian, from the Niobrara, all coming into the Cushing hub, has created very high WTI look-alike or Cushing supply generally. And there's also very limited takeaway going away from Cushing. The pipelines northbound, including our Ozark system, are generally running full and in apportionment because there's a desire to move cheap WTI-type crudes to any refinery that can have access to them, which includes at the moment Eastern PADD II, Kentucky and Ohio. And the Seaway pipeline, which we started flowing on May 19, is only flowing just under 150,000 barrels a day, and that will be true until sometime in Q1 of 2013 when it will go to 400,000 barrels per day, and then of course with the twin project that's being worked on, it will go to more than twice that. But certainly, that differential is wide, and I think that's a couple of the fundamentals that are driving that. But watch what's happened with some of the other differentials.

Let's talk about Bakken, and when we talk about the Bakken marker, that is at a Clearbrook delivery point, which is the entry to our mainline system. Yesterday, that was trading at a $6 premium. So Bakken delivered to the mainline, the Enbridge mainline at Clearbrook was priced at a $6 premium to WTI. It was at an $8 discount in July. So you can see the huge swings there. And the same thing has happened with Edmonton light. Light crude from Western Canada versus WTI, which yesterday was trading at a $2.20 premium to WTI. And so that's tremendous. To think that you're able to sell crude on the pipe at places like Edmonton or Clearbrook at a premium to WTI, when everybody thought that you're getting hosed on the price. And that differential incidentally was $10 discounted on light crude at Edmonton back in July. Just to round it out, the heavy crude marker Western Canadian Select versus the heavy marker on tidewater which is Maya from Mexico was at a $17 discount yesterday closed in from the average that Al gave of $26 or $27 a barrel, which it was back in July.

So the point of all this is that differentials are very volatile. And incidentally, those 2 Bakken and Light Sweet at Edmonton premiums, the WTI, I think that's a transitory phenomenon. I think early in the month, generally speaking, people are worried about supply, Suncor is down at the moment with some of its plant. They're worried about supply. They pay up to get supply for the various commitments that they have. I would expect to see that normalize as the month of October goes along.

But what this tells you is that the differentials fluctuate very widely. And certainly, the transportation mode that's able most quickly to take advantage of fluctuations and dislocations is rail. And that's why we've seen the rail phenomenon really proliferate. It's an agile, here in U.S. we'd say agile, way of getting to market. You can build rail facilities for loading and unloading fairly quickly. But differentials have to remain large in order for rail movements to work. And rail movements can and will get turned off in a day if the differentials collapse. We've seen that happen at Cushing, big new rail facility not far west of Cushing isn't moving hardly a barrel these days, because the barrels once they are on the rail are going straight to St. James, Louisiana or to California or to Philadelphia or to the East Coast of Canada.

And so generally, that's something to remember. Differentials have to remain high and be seen to be remaining high in order for rail to continue to be viable. No one is building new track. You hear a lot about loading facilities and unloading facilities and rail cars being welded together, but nobody's building much for new track. And so at some point when you think about the rail phenomenon, which incidentally, you know that we are participating in with our Berthold rail facility, you have to wonder whether you have congestion issues, because pipelines unlike rail do not need a backhaul. Pipelines move in one direction. With rail, you have the rail cars all empty at the wrong end and you've got to, hopefully, get a backhaul of some kind or somehow get them back to the source.

So rail is currently accessing markets that pipelines don't. It's just that simple. You can't get any appreciable amount of crude to the Eastern Gulf Coast; St. James, Louisiana or Philadelphia by pipeline. And therefore, rail is accessing those tidewater markets and taking advantage, even at a fairly high transportation cost, taking advantage of the big differential. Again, WTI to LLS $20, leaves room for quite a bit of transportation cost. So in terms of who can thrive and who can survive at differentials, if you think about pipeline tariffs, almost always they run between $3 and $9. Let's just put our hand over it. In North America, generally, to get from point A to point B, if it's any distance, it will be $3. You know that our toll on the mainline system for heavy crude is $3.93 from Western Canada to Chicago. And then depending on how you piece the routing together, you could get up into the high-single digits for a toll. Rail rates of course run $12 to $16 a barrel. You got about $3 a barrel spent before you move it an inch because you're going to have about that combined on the loading and unloading and switching charges and so on. And so therefore, then you add the rail rates themselves.

So that's something to keep in mind. And by the way, just when you're wondering how far can the rail phenomenon go, I did a little bit of math, about the only math that I felt competent to do. And to replace the Enbridge mainline system alone would take 3,600 rail cars unloading every day, 7 days a week consistently to replicate the roughly 2 million or so barrels a day that we deliver with the mainline. So that, I hope, is a quick flyover of differentials, because that's a very important component of everything that we're looking at.

Now looking at the overall supply push demand pull picture. If you look on the left-hand side, you basically have the biggest resources, the Western Canadian Sedimentary Basin production and the Bakken, that are both connected to the Enbridge mainline. You should -- you can see that the CIBC forecast in Western Canada and the PIRA forecast in the Bakken are both considerably higher than ours. We would say about 2 million barrels per day of growth combined between the 2 up to 2020, CIBC and PIRA combined are about 4 million barrels per day of growth. And over on the right-hand side, you have what we analyzed to be the greatest areas of demand. And so we sit in the middle between the areas of biggest supply and the areas of largest demand.

And our existing footprint of the system, as well as the new tolling agreement, the CTS on the mainline, really gives us a leg up on development here, because we have the ability as a common carrier to attach new markets to that common carrier and pull the barrels through. So there's 2 stories that I'd like to tell: One is a heavy story and one is a light story, and I'd like to walk into that now.

Starting then with the Alberta regional infrastructure, you're familiar with most of this, especially the secured capital, the expansion of Athabasca and Waupisoo pipelines, the twinning of the Athabasca Pipeline that Byron referred to; the Woodland Pipeline for the Kearl, Exxon Mobil-Imperial Oil Kearl project coming into service soon; the Norealis Pipeline for the Husky-BP-Sunrise project; Wood Buffalo for Suncor which is nearly completed; and now the additional bitumen blending facilities for Suncor. All of that is in the secured capital category.

Beyond that then, we're looking at things like the Woodland Pipeline extension and we announced that we have regulatory approval to build that large diameter line, which essentially is a twin to the Waupisoo pipeline, very similar routing. The possibility of additional capacity needed between Cheecham Terminal, shown there, and Edmonton. Dealing with import line that we've been pursuing known as Norlight, and then additional infrastructure in the oil sands themselves. It leads us to quite a robust picture in terms of where we are in the Alberta regional picture.

In terms of heavy crude fundamentals, this is the buildup of the 1.5 million barrels a day of heavy crude growth from Western Canada that we are forecasting. And basically, the disposition I would say is as follows: Step one is to fill the cokers, the new conversion capacity in PADD II. That would be the BP Whiting refinery in Chicago, near Chicago, and the Marathon refinery at Detroit. That is step 1. Those cokers will be and need to be and must be filled with heavy crude. The second is on to the Gulf Coast where the only other accessible heavy crude conversion capacity really is and that would be our Flanagan South and Seaway projects that are combining for close to 800,000 barrels per day down to the Gulf Coast. The next tranche we've called other, let's call it XL for the sake of argument. We assume and we always have that XL is going to get approved and that XL is going to get built for 2015, and we've assumed that in this. And then beyond that Gateway is what takes over in terms of heavy crude disposition. When you've filled basically all of the accessible coking capacity in the U.S. then you really need to move offshore, and that would be into the Pacific basin not the Atlantic basin. There's very little heavy crude conversion capacity in the Atlantic basin. The Pacific basin, it's not by accident that we are looking at, as Al talked about, access to the Western market which includes California and the Asian market.

Moving on then, there are specific projects, and Byron touched on some of those. These are backstop by long-term take or pay contracts that range up to 20 years in length, and this would be for the Flanagan South project which twins and upsizes the Spearhead line and then the Seaway twin and each of those are shown there in the buildup. We have a good partner, a great partner in Enterprise on the Seaway part of that system and the ECHO terminal. And then we are building the Flanagan South portions that feed that.

Looking then at the light crude story, the Bakken. We have the Bakken projects that we've announced previously shown at the upper right of the slide: The Bakken expansion project, the Bakken Access Program and the Berthold rail facility. The next thing would be the Sandpiper pipeline, the Sandpiper project, that we are not yet ready to announce, but we're ready to talk about. Isn't that a funny way of looking at it? So that would be the next high-volume export from the Bakken project that we would be pursuing, and it would go to our mainline system, not at Clearbrook, but all the way to Superior to get past some transportation congestion that we see in the mainline between Clearbrook and Superior. We're working with producers to develop this Sandpiper concept. Rail certainly has been making a lot of inroads in the area, that's been a tremendous story in the North Dakota Bakken. And I'm thankful for rail, because quite honestly it has kept the production profile growing as it has been. That's also true in Saskatchewan. So that is the next potential capital would be the Sandpiper project.

The similar chart on light oil then says that first the growth of the 0.5 million barrels a day that we forecast the Bakken growth has to go to the Midwest and the Gulf Coast on pipe, and it's going to the East Coast of Canada and the U.S.; Washington state; Eastern U.S. Gulf Coast; St. James, Louisiana. It's going to all of those places now by rail.

So once we have the Line 9 reversal, we really think that's going to open up the lowest cost access to Eastern Canada via the mainline. And then into 2015, we expect to have further access initiatives in place, some of which I'll touch on in the following slides.

Then just looking at the Eastern Access program, expansions basically that support this whole idea of Eastern Access and most of these were announced quite some time ago, but all in the last year. They're all listed there, and we've given you the capacities of each one of those. And that is the building block, the foundation for the Eastern Access program, generally, expanding Line 5, reversing Line 9, twinning the Toledo pipeline, giving the Spearhead North pipeline -- the small piece from Flanagan to Chicago -- an expansion and also the Line 6B replacement that Byron touched on that will actually bring the capacity of that to 500,000 barrels per day. We also have financing flexibility. Some of these you'll notice are EEP and Enbridge joint funded and some are entirely Enbridge funded and we've tried to delineate with blue and yellow just which ones those are.

So in terms of the direction that we're taking, these green arrows and potential capital are really intended to say this is where generally things are going. I guess this would be the playbook. This would be the roadmap. This would be the pathways we're thinking about for light crude and where it needs to go for the foreseeable future, and in some cases, heavy crude as well. So starting on the upper right, looking at upsizing Line 9, perhaps, to not only meet the needs of the Québec refineries, which the reversal does, but also provide access to tidewater for spot barrels that can go to other Canadian refineries on the East Coast or elsewhere.

U.S. East Coast are going straight across basically to Philadelphia. That's a light market incidentally. The Canadian side is mostly light, there's some heavy crude capacity at the Irving refinery in Saint John, New Brunswick. The Philadelphia story is mostly all light and it's also probably a rail in both market, rail and tanker market. It is not a pipeline market in the near future as nearly as we can see. Eastern PADD II is very important refineries that would like access to the Bakken barrel, maybe the light Canadian sweet barrel that are currently running crudes that are sourced up from Cushing in the Gulf Coast and then Eastern U.S. Gulf Coast, both a light and a heavy market. There's good heavy crude capacity in the Eastern Gulf, the whole area around New Orleans and Mississippi, as well Pascagoula. And we see access to the Gulf Coast being important.

One of the questions we had last year, I think, was how viable are the Philadelphia area refineries? PADD I refining has suffered from the worst margins, maybe in the world. I don't know if that's exactly true, but pretty rough margins. And what's happened in the intervening year of course, is that rail has started to make real inroads into the Philadelphia refining market. We've also seen some interesting ownership changes of those refineries and that's created opportunities to move light Bakken barrels mostly over to Philadelphia. When you have 1.5 million barrels of refining capacity a stone's throw from New York and Philadelphia and other population centers, there's got to be some fundamentals for the business there.

Looking then at the mainline. We are adding pumping stations, no new pipe, but basically expanding Alberta Clipper on both sides of the border and also expanding the Southern Access Line 61. The potential capital then would include expanding Edmonton to Hardisty, which is a developing bottleneck in the system on the Western end; expanding Alberta Clipper and Southern Access to their full hydraulic capacity; expanding the Chicago piece, what we call Spearhead North or Line 62; Line 6B expansion through horsepower; and also some expansion for light crudes coming in at Cromer, Manitoba down to Clearbrook. So that all adds up to about $5 billion of potential capital that we could deploy generally on the mainline.

So if you put it all together, the Light Oil Market Access initiative is the specific items from the previous slides more or less brought together in this $5.5 billion initiative. And that would include Sandpiper, the Southern Access expansion, also the Southern Access extension from Flanagan to Patoka, which we've talked about in the last 4, 5 years quite a bit, and we were not able to this point to get commercial support to do that. There is interest in doing that, and so that would be a part of this if the commercial arrangements come together. The expansions I've talked about generally around and east of Chicago, that all comes together in this Light Oil Market Access initiative that we are focused on right at the moment. Primary supply would be Bakken, but also the Canadian light barrels. And if you look again at where, not only Canadian synthetic production is, but also the light oil being found in tight plays through the drill bit in Alberta, there's a lot of potential to move that light crude through this system as well.

So next to last slide is a build slide, and I'm sure there's somebody in the room sweating as to whether I'll get it right. The gray is just basically all of the refineries in North America, and I think what we really want to demonstrate here is what differentiates the Enbridge system from all others, and that is the diversity of market access that is and will be a part of the Enbridge system going forward.

So the first is the refineries that we generally access. The one funny-looking one is kind of in PADD IV. We do supply the Salt Lake City refineries with our frontier pipeline that we co-own with Plains. But generally, you can see in the green stars the areas of market access that we have now secured via the projects that we have been pursuing, going to the Gulf Coast, going as far east as Montréal and so on. And then the -- sorry, that was the current market access. Now the secured market access gets us more into the Gulf Coast to more refineries. Of course, it gets us fully into the BP Whiting expansion at Chicago, gets us to Detroit and Toledo with the Line 17 expansion, and then as far east as the Québec refineries are secured market access.

And then potentially, of course, you can see the red stars that now hover around the Eastern U.S. Gulf Coast, which currently is only served by Western Canadian and Bakken crude by rail. Eastern PADD II, that would be Kentucky and Ohio, largely, is a cluster there. And then generally, the East Coast are other opportunities for market access, not all of which may be by pipe incidentally, but that really gives a sense for what the potentials are.

So concluding then, I think it's fair to say that heavy crude growth remains strong. Light crude growth continues to surprise almost everyone in terms of just how robust and prolific it has been. Crude price differentials support our business. It's because of differentials that this business thrives. And again, pipes can thrive at much lower differentials than can virtually any other mode of transportation. And again, the $13 billion of commercially secured projects and then another $14 billion, if you add up what I've walked through of potential opportunities identified in the next 5 years or so. And we will continue to be the premier system for diversity or diverse market access. And I think that's a very important thing, because again, without the right market access, price is the victim. Price is always the victim in an area where you have rising supply, declining demand and not enough access to market. Price will be the victim, and we've seen that very often happen in the last couple of years.

So with that, I'll stop and see what questions you have.

Andrew M. Kuske - Crédit Suisse AG, Research Division

Andrew Kuske, Crédit Suisse. Steve, if you could just give us some context and color around your thoughts on potential conversion of TransCanada's Mainline from gas service to crude service to push further volumes to Eastern Canada. And then really, I guess the root of the question is if we compare that potential project with the Enbridge system of going through batching process, a lot of complicated transfers versus really dedicated line to north part of Toronto. Admittedly, new build has to be done, but if you just give us some color and context around your thoughts on that.

Stephen John Wuori

Andrew, there's probably a couple of dimensions to that. One is the complexity of removing such a conduit from gas service, what is its value, is the transfer value high enough to have a positive effect on the gas shippers on the mainline. I think all of that is wrapped up in areas that certainly I am not competent to answer and are actually being debated pretty robustly in the TransCanada Mainline hearing process. So there's the whole regulatory piece. There is the issue of plumbing, as you mentioned. There is new pipe needed at the head end, new pipe needed at the far end and connectivity and other things. And so that becomes a question of the CapEx necessary to do the conversion of the conduit itself and then build the connections on both ends. Having said that, it is a direct route. It is direct, more or less, from Alberta to the Ontario area, depending on where it would land and then extend from. But at the same time, it goes past no other markets. Whereas in the Enbridge system, you are showing the barrel to the Minneapolis refineries, the Chicago refineries. You're giving it the option to move down to the Gulf Coast if it wishes to, maybe to Eastern PADD II, maybe to Toledo or Detroit, maybe to Sarnia or maybe on to Québec. And so I would say that from a market optionality perspective, a bullet line concept like that does not have much optionality, although it certainly has the benefit of quicker transit times presumably depending on the flow rate and the ability to go all the way across without the longer distance. So I think it's going to be a balance of market optionality versus the issues around converting a gas line and what the CapEx is, and therefore, the needed tolls on such a system. I think our focus, really, is on the projects that I've talked about.

Andrew M. Kuske - Crédit Suisse AG, Research Division

So just as a follow-up, within that optionality, is it more important, in your view, to secure effectively refiners within that Québec market? Or is it more important just to have crude hit tidewater?

Stephen John Wuori

In our business, Andrew, when we're deploying capital, we like to have secured contracts for a minimum of 10 years, and we like longer terms than that. And so therefore, I think that to build a speculative pipeline just on the notion that hitting tidewater is a good thing, especially when pipe is nowhere near as agile as rail for example, is not something that would appeal to us very much because sure enough, just when you think the differentials are going to stay there forever and there's going to be a great arb somewhere on the East Coast for Western crude versus Brent or West African or Arabian crudes, it may close up. And so I think as a pipeline company, you really have to have secured commitments in order to make sure that the capital that you're deploying is not left hanging if differentials swing wildly in one direction or another. Having said that, it does appear that a light crude market exists in the East. I mentioned there isn't any appreciable heavy crude market, which is one of the problems with the very simplistic notion of let's go east instead of west because West is the only place you really can go to get at the heavy crude market to take the growth from the oil sands in heavy crude. But there certainly is a light market in the East, and that's why we're seeing the rail doing so much now to Eastern Canada as well as to Philadelphia, because there is that arb. It's just that when you're putting a pipe project together, it really has to be underpinned. And so kind of a long way of saying that I choose A of your 2 choices, which is secure refining commitments or producer commitments before just simply saying I want to get to tidewater.

Theodore Durbin - Goldman Sachs Group Inc., Research Division

It's Ted Durbin with Goldman Sachs. Can you talk a little bit more about the Sandpiper project? What are you thinking about in terms of capacity, maybe capital dollars? And then can you contrast it to the Oneok project that's going to try to take Bakken to Cushing?

Stephen John Wuori

Sure. Well, I think in terms of capacity or CapEx, I'd rather let that flow with an announcement if one is going to be forthcoming. And so fair to say though, it would be quite high capacity. If you look at the growth curve of the Bakken, there is no question that a conduit for more than 100,000 barrels a day or 150,000 or 200,000 barrels a day is probably needed even for the long term. But we'll let that develop. And that's part of what we're assessing as we look at the fundamentals of what's happening in the Bakken. The Oneok project, certainly, is in its open season. I think the main issue we would have is that we do not believe that the incremental Bakken barrel ought to go to Cushing. We think it's going to fight there with the Permian barrel, the Niobrara barrel, the Mississippian barrel, the Canadian barrel and a lot of barrels that are converging and will on Cushing, and we do not think that simply getting more Bakken incremental production to Cushing is the right price move for the producer.

Theodore Durbin - Goldman Sachs Group Inc., Research Division

And then the other one is somewhat on the competitive threat as well. If you think about potential for Capline to reverse that's been discussed sometimes, energy transfers, potentially going to change trunk line out to be an oil service to go from Chicago to the Gulf Coast. How do you think about sort of that north to south flow and the threat to some of the things you're doing on the Gulf Coast that exist?

Stephen John Wuori

Well, I think either one of the projects that you mentioned are complementary to what I've just talked about, which is that there is going to have to be access to the Eastern Gulf Coast market, that being the Mississippi River market; Saint James, Louisiana; New Orleans; Pascagoula, Mississippi and so on. Crude is moving there today from Canada and the Bakken by rail and barging down the Mississippi from St. Louis. And so in fact, there even was at least one very tired batch that went from the Trans Mountain dock in Vancouver through the Panama and all the way up to one of those refineries. And so either of those projects, a reversal of Capline or conversion and reversal of the trunk line gas system, which is a publicly announced intention of Energy Transfer, I think would be complementary to our view just in terms of where crude needs to go next. And Eastern Gulf Coast is certainly one of those. I won't handicap what's more likely to happen. The Energy Transfer project has made its FERC application to abandon gas service and convert to crude, and so we'll see how that plays out. And of course, Capline is not simple. It has more than one owner, and they probably have views that they form on their own. But certainly, as I said, either one of those would be intended to accomplish part of what I've just talked about. Rob?

Robert Kwan - RBC Capital Markets, LLC, Research Division

Robert Kwan, RBC Capital Markets. Steve, can you just talk about whether it's something you encountered as part of the Gulf Coast or Eastern Access initiatives or whether you anticipate it going forward, but have you received any pushback on the Mainline being a common carrier system yet you're seeking firm transportation onwards? And are there any plans to do something, either [ph] what Trans Mountain did to try to allow for firm transportation, whether that's on the existing portion or some of the Mainline expansion?

Stephen John Wuori

I think one of the hallmarks of the CTS agreement for the industry was that they wanted the system to be a common carrier, the main trunk system with no commitments required, nobody's balance sheet has to be put up against it, we do it on a 30-day nomination basis. I think what we've -- the approach we've taken rather than try to allocate space and get regulatory approval in 2 countries to do so is to get firm space committed downstream that will pull the barrel through and then make sure that we have the capacity to be apportionment-free on the Mainline common carrier. I think that's the approach we've elected to take to this point rather than trying to allocate specific tranches of space on the Mainline, which, I think, is pretty problematic under the CTS agreement, which, really, is founded on the basis of it being a common carrier. And that was one of the things, I think, that the industry really valued a lot, was having at least one line, a large system that isn't contracted, leaving Western Canada.

Robert Kwan - RBC Capital Markets, LLC, Research Division

You don't anticipate -- or there wasn't, and you don't anticipate any concerns of shippers who will want that firm transportation capacity all the way through?

Stephen John Wuori

There wasn't. I can't guarantee that as things unfold, that, that might not be an ask or some design feature that some shippers would like. I think though our approach of just continuing with the Mainline expansions to stay ahead of that issue, that would require firm space. The only reason you would require firm space is if you fear apportionment and keeping in mind that at least in the United States, FERC requires a premium for firm service rather than a discount for committed firm service. And so it probably is less simple to look at doing that.

Robert Kwan - RBC Capital Markets, LLC, Research Division

And if you can just talk about the contracting practices for the light crude for these services and typically, at least in the past, they've been wanting to cheat to the shorter contracts. Do you get the sense with some of the differentials they're seeing that they are quite a bit more willing to look at the contractual terms that you're looking for?

Stephen John Wuori

That's a great question. Generally speaking, the tight oil players in the Bakken and other tight plays have not been accustomed to making long pipeline commitments on their balance sheet. We did get some of those commitments for the Bakken expansion program from producers that heretofore had not really done pipeline commitments. So that's a good sign. I wouldn't say that there is a groundswell of producers who are willing to sign long pipe commitments in places like the Bakken. I think they view that they will take whatever pipeline capacity is available on a common carrier basis, and they will rail as the flywheel, as the compensator for what they can't do by dent of pipe capacity. That's just a general thought, is that -- now if the differentials become so compelling due to production that rises beyond, say, our forecast and looks more like PIRA's, you could see maybe a change in view on that.

Al Monaco

Just to go to the risk side of the equation really to emphasize what Steve said there, in that situation where you've got a little bit of reluctance by some of these tight oil players, the downstream takeaway, the commitments on the downstream pipes, is really important to us. So in the case of the Gulf Coast Access for example, we have Flanagan South commitment, Seaway commitments, Eastern Access. We've got commitments on Line 9. And in terms of Steve's discussion around the new light oil initiative, we're going to have to focus on downstream commitments on Southern Access extension and then further into the Eastern Canadian market. So from our point of view, we have to deal with this reluctance sometimes for these light oil shippers, and that's the way we do it is to make sure we have downstream take.

Stephen John Wuori

I would say as a general thought, Robert, that the Western Canadian producer is much more attuned to the idea of longer-term pipe commitments than some of the others in the shale plays.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Steve, Matthew Akman, Scotiabank. On that front, in Bakken, a lot of the expansion has taken place, from North Dakota and then direct north up to the Mainline through Quebec and Canada. And now you're talking about a pipe that goes kind of straight across, I guess, to Wisconsin. What is the rationale, I guess, the driver behind the change in direction? Is it the potential for longer contracts that's driving that larger project? Or so much growth in Saskatchewan that, that piece of pipe north of [indiscernible] is full? What is driving the new, I guess, direction on how you're planning on moving Bakken crude?

Stephen John Wuori

Yes. Great question, Matthew. I think you do what you can when you're doing it. I don't think that's terribly profound. But I think at the time we proposed the Bakken expansion program, which is now over 2 years ago, A, I don't think anybody saw the explosive growth continuing in the Bakken like we're now seeing. Secondly, we already had an idle piece of pipe between North Dakota and Saskatchewan that we laid many years ago to move crude south that was available to us, and we were able to put together very attractive toll-wise proposal for shippers to come into the North Dakota system, move up this new Bakken expansion program, part of which is that idle pipe, and then move over to the Mainline system at Cromer. They will do very well. Those shippers are going to probably have the lowest tolls of anyone other than the legacy North Dakota shipper that's moving on the common carrier now. The way things look to us right now, and I think you touched on it, there is an issue of congestion developing in the Mainline upstream of Superior. And so therefore, bringing in more to Cromer would probably not be as good as coming across and going down into Superior. So that's the rationale for how the chronology has taken us here.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

And I guess as a related question, just a follow-up, how would you -- what would the economic model be behind the expansion of the Mainline that you talked about to handle more light oil? Would it be handled just within the CTS? Would it be kind of an additional toll or surcharge? Or would it be a completely different kind of agreement outside the CTS?

Stephen John Wuori

Well, I think everything will be done within the construct of the CTS. That's a pretty powerful 10-year agreement. And so I think the plan would be that CTS would generally be the mechanism. Now having said that, we didn't ever intend that the CTS toll would never change. And that's part of our discussion with the industry, is that though we notionally capped our toll at $3.85 a barrel for heavy crude to Chicago plus inflation, certainly we did not contemplate that we would spend unlimited expansion capital without any adjustment to that, and that's part of our discussion with the industry. The other part of it is to the extent to which the downstream commitments help to pay for the Mainline expansion by dent of the volumes being drawn through. It is -- CTS is clearly volume driven. So there's probably 2 parts of the equation in play there. How much do the simple draw through of those guaranteed volumes -- what does that do for the economics versus what do we need from the industry in terms of a CTS toll adjustment? And we are pursuing both of those.

Chad Friess - UBS Investment Bank, Research Division

Chad Friess with UBS. A lot of the more distant plans in the growth profile are a little bit contingent on light oil production growth from the U.S. Bakken as well as Western Canada. But we've seen a little bit of a pullback in drilling and maybe the pace of growth lately. So my question is how confident are you in those growth plans? And there's some pretty divergent views out there. And does that impact your willingness to take risk on new projects?

Stephen John Wuori

The answer is yes. That does impact our willingness to take risk, and that's why when we've looked at the Bakken production profile rising in some people's minds to 1.2 million barrels per day, we have no intention of building pipe capacity for 1.2 million barrels a day out of the Bakken for exactly the reasons you are alluding to. And that is that the business does fluctuate. It's like a lung. It expands and it contracts and you have high rig utilization rates in one area. Nobody will admit they're drilling for dry gas anywhere. They're all drilling for wet gas or oil. But we know these things cycle. We definitely do. And I think it's worth watching the fundamentals of natural gas going forward. With the dearth of drilling for dry gas, maybe a price response is in the offing, even though it's hard sitting in one place to think it's going to be different tomorrow, and gas prices have been so low for so long that it looks like all the rigs should stay deployed to oil. But I think your question really comes down to the extent to which we believe we should take risk based on drilling forecasts and production forecasts. And the answer to that is not that much because either we will contract for the volumes to inoculate ourselves from things that we can't control like drilling rates or we will stay considerably under the production growth profile in terms of pipe capacity. So that's, I think, the approach we're taking because there's no question that we have to watch very closely the explosive growth of light oil and ensure that it's really a trend versus an anomaly.

Chad Friess - UBS Investment Bank, Research Division

And I guess regardless of what the northern part of the continent produces, the southern part of it is pretty robust, a lot of production coming from Texas. So are you seeing that, that new production from the southern part of the continent is backing out that Northern crude and thus making the Eastern Access projects more viable? And I guess are you indifferent as to where that light oil crude production growth comes from since it both supports -- they both support your [indiscernible]?

Stephen John Wuori

Yes, that's an interesting concept. I think the answer is that it's not backing out the Northern volumes, but the price is the victim. And that's the issue with not having good market access everywhere that you need to is that basically you're going to move the barrel because you simply must sell it. And if you're competing with an Eagle Ford barrel, you're going to have to price below an Eagle Ford barrel as an example. But it really does drive the need for this Eastern movement that I was talking about. And I think I hadn't thought about whether we're agnostic, really, as to where the production growth comes from. I think our bias, obviously, would be to Canadian -- Western Canadian and North Dakota growth as opposed to elsewhere. But all of it feeds this fascinating phenomenon that's taking place, including the Eagle Ford, which, of course, is a stone's throw from Houston. So we've got to realize that Eagle Ford barrels land pretty cheaply in the Houston marketplace. Some question as to whether it's too light, whether it's too much like natural gasoline or condensate and whether that barrel probably needs to end up in Alberta. So that's another part of the equation that's fascinating to kind of consider. But the fundamentals, no matter -- I guess no matter which side of the coin you look at, the fundamentals say, "Go east, young man. Go east."

Al Monaco

Just to add on to that briefly and to emphasize Steve's point around ship or pay contracts, that is critical part to our value proposition, Chad. And so that's what we're going to focus on continuing to do. We are getting -- the difference is in this environment, we are getting a lot of calls because of the price disparity. I've think you've seen producers want to have firm capacity. And frankly, that's what's leading to some of the discussion around the TCPO [ph] gas Mainline conversion. Your earlier point around you're seeing a slowdown, I think the rigs are just about totally focused on oil. And if you look at the stratification of F&D costs throughout North America, certainly the light oil barrels, particularly in the Bakken, ranging from the $50 to $65 mark, are positioned very well relative to the other finding costs throughout North America. Whether it's south in the Gulf Coast or relative, of course, to the oil sands, I think the Bakken is in pretty good shape that way.

Stephen John Wuori

Any last question? Okay, here. I'm conscious that I've overrun the coffee break by 6 minutes, and I honestly don't know the consequence for that. Is that right? Okay. So we're still okay because this machine is saying -- okay. Terrific.

Maria Berlettano - J. Zechner Associates Inc.

Maria Berlettano, J. Zechner Associates. All of this frenzy reminds me of the gold rush, and of course, for some prospectors that made it near the end, by the time they got there, the rush was over. So my question to you, Steve, is in the context of what's going on today and all your building plans, how do you make prudent decisions today to make sure that we don't have an overcapacity situation in the pipeline industry in 10, 15 years from now?

Stephen John Wuori

I think if you look at the production growth curves or profiles, our view is not to be trying to attack the top of that curve and try to nip that off with pipeline. Our view would much more be to deal in the core and compete for the core that's going to be there for a long time to come. And so whether it's going to the Gulf Coast with the Flanagan South projects or the Bakken project, I think that's the key, is that the pipe really shouldn't chase the top of the curve. The pipe shouldn't chase that barrel that could turn out to be whimsical. What the pipe should do is compete very much for the core barrel, some of which may today be on rail, but should be movable to pipe with better economics and market access. I think that's the view, and we're very much conscious. And that's why our own forecast, I think, is so much more muted than the others. I think consistently, we are hundreds of thousands of barrels per day under the general forecast out there from PIRA, CIBC or whoever because we are taking some of that into account and making sure that we don't look like Jeremiah Johnson kind of thing, showing up late and being very much hoping that a production profile will emerge. I think what we're really about is not relying so much on hope but on what appears to be certainty. And I think it's a great -- it's kind of back to the earlier question Chad raised about are we seeing any tail-off in this right now. It will be fascinating to stand here a year from now and just see what the growth curves look like. Are they more robust? Or are they less robust? And of course, the whole backdrop, again, is falling demand. That we can never forget. And so you have a tremendous phenomenon that we'll remember one day where you had falling demand in North America and rapidly rising supply and all of the things that happened to that. And generally speaking, no exports. And so part of the answer is exports. There's no question. And that's really what brings us to the Northern Gateway Project, getting another bit on the crude, another market for the Western Canadian barrel at least. I just think we feel that's very, very important for the industry and the country.

Any other questions? Okay. I guess we're on to the break and reconvening at 10:40. Thanks.

[Break]

Leon A. Zupan

All right. Well, in the interest of time, while everybody is grabbing one more cup of coffee or a muffin, I will go ahead and kick off the gas side of our presentation. It's certainly an interesting position for me to be in, having spent 25 years on the crude side of our business. I've spent about the last 5 months on the gas side. But the one thing that I've noticed is that a lot of similarities in terms of where the 2 business have come from and where they're going. Some unique challenges, certainly, in the gas side these days, but a lot of opportunities. I'm going to spend a little bit of time this morning to talk about some of the fundamentals, and then we're going to bridge into a number of the exciting opportunities that we have in front of us in the gas business.

So I'll just give you a preview of some of those opportunities as we go forward here. So I got a bit of a build slide because we got a number of different things that we're working on over the course of the next few years here.

So first and foremost, we have seized the Canadian midstream. I'll talk a little bit more about our development with the Cabin Gas Plant in the Horn River, British Columbia. I'm going to spend some time talking about a lot of things, but not a lot on LNG. We have been working with producers to come up with an industry-based solution. There's not a lot more I'm going to cover off on this side of the opportunities today. But let me just indicate that after working in BC for the last 10 years on Northern Gateway, we believe we're in very good position to develop a project there as well.

We have been in the gathering and processing business in the U.S. for quite some time through Enbridge Energy partnership. And along with our ownership in Aux Sable, we believe we're in a very good position to capitalize on the many rich gas opportunities in front of us. And by leveraging these facilities and our expertise, we really believe we can expand our NGL position in the rich gas in both Canada and in the United States. And I'll also speak about our ability to capture that upside through our joint ventures in both Alliance and Aux Sable. And you would have noted recently that we have announced another JV with Spectra and DTE on the Utica pipeline. We'll touch a little bit about what's going on in the Utica and how we're going to play in that area. And then lastly, the area that I also look after is the U.S. Gulf Coast and the significant upside that we see in the Gulf Coast on the oil side of our business.

So let's start off with some of the fundamentals as everybody else has done here. We've got some exciting projects, and they're really, I think, well suited to where we see the natural gas and NGL business going. Let's start on the production side of the equation here with North American natural gas production. We've certainly seen some very rapidly evolving drilling and completion technologies being put in place, and it's really allowed them to reduce the drilling time. And so even though the rig count's down a bit, we're seeing that they can turn those rigs around very quickly and bring on more gas. Particularly the case with respect to shale. You can see here the big blue wedge on the graph is really about what we expect to see happen on the shale side, about another 50 Bcf a day -- growing to 50 Bcf a day by 2025 here.

And when you look at the conventional side of natural gas, although we've seen a decline over the last little while as people pulled out of some of the dry gas drilling, you're seeing by about 2015, 2016, it's pretty well stabilizing. And we believe that with tight gas coming on the market, we're going to see the conventional side plateau mid decade and beyond.

Looking at the disposition side. We've got the slide on the right indicating our view of where we think the demand for gas is and will be in a high crude environment. We've spurred -- we will spur renewed interest in natural gas as a feedstock for the fertilizer and the petrochemical business, particularly in the United States, in the Gulf Coast. And we expect gas-fired generation with coal retirements over the next couple of decades to represent about 55 gigawatts of conversion, which will represent about another 5 Bcf a day of additional demand.

And coupled with the other areas that you see on the graph there, we really see a growing demand by about 15%, representing about another 10 Bcf a day of demand, which really is going to start to affect the amount of production that can come on and find a home. And lastly, at the very top is the net export wedge. There's a lot of discussion going on in our industry right now as to where LNG will go. We really see a need for exports in the long term here and particularly off the U.S. Gulf Coast and the West Coast of British Columbia.

Looking at the NGL fundamentals, flight to rich gas is really what we're seeing in all of the drilling that we have. And even though some of our more traditional assets in the north and east Texas systems have been largely dry gas, we're seeing that rich gas is being found and brought on stream and looking for processing capability down there, and we expect that trend is going to continue.

With that increasing supply of natural gas liquids has come a fairly sudden retraction of prices. We've seen a warm winter impact that. We've seen some tightness in having enough gathering and processing capability on stream to be able to handle that as another one of the issues. But really, it's the high supply that came on very suddenly versus demand for particularly ethane and propane that has had prices come down a bit in the last year, certainly a big change from last year.

But we really see that the facility side in the demand is well positioned to start picking up and address those bottlenecks, particularly with plants and new fractionation coming on in the Gulf Coast and the ability to export to tidewater. So when you look at supply and demand together, we believe that, that lower feedstock price that you're seeing in North America right now, what's already made North America the cheapest supplier of ethylene in the world, and we think coupled with the ability to export even more NGL product to Mexico, to Central and South America, is going to be able to balance out supply and demand on that growing NGL supply picture that you see there.

And the last piece of fundamentals I wanted to talk about here is commodity prices. We had seen natural gas prices stabilize at around the $4 and then drop off significantly with that warm winter that we experienced last year. But looking ahead, we see recovery coming on the natural gas side of the business. And really, that big surplus that was created in inventory has largely been drawn down due to a warmer than normal summer and a big air conditioning load, and we think that prices over time are going to continue to improve that side of the business. On the frac spread for NGLs, I think we believe that over time, you're going to see, although probably a wide variance of where it could be, it's still going to be well above the traditional frac spreads that we've seen in the past. And we really believe with the build-out of the petrochemical complexes you're going to see a good demand for NGL and its products as we go forward here.

So now I'm going to move into some of the upsides in the exciting projects that we're seeing in the gas business. I think we're very aligned with where some of the changes in natural gas and NGLs are going. And in this particular graphic here, you see the Alliance Pipeline system, a 2,300-mile unique rich gathering and transport system for gas that we own about 50% of, terminating at the Aux Sable plant in Channahon, which we own another 43% of. It provides very attractive netbacks for customers for their natural gas as well as their NGLs.

And the footprint that you see there really covers off the major fields where rich gas is being developed in both the Northern U.S. as well as into Canada and in particular, Alberta and into BC. And one of the interesting stats is that we've probably come within 25 miles of all of those major fields, and that we've seen over the last little while that the amount of gas from those fields has increased by about 6 Bcf a day even though the overall Western Canada supply has been in a somewhat small decline. So we're very well positioned, and we're looking favorably to where Alliance is going to be.

In fact, this morning, they announced to their customers that they're going to be rolling out a whole new suite of options for them as their legacy contracts expire in 2015. They've got a very unique and flexible system, and I think you're going to be very interesting to see what they can do to add value for producers, for marketers, for LDCs, in terms of repositioning their system from really a single-service single-toll pipeline to one that offers a host of opportunities to customers, including toll certainty; zone, service and term differentiation; and the potential for market-based sharing mechanisms with their customers. So more information is going to be coming available shortly in October here, and I know people will be looking very closely as to what that suite of services looks like as we go forward.

Looking at the Aux Sable side. Here's a very recent picture of the Aux Sable site. It's the largest gas processing site in North America. It can handle 2.1 Bcf a day and process about 100,000 barrels a day of NGLs. But rail and truck loading, that you can see in the far right of that picture, is continuing to expand. They're doing about double the business they did a year ago, and they have the ability to double that again over the next foreseeable future here as really we see it being a very attractive plant for people to bring their NGL to. And Aux Sable is going to be able to grow their business in a three-pronged approach that I'll cover off now.

First and foremost, Aux Sable has shown that they've been able to align themselves with the rich gas producers who really have high BTU of gas that we really want to track to the Alliance system and process down in Channahon. And they're doing that with a rich gas premium, which really is going to allow the producers to avoid putting in costly deep-cut plants in a lot of these areas. And in fact, you see a quote there from Cequence Energy that indicated how much doing a deal with Aux Sable really benefited their company. And I think they've also said publicly that they've saved $30 million to $35 million in capital, which is allowing them to put more drill bits into the ground rather than paying for infrastructure. We see that continuing with a number of customers that Aux Sable has and will be doing business with.

Secondly, the expansion of their rail yard is allowing them to bring Marcellus gas. Some of it is being trucked, but most of it's coming in by rail and they're going to be very well positioned to do the same thing on the Utica. And finally, Aux Sable continues to work for opportunities to expand their physical presence in both the Western Canadian Sedimentary Basin and in the Bakken. And here's a couple of maps that really show you how well positioned that we are in these areas.

So starting at the top is the Bakken area, which is really a lot of very rich gas that's coming off of oil production. You've probably heard about the many players that are going on in the Bakken still today. Well, the picture here shows the Palermo gas plant and the Prairie Rose pipeline that were acquired by Aux Sable and have the ability to take even more rich gas in, in the future here. And just this past week, the FERC announced the approval of the Tioga pipeline system that will have about 100,000 Mmcf per day of capacity. It's got about 60% commitments already, and so it has a lot of upside to start tying in more rich gas associated with oil drilling in the Bakken.

And at the bottom, you can see the 2 major field plays that are happening in the Duvernay and the Montney, which are really very rich gas that everybody is talking about doing a lot more drilling in. And as you can see from the red line, the Alliance system goes right through that. So we think we're going to be in very good position to be able to start capturing that rich gas and bringing it into market.

Another JV that we have recently talked about is the NEXUS pipeline project. NEXUS is going to be about 1 Bcf pipeline, about $1 billion in capital and it's a joint venture between ourselves, DTE and Spectra. We're looking at being able to take that Utica gas, which incidentally is probably the lowest cost gas to produce in North America. I think their breakeven costs are around $2 a barrel, and be able to bring that into not only Michigan and Ohio and Ontario LDCs, but also to industrial and power generation companies in Ohio as well. We see it really being an attractive pipeline to get into Vector and into the Dawn Hub in Ontario, which is the third highest physically traded hub in North America right now. We really think that Vector is going to be the right way for that to get to market. It is connected to a lot of places already both in Michigan and in Ontario, and we have expanded Vector 3 times since it went into service. It's now at about 1.3 Bcf a day, and we believe that Vector is going to be continued to be well utilized well into the future.

Let's talk about capitalizing some of the other rich gas opportunities. Here's the map of Texas and our kind of legacy gathering and processing business. It certainly has provided tremendous insight for Enbridge into the North American natural gas and NGL business, as well as providing us an active role in the development of the shale revolution that's happened down there as well.

We've got our 3 primary assets there in Anadarko, the large East Texas system and in the North Texas system, which is the oldest of the 3, but is really in the heart of where it all started, in the Barnett Shale in the Dallas/Fort Worth area. In 2012, it has been a challenging time for that business. We saw some fairly significant declines in commodity prices. But producers are continuing to find rich gas, as I say, in all 3 of those areas, and we have seen the opportunity to continue to expand our value chain there.

Particularly in the Anadarko and Granite Wash area that you see in the northern part of the Panhandle, we've completed 150 million cubic feet per day Allison plant at the end of 2011. We have a very similar sized plant called Ajax that's going to be coming on mid this year under Byron and the Major Project team. And we believe that with those 2 coming on, we'll actually be close to 1 Bcf a day of processing capacity out of the rich gas coming out at Anadarko and Granite Wash. And finally, as we see prices continue, we do believe that those very prolific dry gas fields, particularly in East Texas, are going to be drilled up probably just a little bit later on than where we were last year.

One of the things that Al highlighted in this role last year was a very exciting enhancement to the NGL value chain, which is really our participation with Enterprise and Anadarko. And then DCP midstream in the Texas Express system, a $1.1 billion system which we own 35% of, 580 miles in length that really is tying in a lot of NGLs coming in from the Rockies, the Niobrara and local volumes at Skellytown, Texas, down to the premium fractionation point in North America, which is really Mont Belvieu, where everybody would really like to get their NGLs as we move forward here. It's a strategic project for us. It's also a project that's based -- that's fee-based and that, coupled with our capacity and fractionation in Mont Belvieu, is going to provide some stable earnings going forward into the future. But we will also be able to continue to tweak that system as we see more gas coming on in all 3 areas.

The other big announcement after last year's Enbridge Days was our Canadian midstream prospects. We alluded to it last year and shortly thereafter, we announced the partnership with Encana and the Horn River Producers Group for $1.1 billion worth of infrastructure that really is in 2 very large 400 million cubic feet per day processing plants in the Horn River. Cabin 1 is about 92% complete and will be finished in December, and we're currently at about the 50% completion rate for Cabin 2. And the photo you see there is really indicative of the significant size of the Cabin project up in the Horn River.

We have future phases of the Cabin project, as well as more dry gas is going to be required for LNG export, and we see the opportunity there and in other parts of Western Canada, say about another $4 billion of projects that are available as really the gas producers are looking for the midstream solutions to take away their gas and provide their facilities. We see this particularly in the Montney and Duvernay, of which we have a very good footprint with Alliance. And working with Aux Sable, we think we're going to be able to attract a lot of those and be able to provide the infrastructure to go with that.

The last major piece that I'd like to talk about is really covering off our offshore business. We have seen that with low gas prices and the Macondo incident in 2010, that drilling in the Gulf did suffer, particularly on the natural gas side of the business. But what was recently announced in the Wall Street Journal is really what we're referring to as an oil boom. We see a significant potential for new production to come on as people put more and more drilling into the deepwater. I think it's pretty clear they've taken a very serious approach to how to deal with it safely, and we have done the same thing when we take a look at providing physical infrastructure to tie that in.

Drilling permits are up. The amount of areas where people are appraising activity is continuing to increase. And as operators invest tens of billion dollars -- tens of billions of dollars in this oil play, we think there's going to be a lot of associated gas and the need for infrastructure for both the oil and the gas side. We have 3 commercially secured projects out there totaling about $0.75 billion that are going to be brought on stream in 2013 and 2014, including the Walker Ridge Gathering System that's shown in the yellow oval there -- sorry, the yellow system on the graph, the Big Foot Oil gathering system and the Venice stabilizer in Louisiana shown by the red star there.

We're using a very similar business approach that got us these 3 projects. We're working with a number of producers on the gas and in particular the oil side of the business, and we're very excited about our position, our expertise and what we'll be able to announce into the future in the development of the Gulf. Particularly areas of focus are the Green Canyon/Walker Ridge area, Keathley Canyon as well as some of the -- finding unique and value-added ways to make our customers want to do business with us into the future. We see great opportunities for this side of the business. It may take us a little while to get us to that 50/50 mix that Al spoke about earlier. But we are in a good position, I think, to be able to start capitalizing on growing our gas business as well.

And with that, I would be happy to take any questions.

Andrew M. Kuske - Crédit Suisse AG, Research Division

Andrew Kuske, Crédit Suisse. To what degree do you believe the BC government wants a million BC solution with BC-produced gas heading out to the West Coast via LNG as opposed to tapping into a little bit of the plays, which are really on the Alberta-BC border? And how does that kind of strategy, if that's what the BC government wants, ultimately affect things like Alliance?

Leon A. Zupan

I think my view would be that BC probably can have both. One of the challenges on developing LNG is that you're going to need a very large supply source. You can't afford to build a very expensive liquefaction plant on the West Coast and take 5 years for it to fill up. So I think the strategy that allows Alberta and BC gas to initially flow to the West Coast, the ability to bring on more liquefaction over time is going to allow them to probably see all of their gas, if it needs to, head west. And where it doesn't, to continue to use the existing systems that can allow it to go south and east.

Andrew M. Kuske - Crédit Suisse AG, Research Division

So do you believe over the longer period of time the Alberta gas gets effectively dislodged from going to LNG on the West Coast?

Leon A. Zupan

I think there is the opportunity for both. I think with the gathering systems that are in place right now, it's going to give a lot of optionality for gas to go in both directions depending on where the markets are. One of the first things that really has to be decided is how are you going to price LNG gas and how is that going to compare to the growing price for natural gas in North America as demand continues to increase. And of course, the oil sands. You've got about 1.5 Bcf of new demand that's going to be required for the oil sands. It's going to take a lot of Alberta gas and find a local home for it. But I think net-net, when we look at the forecast, we believe that there is the room for BC gas to go west. There's room for Alberta gas to potentially go there in the short term as well as to go into the oil sands and to go down the Alliance system and down to Chicago and on to Dawn. Yes, Laura [ph]?

Unknown Analyst

Looking at your Cabin future opportunities, I would imagine you're probably already in some preliminary discussions regarding LNG export opportunities, et cetera. First of all, what would be Enbridge's view in terms of how LNG exports would be additive to the production profile in Western Canada? And can you comment on where you see Enbridge having the best opportunities to participate in exporting LNG?

Leon A. Zupan

Well, I think when you look at the reserves that are out there now, you've got at least 100 years of gas out there. We've gone in the space of about 4 years from talking about LNG imports to now LNG exports. As we continue to see technology drill up some of these formations, I think there's the ability to bring on a lot of gas in a short period of time. And so as a result of that, we really believe there is a good opportunity to see LNG come on board in the future. That's the top part of our wedge. I think the biggest issue that you need to do is to bring all of the pieces together. And so when we talk to industry about a solution, we're ensuring that we've got a good supply base that can be drilled out in the right period of time that we can provide the right infrastructure to get to the right tidewater port, have the right liquefaction player and most importantly, have the right markets established that will give the price sensitivities, the price signals back to the producers to know that they can now go ahead and start drilling up these big, big fields that are out there.

Al Monaco

Make a -- maybe just make a quick comment to add on to that. You'll probably see us play primarily in a space where we can bring our low cost of capital to bear, and you saw that happen in the Cabin project. So I think reserve certainty and ability to underpin the LNG liquefaction is really the key. So I think the producers will look to us for that midstream capability which has -- which gives them certainty on that and where we can really leverage our low cost of capital providing, of course, that we do have the commercial underpinning for that. And that fits very well with what they ultimately will want to underpin a long-term liquefaction plant.

Linda Ezergailis - TD Securities Equity Research

[indiscernible]

Al Monaco

Yes, I mean, that's a good point, Linda...

Leon A. Zupan

Do you want to repeat the question?

Al Monaco

Yes, the question was would we consider power generation. I think generally, yes. Mostly because it would have the same commercial underpinning, which is if we can get a long-term contract for gas to supply a power gen facility, we would do that. We -- and just to be clear, though, we are not working on anything like that at the moment. But certainly, it's something we would consider.

Winfried Fruehauf - National Bank Financial, Inc., Research Division

To what extent does Enbridge balance liquids pipeline expansion with the potential strong penetration of the transportation market in the United States by NGV?

Leon A. Zupan

Well, the liquid side of that question is probably best answered by Steve. But from the work that we've been doing and see going forward, we really see that over time in a gas price that's somewhere in that $3 to $4 range, you're going to see a lot of interest in liquefied natural gas going for transportation. How much of an impact it has and how quickly, I think, is going to be a function of how quickly natural gas prices recover. We've seen that happen on the propane side years ago where people switched to propane vehicles and then the price of propane went up and then that market pretty well disappeared. But I think a lot of big fleets that don't go very far have already started down that path. And so it has the potential to continue. I think it will become a function of what's the spread between liquids prices and on the oil -- crude oil side versus natural gas. And if we continue where we are right now for a little while, I think it's going to have the ability to start bringing on more transportation based on natural gas. And I'll turn over to Steve and see if he has any comments on how it affects our long-term vision.

Stephen John Wuori

Sure. Winfried, I think the way the rough numbers work is that if the entire U.S. heavy truck fleet was converted to NGV, if would take about 2 million barrels a day of crude oil demand off the market, and that isn't insignificant when you consider that Canada's exports accrued to the U.S. are about 2.3 million. So it is certainly a factor. As Leon said, some of the dense transportation corridors are going that way. I don't think I can see in the foreseeable future that the entire heavy truck fleet is going to do that because of the distances in the infrastructure, the lack of NGV fueling infrastructure for the trucks all across the country. So it will be a factor, but I don't think it will be anywhere near a 2.3 million barrel a day factor. However, every bit of it is in the direction of what I was talking about earlier, which is sinking demand for crude oil.

Leon A. Zupan

I just want to add one quick point to the original question by Linda here. One of the things other than the cost of capital that will be important, I think, going forward, and I know we've mentioned this many times today, but the major projects execution capability as far as underpinning the midstream work that's got to happen to make all of these LNG projects that are being talked about go. And for us, that's where we bring some additional value to the table. There's probably only 3 or 4 players in our space that can really undertake the magnitude of these LNG-related midstream opportunities, upstream of the plant and that's probably a good position for us as well as the fact that was mentioned that we have some good experience already on Gateway.

Unknown Analyst

Just a question on LNG export. What's sort of the baseline assumption with respect to a level of sustainability in LNG exports from North America?

Leon A. Zupan

Well, I think there's been a number of experts who have given their views that they could see as much as 6 Bcf of gas eventually going off of the United States. We have projects being announced, 3 projects in BC, that could take another 2 Bcf a day of gas further west. But it's really a question of timing. First of all, there's the political question of what will be agreed to or not agreed to in terms of natural gas exports in the United States. The BC government is very, very conducive to seeing that type of development, the National Energy Board and the BC government seemed to be fine with the export permits and improving the pipelines and the facilities. And of course, working with the First Nations to make sure that it's a partnership in terms of how it's being developed. So I think we can see that with the amount of gas reserves that are out there with the right price signals, you can still see a world where that type of export capability could come into play. There are other things that could challenge that, but the biggest one to date has been prices. And of course, everybody is looking for an oil-based price for an NGL market that may occur or it may be some sort of a hybrid between oil and gas to make sure that both the markets and the producers are getting some sharing of that. It's very difficult, at this point in time, to see how big that LNG market in terms of the demand is going to grow, particularly in Asia. But you're talking 20 to 25 Bcf increased demand over the next 10 to 15 years. And so there is a big market that needs to be served, and we think North America is going to be part of that solution.

Okay. If there's no other questions, I promised Richard I'd give him a little bit of time back that we used up this morning.

Thank you very much.

D. Guy Jarvis

Thank you for that rousing introduction, Leon. Good morning, everybody. I'm very happy to be back here again this year to talk to you about our Gas Distribution businesses where we find ourselves in a very interesting and active time. There's a lot of regulatory activity underway. We're executing our largest capital project in 20 years. The natural gas supply landscape is changing. And importantly, we're continuing to grow our distribution franchise.

Our growth is underpinned by the current low natural gas prices and the general expectation in the market that while natural gas prices may rise, they will be stable in the longer term. This view paints a picture that sustains our strong competitive position versus competing energy sources in our franchise.

The greater Toronto area continues to grow largely driven in franchise regions that we serve. While much of our growth will be centered around assets already in the ground, the compelling story of our competitive position is leading to the potential to extend to communities that were traditionally viewed to be uneconomic to attach. The result of these natural gas and regional fundamentals is that we expect to maintain our position as one of North America's fastest-growing natural gas utilities.

Leon spoke about some of the changing natural gas supply dynamics, and I wanted to address how these are impacting our business. I suspect many of you are active in your own assessments of new natural gas supplies in the Marcellus and Utica, so I will not spend much time speaking about the basins themselves, other than to say that we believe they have proven that they are not a flash in the pan and that they are here to stay for a long time.

As you know, the cost of gas is a pass through in our Gas Distribution businesses, and we do not profit from it. The commodity and related transportation portions of our bill, however, account for greater than 50% of what our customers pay. So we have a significant obligation to ensure that they continue to have access to competitive and reliable supplies. The reality for our customers is that the changing face of supply in North America represents a huge opportunity to reduce the cost of gas over time while attaching to growing long life new reserves. The pricing influence of these new supplies and their regional location advantage can already be evidenced by pricing in today's market.

A snapshot of expected October pricing to our Toronto City gate from last week, highlights the deliveries from Dawn have an approximate dollar $1.46 per gigajoule advantage over Western Canadian supplies delivered via TransCanada. While this baseload price advantage is very significant in its own right, the closer proximity of the new production and expected lower demand charges on pipelines that will deliver the gas to Ontario will allow us to realize significant cost savings, as we structure our portfolio to meet our winter base load and peaking needs. This opportunity's not simply going to manifest on its own, however. We need to be active in making the right decisions about the design of our system and about our portfolio to ensure that the required infrastructure is in place to allow our customers to continue to benefit from this new supply.

Our proposed GTA project, in part, very much takes into consideration the changing gas-supply landscape. On September 6 of this year, we announced our plan to move forth with the most significant upgrade to our distribution system in 20 years, through a $600 million project to construct 47 kilometers of high-pressure pipeline along with related stations and regulating facilities. We expect to file the project with the Ontario Energy Board in November. And if approved, it will come into service in 2 phases, late in 2014 and 2015, respectively. The benefits of the project center around serving our growth needs while increasing the reliability and flexibility of our system.

From a growth perspective, we've added approximately 800,000 customers over the last 20 years with much of this growth creating new load centers that need additional high-pressure supply. From a reliability perspective, it addresses issues related to each of our key pipeline providers. The origination point of the project will be at new facilities planned to be constructed by Union Gas, which while also addressing future growth needs, will provide that all supplies destined for our franchise on the Union system will now have 2 distinct and effectively redundant delivery paths. As it relates to TCPL, declining volumes on its system have led us to design the project in a fashion that maximizes our own ability to address an upset condition, as we project TCPL's historical ability to help us is declining.

From a flexibility perspective, the key-on system benefit will be an increase capability to manage flows throughout the GTA in the event of an unforeseen disruption of our regular flow patterns. And in terms of positioning for upstream supply access, the new facilities will allow us the flexibility to source gas supply from the Marcellus, from Dawn or from Western Canada.

This slide illustrates how our continuing growth and the GTA project translate into a substantial capital expenditure profile through our strategic planning horizon. As with the underlying business itself, this capital represents a continuation of investment in a low-risk stable business. As the chart shows, the capital for the GTA project will not fully become part of our rates until 2015 and 2016 as the segments come into service. But given that time line, it will be a critical consideration in how we structure our next regulatory framework for 2014 and beyond.

Given that we are in the last year of our 5-year incentive regulation model, I want to provide some insight into our regulatory status and risk-adjusted return expectations. During the incentive regulation, you can see that we have achieved a growing powder blue wedge of incentive earnings over the term, which has largely offset the declining underlying base return on equity. In fact, in the last 2 years, we have successfully moved near the upper boundaries of incentive earnings that are allowed by the current model. 2013 is required to be a cost of service year, and I'm happy to report that we have reached an agreement in principle with our customers on all matters but one. That settlement is being documented and will hopefully be filed with the OEB any day now.

Both ourselves and Union gas has sought an increase in our equity thickness from the current 36% and that matter is going to hearing for both utilities. It is important to point out that by going to cost of service in 2013, it allows us to achieve the Ontario Energy Board's ROE formula that was updated in 2010 and provides us with a better starting point to build upon.

Looking at 2014 and beyond, we're getting close to being able to more aggressively develop our new plant. The cost of service foundation is in place, the OEB is providing all utilities with better guidance on several models to consider going forth, and we've been actively consulting with our customers.

Our current model provided for up to 300 basis points of upside potential and while it may be more difficult to achieve given the benefits that flow to our customers through 2013's cost of service rebasing and the growth of our underlying rate base, we believe we can structure a model that offers meaningful upside to the business while meeting the needs of our customers. In terms of our future expectations for a return on equity, the slide illustrates that much like we experienced in our first incentive regulation period, the incremental returns will take a while to ramp up.

So just to wrap up on this slide, we're feeling like we're in a pretty good spot here. We have established a solid relationship with our customers, we have an attractive underlying ROE which we expect will firm up as interest rates change direction, and we expect another 5-year model which will allow us to continue to drive enhanced value.

So in summary, we believe we're well positioned to access new gas supplies. We expect our strong competitive position to be sustained. We are executing the largest capital project in 20 years, and we expect continuing favorable risk-adjusted returns will support continued low-risk growth in earnings and cash flow.

And with that, I'll be happy to take any questions.

Andrew M. Kuske - Crédit Suisse AG, Research Division

Andrew Kuske, Crédit Suisse. Guy, do you see any changes to your views on TransCanada's ability to provide gas through the mainline at competitive rate when you think about the recent announcement of the Lennox plant and really the settlement between the government of Ontario for what happened with Oakville and that being a substantial draw for incremental gas supply. And then also, in addition to that, what changes do you anticipate to your system to really supply that plant or any prospective plants for natural gas within your service territory?

D. Guy Jarvis

Okay. So first and foremost, the Lennox is in the Union Gas territory so it will mean very little to us. I think our view on that type of new gas load in the eastern end of the TransCanada system is positive. We want as much volume to be on the eastern end of the system as possible to help make the tolls there more economic. We are concerned about the current situation. We're not sure that the or we don't believe that the TransCanada proposal that's out there represents a long-term solution. We're concerned that some of what they've got in their proposal actually will make it more difficult to come up with a long-term solution. So changes need to occur, and we're concerned about the pace that they're getting there. The tolls in TransCanada and their ability to bring Western Canadian gas is becoming more than a TransCanada issue. It's about the supply forecast. And our duty as a utility is to ensure that our customers have access to multiple basins, to ensure not only competitive prices, but the security as well.

Andrew M. Kuske - Crédit Suisse AG, Research Division

And then just as a follow-up. Within your service territory and the connectivity of your service territory and Union's, what kind of further infrastructure opportunities do you see really driven by gas plant developments?

D. Guy Jarvis

Right now, we do not have a lot of new ones that are being seriously proposed within our franchise area. We'd certainly love to have more. We know that certain parts of the electric business within the province feel the need to continue to look at building them closer to the load centers. We'll see how that evolves over time. But right now, there's not a lot of activity.

Stephen Dafoe

Stephen Dafoe, Scotia Bank. Do you anticipate getting a special bump in rates for the GTA project, if it comes into service in the middle of a 5-year IR interim?

D. Guy Jarvis

Well, you might be referring to another utility here in Ontario, who tried to bring forth a major capital project in the midst of an IR period, and didn't receive very favorable reviews on that from the Ontario Energy Board. So going back to the point that I didn't make it clearly enough, is within our next 5-year incentive regulation model, the treatment of that capital will be one of the cornerstones of the model. One more, okay.

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

Steven Paget, FirstEnergy. And just a question of when we're seeing lower bond rates in the overall market, could that result in pressure to slightly decrease ROEs using the old NAV formula where it was long-term bond rate plus-plus to get an ROE?

D. Guy Jarvis

Well, I think -- well, first and foremost, the OEB when they set the new formula back in 2010 indicated that, that was not something that they were going to look at again until sometime in 2014. So it is a little bit -- a little ways off. I think the question really boils down to, I think, the board at the time that they changed the formula was taking a longer-term view that said, we need the utilities to be in a position to attract long-term capital to make their long-term investments. So how they might be influenced by the shorter-term goings-on and their own views of how short-term, short-term is may or may not factor into that. All right. With that, I'm going to transfer the podium over to Richard Bird. Thank you.

J. Richard Bird

Good morning. So I took on responsibility for the executive leadership of this collection of our new growth platform businesses earlier this year as part of my corporate development hat. They're a relatively small part of the Enbridge story from a near-term earnings perspective, but they play a bigger role in our longer-term strategy, laying the foundation for a more diversified future asset base and for continued growth and prosperity in a future energy economy with a lower liquids hydrocarbon intensity.

Electric power generation and transmission is a platform that we believe offers some promising prospects. There will be continued growth in North American power demand, and that's in contrast as Steve Wuori mentioned to really a shrinking demand for crude oil. Renewables are expected to play an increasing role in meeting this demand and gas-fired generation even more so as coal-fired plants are retired. With a very substantial corresponding investment in generation plant, that's going to be required. And the transmission system will also require significant investment to accommodate the growth and to tie in the more remote renewable sources of energy.

Our renewables business is reasonably well established with nearly 1,000 megawatts operating or under development. It's a small part of Enbridge, but we're actually a pretty good-sized player in the renewable space. Our existing asset base is heavily concentrated in Ontario, but our focus for further development is Quebec, Western Canada, the U.S. northwest, and the U.S. southwest, and these are generally the areas we see as having the most attractive combination of wind or solar resource and the best market opportunities. We plan to double our capacity in the 5 years from 2011 to 2016, and we'd like to gain a foothold in the gas-fired segment by then.

We expect to see lower policy-based incentives supporting growth in renewables in the future. However, we expect to see that's going to be offset by technology enhancements and lower capital costs. And we're involved in a few promising technology development ventures ourselves through our alternative and emerging technologies group.

We're looking forward to seeing our first transmission project, the Montana-Alberta tie line go operational in the first quarter of 2013, as Byron mentioned earlier this morning. The Montana section is well progressed and actually portions of that have already been energized. But we are about 4 months behind schedule in Alberta due to land owner and regulatory challenges. Once that's in service, we'll follow very quickly with doubling the capacity of the line and then with the green line extension to the southwest, and both of those are well in the money based on current local power price differentials. We're also looking at opportunities for additional transmission investment in both Ontario and Alberta.

Most of you would know that by the middle of the last decade, Enbridge had a fairly significant international asset base which we then sold off at very attractive prices to help fund our last growth spurt. We've maintained our international presence since then through our Enbridge Technology Consulting and Training arm, but we plan now to reestablish an asset position. We think the same advantages that we previously brought to the table continue to apply and as do the same investment criteria which guided our prior investments. We'll focus on countries like Colombia and Australia with strong energy export fundamentals, favorable investment climates and significant infrastructure development needs.

Lowering the microscope a little on Columbia. Here we have a country with a supportive policy environment for resource development, with resulting growth in crude oil production. The geography is interesting with an East Coast enabling exports to the U.S. Gulf coast, which is where the existing pipeline infrastructure is pointed, but also a West Coast, from which Asian markets could be economically accessed. Enbridge has a positive history and relationship with the government and local producers, including Ecopetrol, the national oil company. We are sponsoring the development of the Oloeducto al Pacifico pipeline. Effectively, the Colombian version of the Gateway project, with significant support from potential shippers in that project. So it will be interesting to see which project moves barrels to Asia first.

I'll finish up this section with a few comments on our Energy Services business. This business provides marketing and logistical service -- services to small and medium-size producers who don't have the specialized staff to move their production to market, and is also providing supply sourcing and delivery services to refiners who augment their in-house supply department staff in this fashion. This is a steady, low-margin business at its core, but it does provide a base on which to capture physical arbitrage opportunities of various kinds which open and close as markets evolve. These include point-in-time arbitrage, crude quality management and location arbitrage opportunities, like the simple example that's depicted on the upper right-hand chart.

So the example illustrates that there's a $10 disconnect at present between pricing at Cushing and at Patoka, with a transportation cost of only about $1 to move crude oil from one to the other.

What does it take to capture a piece of that arbitrage? Well, it takes first of all access to physical barrels. You have to be able to lay your hands on the barrels, either by having them in storage or by having arrangements in place with producers. It takes relationships with refiners and the knowledge of their preferred crude specifications and it takes a logistical capability, including access to pipeline and storage capacity, as well as scheduling and nominating expertise. Pipeline capacity can be held by contract or often by historical nomination rights.

Having these ingredients doesn't mean that energy services can pocket the whole $9 arb. That depends on how liquid and transparent the market is at both ends of the arb, and it often involves negotiation with a small number of potential buyers. And we're not necessarily the only ones in the game. Then by their nature, arbs are temporary imbalances. And sometimes something will come along to arb them away by their nature, whether it's additional pipeline capacity, whether it's railing or whether it's just competition.

So our Energy Services group is always on the lookout for new arbitrage opportunities to replace existing strategies as they close down.

Recent developments for this business include the initiation of a crude by rail strategy and extension of the term of some of our arrangements in order to stabilize the earnings contribution from this business rather than have it fluctuate as those arb opportunities arise and then dissipate.

To wrap this section up, I'll just say that between them, these new growth platforms are well positioned to fulfill the group's strategic mandate of diversifying our asset base and building a foundation for longer-term growth with a modest contribution to near-term growth and to our insight into market development opportunities as a bonus.

And on this section, I'll take your questions now.

Winfried Fruehauf - National Bank Financial, Inc., Research Division

Regarding OAP, is 2016 still the expected start-up date? If not, what are the reasons for delay? And also, what is the current estimated capital cost?

J. Richard Bird

So 2 questions there, 2016, I don't think we've fixed in on a firm start-up date for that. If it was 2016, I guess it would be ahead of the Gateway project. That project is still in the early phases of development, Winfried. We've kind of gone through a basic scoping. We've got partners on board to fund a next step in the process, but I think it's a little too soon to be putting a firm date on a start-up. And your second question, just remind me?

Winfried Fruehauf - National Bank Financial, Inc., Research Division

[indiscernible]

J. Richard Bird

Oh, CapEx, yes. Same thing there, really this next phase, we'll get into more detailed engineering and establish a capital cost, so little too soon to land on that as well.

J. Richard Bird

Okay, I am seeing no other questions on this section. Going once, gone. Okay, I'm going to move on now to my other half, the finance side of my responsibilities. So Al spoke earlier about our exceptional array of attractive investment opportunities, $35 billion in aggregate that we are planning to invest in growth on an enterprise-wide basis from 2012 to 2016. And you've seen the details of many of these opportunities in the business unit presentations.

So I've laid out on the chart here just the distribution of that $35 billion across our business units and by the 3 layers that we categorized that capital into in terms of certainty. It won't be much of a surprise that the greatest portion of this opportunity is in our Liquids Pipelines business. Growth investment in our other businesses is substantial in absolute dollars. It's not that they're not coming up with great opportunities, as both Leon and Guy described, it's just that it's somewhat dominated by comparison to the Liquids Pipelines side of the business.

To clarify the 3 components of the growth capital that are included in the plan, the commercially secured layer is the same concept that we've been using for many years. And it corresponds to projects that have reached a sufficient point of maturity to justify public disclosure as announced projects. And really with no remaining material conditions from a commercial perspective associated with them.

The second layer, the highly probable unsecured layer includes projects or programs, which do still have some outstanding commercial contingency associated with them, but which have progressed to the point that we are highly confident that they will be approved and they will proceed, but not yet to the point where we're in a position to announce specific details. And we have actually included these in our strategic plan on a 100% basis. So 100% of the required capital is provided for in our funding plan and 100% of the earnings is included in our earnings per share growth projections. So technically, there is at least some small probability that any one of these could get hung up. And probably the best example of a project, which would be in this category, is one that in a sense we have announced and that we've announced regulatory approval of it, and that's the Woodland extension pipeline. But technically, the shippers could still decide not to proceed with that project. We think that's very unlikely. It's more a matter of when and not whether, but -- so that's something we would put in that highly probable, but yet still technically unsecured from a commercial perspective.

And last is the risked unsecured layer. This is in effect an allowance for all the other growth projects beyond those that we've classified as highly probable, which are on our drawing board. And we've applied a top-down risking of the amount of capital we believe we will need to accommodate success on a portion but not all of those opportunities. This risk capital of $5 billion is included in our 2012 to 2016 funding plan, so we've made provision to fund it all, but we've assumed that none of it is generating earnings or cash flow prior to the end of that 2016 horizon of our plan. So this is one of several of the significant factors that will contribute growth momentum to the post-2016 period. In other words, we have provided for the funding of it during the current plan period, but we won't see the benefit of it until afterwards in the next 5 years.

Another aspect of the plan that I'd like to expand on, and there were a few questions earlier in the morning, with respect to is our upward tilted return profile on about $8 billion of the capital, as Al referred to earlier. So historically, most of Enbridge's investments have been flat return profile projects with a cost of service-like toll agreement, either classic cost of service projects or projects with a toll agreement, which mimicked that type of arrangement which provides an approximately equal return on the capital investment in every year of the project.

And the first 3 projects that I've listed on this chart here fit that historical mode. Actually, none of them is a classical cost of service arrangement but they all follow the same pattern. They have differing expected full life returns from low-double digits to mid-teens. But in all 3 cases, they achieve that level of profitability immediately upon going into service.

With our near-term growth already well looked after, we have had the luxury with some of our more recent and larger projects of being able to accept contractual toll structures, which provide attractive full life returns but require several years to climb to the full life return level. And, of course, if they require several years to climb to that level, it means they have to climb past that level beyond that point in order to deliver that on a full life basis. So that tilt is due either to an escalating toll arrangement or an escalating volume commitment or possibly both. So this capital makes a contribution -- makes a modest initial contribution to earnings per share growth as such a project comes into service. But then that accelerates over the remainder of the contract life of the project. So this is another of the significant factors in our growth momentum, as we pass beyond the 2016 horizon year of our detailed strategic plan. Most of this capital is just starting to kick in, in the last year or 2 of the plan and develops momentum thereafter.

With respect to financial risk management, we continue to follow a very conservative strategy in the face of global financial market uncertainty and potential volatility. To predict the stability and reliability of our earnings and cash flow, we're prepared to forgo potentially more favorable future exchange rates and interest rates, and we're prepared to do that, forgo those, for the sake of eliminating potential downside volatility.

On our U.S. dollar exposure, we have 90% locked in for 2012 and 2013 and then 80% all the way out, not only to 2016, but at this point, through 2017. That's the year beyond the end of our strategic plan horizon.

On floating interest rate exposure, again, we're similarly highly hedged, though a little less so for 2016 and 2017. And we've also locked the rates on 70% of our forward-term debt issuance plans. We're also pretty conservative in the amount of liquidity that we carry with $9.5 billion currently in hand after adding $3 billion of new committed facilities this year. And further liquidity building actions are currently in process. This means we do carry a bit of standby fee expense, but we like to know that we've got the cash if capital markets falter and so we feel that standby fee expense is well worth the insurance it provides.

For the time being, however, capital markets remain robust, and we've been taking full advantage of that to get a good start on our 5-year funding plan. We are the largest issuer of rate reset preferred shares with 2.3 billion issued this year and 3.3 billion in aggregate to date. And at a 4% yield and with the rating agencies providing a 50% equity credit for this security, this is a very low cost and flexible source of capital for us.

We've also significantly -- we have significantly topped up the common equity component of our capital structure, as we move into this high-intensity capital investment cycle, while on the debt side, it's been a more modest activity year and that's been intentional, the front-end more on the equity side and back-end more on the debt side. The debt issuances, by the way, include our $100 million century bond, a somewhat remarkable piece of paper that we issued this year.

I'm going to spend some time clarifying our sponsored vehicle strategy because it plays an important role in several ways within our strategy. It's a supplementary source of debt and equity funding. It's a key tool in reducing our cost of funding or enhancing project returns, depending on how you want to look at it, and it's a source of potential longer-term EPS growth. So our principal sponsored investments are Enbridge Income Fund and Enbridge Energy Partners. They have, in common with each other, a value proposition which involves a payout of nearly all of the cash flow that they generate as current distributions, with a correspondingly modest growth rate compared to Enbridge itself.

They also both have an incentive distribution feature. In the case of EEP, it's the traditional MLP-tiered incentive structure. But EEP's distributions have grown over the years to the point where the top 50% split applies to its distributions. This means that the 2% general partner interest splits incremental cash flow 50-50 with the 98% limited partner interest.

Enbridge Income Fund is just a flat 25% split of incremental cash flow to the manager. Now although not technically included as a sponsored vehicle, because it's actually managed by the case and not by Enbridge, Noverco has a similar potential to both EEP and the Enbridge Income Fund as a source of low-cost funding. This is because the return from the assets held within Noverco, our return, our share of that, is largely in the form of nontaxable dividends on high-rate preferred shares. So those are the 3 vehicles that we have in place to work with at the moment, at least.

And this next chart is one that I've used before to illustrate the return uplift to Enbridge from projects which are funded within the sponsored vehicles. This isn't an option for every asset because the financial structure of these vehicles only fits well with a mature, stable, high cash flow asset with little further growth potential. However, it's a very powerful tool for assets which fit this description.

For example, as indicated on the chart, if we take a typical Enbridge infrastructure investment that generates a 12% after-tax return at the project level, we get 3 quite different results depending on where in the consolidated group that project is situated. If it's funded on our corporate balance sheet, it would translate into about a 14% return at the corporate level. And that's because we typically carry a small layer of incremental corporate level leverage across the whole portfolio of investments that Enbridge has. And that's leverage beyond the project level debt that would be allocated to each individual project. So that's generally worth about 200 -- about a 200-basis point uplift to the project level return.

However, if we took exactly the same project and put it into the income fund and funded 75% of it from public investors in the fund and the remaining 25% from equity that Enbridge put in, the same project would provide a 20% return on Enbridge's portion of the funding. So we'd fund a smaller part of it, but we'd have a significantly higher return. And within EEP, the same approach would provide a 24% return. So we understand that these sponsored vehicles do create a degree of complexity in our structure, but we think the benefits to Enbridge investors is worth it. And investors in these vehicles also get what they value, and that's a high cash payout.

The financial benefit to Enbridge investors from funding suitable assets through the sponsored vehicles works equally well, whether it's a matter of organic growth of asset platforms already situated within the vehicle or a drop-down of an Enbridge asset to one of the vehicles. And I mentioned before that only certain types of assets are suitable, but we have a lot of those suitable assets in our portfolio as listed on this chart. Nearly $8 billion in hand or near to hand. These are available to supplement the organic growth of the vehicles and to accelerate Enbridge's growth, correspondingly.

In the near term, EEP doesn't have a need for drop downs, or in fact, it doesn't have an ability to fund them due to its fulsome roster of organic opportunities. On the other hand, the income fund has fewer organic opportunities immediately in front of it, though it's currently engaged in the Bakken expansion project. So the income fund does have, even in the near term, capacity for additional drop downs beyond the $1.2 billion renewable asset drop down that we executed last year. So the drop-down strategy is yet another one of those things that we have which provide significant potential as another accelerator of our post-2016 growth, when not only the income fund but also EEP would be in a position to have additional funding capacity.

And my last perspective on this subject is just to show in our current 5-year plan the contribution which the Income Fund and EEP make to Enbridge's earnings growth with the former's contribution growing at 8% and the latter at 13%. And these rates may not seem spectacular by themselves, but bear in mind that they both come with very minimal investment by Enbridge. So the incremental return in effect from the small investment that Enbridge is making is very substantial for that growth in earnings. And also, to be -- just to clarify, neither of these reflects any further drop downs. In EEP's case, it's because it doesn't really have the capacity. In the Fund's case, it's just because the way we prepared the numbers is -- at the Fund levels is without including drop downs, though the Fund certainly has the capacity and it's capacity that Enbridge will want to take advantage of for the benefit of both Fund investors and ourselves.

This chart format is probably pretty familiar. We've used it consistently in the past to describe our funding plan. And so it's updated to our current 2012 strategic plan capital requirements. Capital invested to be funded totals $32 million and that's excluding that to be funded by the sponsored vehicle, so this is an Enbridge perspective not an enterprise-wide perspective. 1/3 of that is covered by our expanding internally generated cash flow, with the remaining net funding requirement of $21 billion split between debt and equity in proportions, which preserve our credit metrics at appropriate levels. We will need to supplement the equity component of our balance sheet with a further $1.9 billion over the remaining 4 years of the plan or 4 years and a bit, having bolstered it by that same amount in the first 9 months of this year.

This residual requirement is well within the amount that we can source from additional pref issuance and drop downs to Enbridge Income Fund. Likewise, the residual debt requirement of $17 billion is manageable for our 3 issuers over the remaining 4 years, bearing in mind the bank facilities we have available as a cushion.

Our asset mix for the next 5 years, as you would expect from what you've heard, will be even more weighted to Liquids Pipelines, as Al mentioned to begin with. That's something that we're quite comfortable with in the medium term, but something that we would like to see move back to a greater balance as we move beyond that horizon into the period thereafter. And all of this attractive investment funded with low-cost capital gets you a pretty spectacular earnings per share growth rate through 2016 and with great momentum established for the years to follow, as Al indicated to you during his highlights.

So the story on the stock boils down to just a few key takeaways. Enbridge is blessed with an exceptional array of attractive return investment opportunities. The financial risk exposures that could take some wind out of our sails have been pretty well taken out of play. We have ample access to low-cost conventional funding sources, really the lowest in our history. And our sponsored vehicles further bolster our cost of capital advantage and growth rate. When you put together a record slate of attractive investments along with a record low cost of capital, you get an industry-leading earnings per share growth rate and substantial valuation upside.

And now I'll take your questions before turning it back to Al to wrap it up.

J. Richard Bird

Matthew.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Matthew Akman, Scotiabank. Why don't you talk about Enbridge Energy Partners and that opportunity? And it looks like it's a really big opportunity. You characterized it as a double, actually, on potential returns on Enbridge investing through EEP versus directly. But yet you said that EEP has kind of a full slate right now, which is too bad because Enbridge's growth could even get bigger and you haven't even talked about acquisitions yet in the envelope. So is there any way you can kind of unlock EEP? What kind of things are you contemplating? Or is there anything you could see on the sort of 3-year horizon for creating different funding vehicles or more access to equity capital, basically, for that vehicle?

J. Richard Bird

Yes. Well, you said it's too bad. In a way, it's too good, not too bad. Our cup runneth over with opportunities. So yes, I mean, theoretically, with all the capital in the U.S. that we have to deploy, if EEP could fund a bigger share of it, that would be even more of a good thing. It would be even better than good, so to speak. The reality is these sponsored vehicles are very powerful vehicles, that's the plus side. The other side of the coin is they are pretty specialized segments of the capital markets. And they don't have the same degree of access to equity capital as, say, a conventional corporation. So in answer to your question, anything and everything that we can do to enhance EEP's funding ability, we will. And that's because, as you've obviously noted, that is in Enbridge's interest to shift as much capital into that supercharger, as I sometimes refer to it, return mode. There are a few things that we're looking at. Not sure whether they're going to be effective or not. So our base plan assumes EEP funding sort of at the maximum of what we would consider to be its conventional, historical ability to access U.S. equity -- U.S. MLP equity markets.

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

Carl Kirst from BMO. Actually, maybe your first question just came off of Matthew's. We tend to think of the MLP market being somewhat limited between mostly retail, right, but you guys with EEQ have a vehicle out there that could potentially be used to more access the institutional market. Is that something that within your plans, you think right now would continue to be sort of the retail EEP dominated? Or is there a place perhaps for more EEQ kind of equity?

J. Richard Bird

I would like to say both. I think we'll continue, we've got both of those arrows in our quiver. Having put that structure in place, we would like to take further advantage of it. And our plan effectively assumes that we do make use of both. If possible, we'll make even more use of the institutional -- access to the institutional market through the EEQ vehicle. But again, the plan is conservative in what it assumes we accomplish in that regard.

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

Great. Next question if I could. Just on the $5 billion of risk-adjusted projects, can you tell us what that number is on an unrisked basis?

J. Richard Bird

I can't really off the top of my head. I could give you a generic idea. Typically, probably the average risking is about a 30% factor, 33% factor. It kind of ranges from 25, 50, 75. So that would probably grow up to somewhere between $15 billion and $20 billion.

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

Okay, great. And then last question if I could. And this really speaks to the dividend, as we enter this period of now, equity requirements. And I guess, one of the questions prior was is it possible that we could see the dividend grow stronger than earnings as cash flow growth outpaces the dividends, as we enter into a more capital-intensive period perhaps. How should we be balancing expectations on that?

J. Richard Bird

I think the way you should look at that is with our expectation of 12%-plus growth in earnings per share because we're pretty confident that we are going to see that highly probable wedge come to fruition. And with some potential, although we haven't built it into the plan, to see some portion of that $5 billion contributing to earnings during the period, you're going to see pretty healthy dividend growth even if dividend growth just parallels earnings growth. You're going to see somewhere between 11% and 15% dividend growth without needing to move our payout ratio past the 70% payout of earnings. So at the moment, that's the way that we're looking at that. Linda?

Linda Ezergailis - TD Securities Equity Research

Quick question on your Slide 11 and looking at your funding requirement. Historically, my perception is Enbridge has taken a very conservative approach and prefunded or funded as you went along on some of these projects. But I think some of your execution in the capital markets over the past 5 years has demonstrated that your access to the capital markets should continue to be strong in any environment. So how might we think of Enbridge opportunistically accessing the capital markets, especially in this low interest rate environment versus maybe waiting until these projects are actually contributing to earnings and cash flow?

J. Richard Bird

Sure. Well, that's a multidimensional question. I think, generally, we're going to fund as we go as opposed to prefunding and building up a significant cash balance, if you like, by raising long-term capital before it's actually deployed. But I'll add a couple of nuances to that. First of all, in a way, we have explicitly chosen in the last 12 months to prebuild the equity side of the balance sheet. That's where you've seen the very substantial pressure issuance activity. That's where you saw us being quite pleased to get $300 million of equity from Noverco as they undertook their secondary of a portion of Noverco's position and actually go to equity markets ourselves for $400 million of equity capital. So we haven't prefunded investment in aggregate, but we've prefunded the equity side of that, and that's really just to build up our strength, the strength of our balance sheet as we roll into this massive investment program. And the debt side of the equation has lagged accordingly to avoid building up the big cash balance. So as we move into the future, we'll still fund pretty much as we require the money, but you're going to see a shift towards less equity funding and more debt funding. That may be good news for some of you out there, some of you bankers out there who focus on that side of the market. In terms of prefunding to take advantage of low interest rates, which is the other dimension of your question, the way that we've done that is rather than by prefunding, it's by locking those forward issuances, so we have locked about 70% of our anticipated -- locked the underlying, either Government of Canada or U.S. Treasury bond on about 70% of our forward financing calendar. So in effect, except for the fact that we're paying up on the curve obviously to do that, we have taken advantage of the current interest rate environment for a very large portion of this capital program.

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

Pat Kenny, National Bank. The 5-year maintenance capital guidance continues to rise, obviously reflecting the accelerated integrity program. But can you just remind us how much of that incremental spend is being recovered through higher tolls down the road or some other cost-sharing mechanism with the shippers?

J. Richard Bird

Sure. So at one level, my answer would be all of that capital is being recovered through higher tolls and higher revenues, but that's a bit of a simplification, and I don't think it's really what you're getting at. So of that $5.6 billion of maintenance and integrity capital, a part of it is really simple. About $1.7 billion of that is being spent in EGD and, of course, EGD is cost of service or variation on cost of service. And so for that capital, it's very easy. You see a very direct causal connection between spending the capital and the recovery of that capital return on and return of. The balance of it is not within the EGD, it's within our pipeline businesses. And in some cases, those have a cost-of-service structure associated with them as well. The Norman Wells pipeline is a cost-of-service pipeline. The Woodland pipeline in the Athabasca is a pure cost-of-service pipeline. But for the pipelines, that's probably the exception where there's a pure cost-of-service recovery regime. The most significant amount of that capital would be on the mainline, and that's governed by the CTS arrangement. So the way that I think of that is you don't have that really simple causal relationship between spend $1 and get $1 back with its return. But what you have is, on the mainline system, a very favorable and attractive toll regime, which has a growing toll over time and a lot of volume generating revenue at that toll, so that's the prize that you get. And you spend that maintenance and integrity capital to make sure you get that prize. So you don't have that direct connection but nevertheless, you're going to get a good ultimate result from having spent that capital and protected that revenue stream. Who's got the mic? It looks like it's Andrew.

Andrew John Kerr - SADIF-Investment Analytics S.A.

Andrew Kerr from Crédit Suisse. Given the limitations in the MLP market and also with Enbridge income fund, would you have any appetite to really divest assets to pension funds in whole or in part as a source of capital?

J. Richard Bird

What we would have appetite to do is a type of transaction that we refer to as a monetization transaction. And let me back up a moment. We're always looking at the asset base as to whether there are assets that we don't think fit our longer-term strategy or are redundant in some fashion. And those would always be a candidate for outright sale and in most years, you'll see us trimming small assets here and there and that in that way. But generally, for our -- what we would think of as our core assets, we would look to a monetization approach as opposed to an outright sale approach. And what I mean by that is some type of funding arrangement where we continue to operate, we continue to manage, we continue to integrate as part of our overall operational and strategic base but potentially import participation of other lower-cost forms of capital into the funding of that asset. In a way, that's what the sponsored investment vehicles are set up to do. We have had and you could think of Noverco really as being a version of the same thing where pension fund, which is the case, is our partner. And we have looked at applying that structure to other possibilities as well.

Andrew M. Kuske - Crédit Suisse AG, Research Division

And then just as an extension of that first question, given a lot of pension funds are looking to increase their exposure to alternatives, and infrastructure happens to be a big area for alternative investment, do you have any appetite for effectively managing assets or pension funds in particular, that you might not want to actually own yourself?

J. Richard Bird

No, I don't think so. I don't think we're -- Al may have a comment on this, but I don't think we view ourselves as being just an operator of assets. Historically we've tended to look at operations as being a value that we bring to the ownership of an asset. Anything to add to that, Al?

Al Monaco

Yes, the short answer is no. However, if there was an opportunity to do something like that, which would lead to some kind of an investment or strategic positioning, I mean, that might be an angle but otherwise, that's not our first priority, no.

J. Richard Bird

Okay. Robert?

Robert Kwan - RBC Capital Markets, LLC, Research Division

Robert Kwan, RBC. Richard, just coming back to EEP, and they're certainly working through their funding plan right now but there is some uncertainty just with the capital build and what they went through around Alberta Clipper. Have you given some -- has any of that interplay changed as you think forward around the big value you see on drop downs but there very well may be more projects as you get out past these 2 years where you would assume more of the capital and then look at drop downs rather than EEP funding at some greenfield?

J. Richard Bird

So more of the Alberta Clipper type of arrangement, is that what you...

Robert Kwan - RBC Capital Markets, LLC, Research Division

Well, to some extent just trying to remove the overhang of some EEP stock right now by you assuming more of the construction and providing better timed drawdown.

J. Richard Bird

Yes. Well, for sure, and that is the structure of the Eastern Access joint funding arrangement, which we've also -- which we've entered into following the Alberta Clipper. So we want to find the balance between doing what Matthew was suggesting we do, which is pumping up EEP and having it raise as much equity capital as it can and funding the biggest piece of the capital that it can on the one hand, and on the other hand, overburdening it with too much and having that impact the price at which it can issue. So the way that the joint funding arrangement -- the Eastern Access joint funding arrangement has been structured is with flexibility to allow EEP to move up or move down in the total amount of its funding. And that band is basically a 15% band. So its target is to fund 40% of Eastern Access. It has the right to pare that back by 15% if it's starting to look like that's too much. It has the right to bump it up by 15% if it's starting to look like or successful in raising perhaps more than we would assume in a conservative case, in which case, it can bump that up to 40% to 55%.

Robert Kwan - RBC Capital Markets, LLC, Research Division

But you'd still see raw for material greenfield CapEx at EEP?

J. Richard Bird

Absolutely, yes, yes. And -- but carefully balancing its funding between what EEP can handle and what Enbridge will take on.

Unknown Attendee

Regarding Slide 9, the wind project. I have a 2- or 3-part question, and I'll ask each at a time.

J. Richard Bird

Good. Can I answer them each at a time then?

Unknown Attendee

Certainly. Are these 3 wind plans experiencing high rate of bird, although not Richard Bird, kill?

J. Richard Bird

In terms of the -- of all of our wind plants that are in operation, as far as I'm aware, they're not experiencing anything out of the ordinary in terms of bird kill. So it's not a subject which is high profile, so I would assume that we've got nothing out of the ordinary going on there. I'm assuming that there's some degree but not -- nothing remarkable.

Al Monaco

And let me maybe just give a supplement to that. We monitor that very closely on all of the wind farms and so far, we've noticed nothing out of the ordinary. In fact, I think the evidence is that you get more birds perishing, running into buildings than you do into wind turbine blades, so nothing on that front as far as we're aware of.

Unknown Attendee

The second and last question is what are the expected rates of return on common equity for your wind plants in 2012?

J. Richard Bird

Generally, the rates of return on equity on all of our wind projects are pretty much consistent with our normal corporate standards. Generally, those -- all of our renewables, whether wind or solar, are kind of in what we would characterize as low-double digits to low teens levels of return. And over here.

Stephen Dafoe

Richard, Stephen Dafoe, Scotia Capital. You've noted the equity prefunding, which the debt market and rating agencies just love to see. On the other hand, the next -- the rest of the 5-year funding plan debt requirement is close to 10x the equity requirements. Are your credit metrics peaking now? And if so, how much would they deteriorate as you execute on the debt, and are the rating agencies okay with that? Or is incremental earnings and cash flow and retained earnings going to keep your credit metrics flat to where they are now?

J. Richard Bird

Yes. So that is a key focus of our discussions with rating agencies, and it is, in fact, one of the biggest reasons why we've focused more on equity in the near term. And we do have additional equity bolstering to do, but we've knocked off about half of it. And the remainder is well within what we see we can achieve through pressure issuance and income fund drop downs. So in fact, our credit metrics will peak this year as we move into this heavy spending and will dip, but it will be a rather modest dip and a very short dip, so they'll recover quite quickly. A number of these projects are coming on in 2014, so 2013 is really the dip in 2014. The metrics are back up again to roughly current levels and approximately what we target on a long-term basis, so it's a pretty modest dip down. And that's -- it's a function of 2 things really. One is the huge cash flow base that we've now built up underneath us, which tends to cushion to some degree as you add incremental capital. It's not yet generating cash flow, but the second is that overweighting on the equity side of the funding that we've done. So as to how the credit ratings, we'll look at that. We're just in the process of going through our annual reviews. And I don't really want to speak for them, but I -- we've tried to manage those ratios to levels that we believe will be appropriate and acceptable to them.

Maria Berlettano - J. Zechner Associates Inc.

Maria Berlettano, J. Zechner Associates. An extension to that question on leverage. In anticipation of a drop down, to what level would you flex the balance sheet? What is sort of your comfort level to get to or not breach by, say, a certain level? Is there a bright line within the organization and in the minds of the rating agencies?

J. Richard Bird

Right. Well, I'm sure there's a bright line in the minds of the rating agencies. And maybe the best way I can answer that is it's a fairly modest dip. And our objective is to stay well clear of any bright line that the agencies might have that would trigger some kind of negative reaction on that part. And we'll have to wait and get the feedback from them, but that's how we've designed the funding program. So the flex in the balance sheet is really a pretty modest flex, really.

Maria Berlettano - J. Zechner Associates Inc.

Okay. And what is the company's base case scenario with respect to the capacity utilization of Alliance post-2015 and the type of variability you're expecting around that utilization? And in the context of the income fund, is there -- and drop down plans, does the company have a notion with respect to what type of blend of revenues they'd like to see within the income fund between contracted and non-contracted? Is there -- are there plans to potentially replace or, let's say, broaden the ownership of portfolio assets within the income fund to achieve a certain blend that supports a certain risk profile for that fund?

J. Richard Bird

Okay. Well, I think I got 2 questions out of that. In terms of the income fund, I think it makes sense for the income fund like Enbridge to be diversified across a broad range of assets. And in fact, if you look at its current asset mix, that's pretty much what's gone on in the last little while, but I would see further diversification in the future. In terms of Alliance, our base case on Alliance is that there's upside on Alliance. The current contractual structure doesn't enable us to fully capture the upside that we see in the future. But as that contractual structure unwinds, we expect Alliance will be the preferred path to market. By far, the preferred path, if you consider the NGL content of the gas and the value of that NGL content as it reaches Chicago compared to the value of the NGLs here in Alberta, but even on a dry gas basis, our analysis of the fundamentals would suggest that, in effect, the Chicago market is going to become the preferred market for dry gas as opposed to moving it all the way to Ontario, and Alliance will be advantageously positioned to capture that as well. I've got one more back there. Al, have we got another minute or 2? Am I chewing in to your time? Sorry, boss.

Theodore Durbin - Goldman Sachs Group Inc., Research Division

It's Ted Durbin with Goldman Sachs. You talked a little about your appetite for joint ventures. You've obviously take enterprise on with Seaway and [indiscernible] Spectra with the NEXUS pipeline. Should we see that as a sign that you don't want to take on too much capital yourself, or is this just more opportunistic around the asset base itself?

J. Richard Bird

That actually feels to me like an Al question. So Al, why don't you come up here and...

Al Monaco

Okay. I'll just -- I would say it's more opportunistic. I think from a funding perspective, we don't see an issue with being able to handle the size of projects like that. In the case of the enterprise partnership, which was mentioned earlier, very strong relationship there. It really had to do with meshing up 2 competitive advantages. They had a good familiarity with the Seaway system and they brought some commitments to that project. We brought some very strong attributes upstream of that with our relationship with Western Canadian producers and, of course, the volumes that will flow down on a committed basis on the Flanagan system. So that really was the driver there. And I would say it's exactly the same on the Spectra NEXUS transaction or potential projects that we're talking about. So nothing really to do with capacity, more to do with strategic opportunities when they present themselves.

So we are going to close off now. I just want to add one quick point on the discussions around EEP. There seem to be a lot of different ways to ask the same question. And maybe the only comment I'll make is that we are focused on this. My office isn't that far away from Richard's. And we do talk about opportunities to see what we can do to address the big picture situation there simply because there is a lot of opportunity. And I think that's been alluded to several times here, so we do have our thinking caps on it for sure. We happen to be in a good position in that there's no immediate panic in that we do have pretty substantial growth throughout even without that.

I'd like to say thanks to our team here. There was 3 individuals that didn't speak today, Janet Holder for Gateway; Karen Radford on the Human Resources side and Public Affairs; and then David Robottom on the Legal and IT side. They are just as critical to the equation that you see up here. But obviously, we wanted to try and focus a little bit more today on the conversation. But please take an opportunity to chat with them later on over lunch.

So I just had jotted down a few key takeaways here from the discussions today, and I won't be long. But number one, we are not changing the business model. Our value proposition is going to stay intact. We are focused on 3 things, to boil it down. One on operations, which include safety and the reliability of our systems; number two, executing the plan, and that is critical because if we execute well, we will generate the earnings per share and dividend growth. Thirdly, extending the growth beyond 2016. We have a lot of levers to do that. You heard of quite a few today, so we're very -- we're in a very good position from that perspective.

To reiterate, we've locked down $18 billion in secured projects, which itself is going to generate 10% EPS growth through the next 5 years. And that's virtually locked in and highly transparent. The big news today was in the $12 billion of highly probable projects in the capital category. Those projects are going to accelerate that growth rate to 12% plus. And there was -- during the break, I noted a couple of questions around, okay, well what exactly is in there? And I think to just give you a couple of projects that fill out the $12 billion, the light oil expansion initiative for $5.5 billion that Steve referred to, that is in there. We've got the Woodland extension at $600 million. We've got the Edmonton to Hardisty mainline expansion at $2.5 billion, and we have mainline expansions at around $1.5 billion. We've got projects within EGD. This is normal customer annual growth of about $800 million, and then we have some green initiatives or new platform initiatives in the $500 million range. So that's a good chunk of what's in that $12 billion highly probable category. Art and Byron were here today because of the importance of executing the plan and to give you further comfort in transparency and us being able to achieve the growth rates that we're talking about. And the growth rates, by the way, exclude any contribution from that additional $5 billion-plus that we've been referring to. Importantly, the funding plan is well in hand and takes into account all of the secured, highly probable and as well the additional $5 billion in risk. So we're in good shape that way.

Another comment I'd like to make is it's not all about Liquids Pipelines, as Steve thinks, but we do have other opportunities. And I think there was a good discussion today about the gas side of the business and the electric international and other sides of what we can do.

The dividend growth rate should be very strong. It should follow earnings per share growth, and we're very confident in our ability to replicate what we've been doing in the past. On acquisitions, that came up a couple of times, and just to reiterate, we will pursue those acquisition opportunities, where it can round out our strategies and accelerate those strategies. Obviously, if we do one of those, you can feel comfortable that we've really bedded down the fundamentals, and it is strategically important to us.

We have a -- we like to think, and we hope we've demonstrated today, a very strong management team with lots of depth. And part of my job is to make sure we're continuing to harness that and develop that going forward.

I guess the bottom line to this discussion today is things are going in the right direction on a number of fronts. Number one, we've got excellent supply fundamentals, particularly on the crude oil side. And part of that, and this came up a couple of times around how we look at risk, the supply fundamentals are very strong today as are demand but, as was pointed out, we can't get too euphoric about that. We're always focused on making sure we have good contractual underpinning as well, as part of the equation.

Our assets, I think, have demonstrated, from what you've seen over the last few years, to be extremely well positioned. We've got good access into the core areas, but our ability and scale that comes with the size of our system to extend into new markets is pretty crucial and is leading to more and more opportunity.

I guess, followed by execution of the capital plan, we're very comfortable that we can handle the magnitude of this. It came up in a couple questions at the break as well. On the $12 billion of highly probable capital, we're not concerned that we won't be able to execute that just as well as the first $18 billion.

And finally, and this came up very well in Richard's slide, which is actually still up. The fact that funding costs are low today and we're taking advantage of that really helps to generate more growth and, ultimately, share price upside.

So we'd like to thank you very much for your attention today. It was a good discussion. Please feel free to follow up with us. There is lunch across the room, I believe. So please join us there, and then we can have more conversation. Thank you very much.

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Source: Enbridge Inc. - Analyst/Investor Day
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