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Enbridge, Inc. (NYSE:ENB)

October 04, 2011 8:00 am ET

Executives

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

Patrick Donald Daniel - Chief Executive Officer, President, Director, Director of Enbridge Gas Distribution, Director of Enbridge Pipelines and Director of Enbridge Energy Company

Al Monaco - President of Gas Pipelines, Green Energy & International

Stephen John Wuori - President of Liquids Pipelines

D. Guy Jarvis - President, Enbridge Gas Distribution

J. Richard Bird - EVP of Liquids Pipelines

Analysts

Carl L. Kirst - BMO Capital Markets Canada

Matthew Akman - Scotia Capital Inc., Research Division

Stephen Dafoe

Chad Friess - UBS Investment Bank, Research Division

Juan Plessis - Canaccord Genuity, Research Division

Andrew M. Kuske - Crédit Suisse AG, Research Division

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

Winfried Fruehauf - Fruehauf consulting

Maria Berlettano

Robert Kwan - RBC Capital Markets, LLC, Research Division

Linda Ezergailis - TD Newcrest Capital Inc., Research Division

Unknown Analyst -

J. L. Balko

All right. Good morning, everyone. My name is Jody Balko, and I'm Vice President of Investor Relations at Enbridge. Welcome to the 13th Annual Enbridge Day, our Investment Community Conference.

So in the spirit of safety, I would just want to give you a quick safety message. And for those of who are at the dinner last night, this will sound a little familiar but we're in a different venue tonight, or today. So in case of a fire alarm, there are exits at the back and at both sites. And please exit through those doors, go down the stairs and there you will be met by the conference people here and they will direct you over to The Sheraton, which is the meeting point. And hopefully that doesn't happen.

So one quick reminder for everyone, this session is being webcast. So if you have a question, please wait for the microphone. And then please say your name, identify yourself, which institution you're from so that people listening to the webcast can follow along.

And with those quick opening remarks, I will introduce Pat Daniel, President and CEO of Enbridge. Thank you.

Patrick Donald Daniel

Thank you, Jody, and good morning, everyone. Welcome, as Jody said, to our 13th Annual and the 2011 Enbridge Day Investment Conference. We appreciate a great turnout. And as you know, we go from here to New York tonight and do a repeat in New York tomorrow. Once again, I expect very good turnout in New York. So this event has grown dramatically over the years, over the 13 years that we've held it.

As usual, the prime objective today is to allow us to go into a lot more detail than we normally are able to in a one-hour one-on-one with you with regard to our operations and the opportunities in front of you. And at the same time, it gives our full senior management team an opportunity to interact with you to understand your questions and issues, and it gives you an opportunity to meet them and find out the depth of the management team. And that's particularly important to me, quite often as Richard and I only out on the road and that this gives you an opportunity to see the full senior executive team in the company.

I hope you have a chance to catch up with Jody at some point during the day today and having taken on the responsibility for HR, Jody has been with the company, I think, 14 years. Jody, most recently, is Vice President of Human Resources in Calgary, prior to that, as Controller of Enbridge Energy Partners in Houston. Before that, I think, it was Superior, Wisconsin and before that, I think Edmonton. So Jody has moved around a fair bit with the organization. She, of course, has taken over from Guy Jarvis who you would have known in the IR role before. Guy is here today, right in the front row. If you've got a problem with your gas bill, you can now talk to Guy because he's running the Gas Distribution utility here. And of course, to complete that circle of moves, Janet Holder, who ran the Gas Distribution business here, has relocated to Prince George, British Colombia as Executive VP of Western Access with prime responsibility for the Gateway project.

And that goes to tell you how persuasive I can be. When is the last time you heard of a CEO talking an Executive VP from Toronto into moving to Prince George, British Colombia? I think that's quite an achievement. Now she is a native of Prince George though, so that made it a little bit easier. And by the way, you're going to meet the full senior executive team through the morning, so I'm not going to go through and introduce all of them.

It's been a very busy and successful year for us since we last met with you. I think you would agree with that. But most importantly from my point of view is that the future looks particularly bright, even relative to the tremendous plans we put in front of you in the future. You may have heard me on the Q2 earnings call and we're very excited by the way in which the year is going to date and have guided towards the upper end of the range on our 2011 guidance range.

I think you'll find as we go through each of the presentations this story of growth and the sustainability of the growth is going to be the key theme. And to that end, you would have noticed over the last few days a series of press releases with regard to new opportunities. And they're quite diversed over many parts of the organization, and we've got a lot more in the bag that we're working on now. So there will be a lot of new announcements from this company over the next while.

I'm going to skip through the legal caveats. You all know them much better than I, but as you know, we're required to put those in front of you.

What I'd like to do is just spend a little -- a few minutes talking about organization. This is the newly restructured executive leadership team of the company. And in addition to the changes that I referred to earlier, of course, many will be presenting today and you have an opportunity to chat with them at the break or at lunch for those that are able to stay at lunch. I mentioned that Janet has moved out to Prince George and is responsible for Western Access. And of course, that Guy has taken over at EGD.

I would also like to welcome Karen Radford to the executive team of Enbridge. Karen has come in to the role of Executive VP People and Partners, which is a bit of a new name. We wanted to bring some new thinking to the executive team and she brought the new thinking in the form of the title itself in People and Partners. Karen, many of you will know, was most recently with TELUS where she held the role of Executive VP and President of Business Solutions. And she brings a very strong and proven leadership capabilities to our executive team. And that obviously is something we're really looking for and a very strong commitment to community. And in this role, with the responsibility for People and Partners, that commitment is critically important to us. And we also look forward to her fresh perspectives. And that, as much as anything, I think it's important to continue to renew an executive team along the way and bring someone from outside is very important to maintaining that.

I've often said to our Board of Directors that I think we have, by far, the deepest management team in the business. And we've been very proactive, as you know, in rotating people from one role to another to broaden out the backgrounds and provide a very in-depth view on the entire company. And that's worked very well for us. Almost everyone on this executive team has been through multiple positions in the organization.

As a matter of fact, going beyond that in the organization, we're also extremely deep in terms of management. And I made the comment to the board back, I think, it was about 6 months ago, that they could lose the entire executive team of this company and things would continue on without a beat because of the depth of the organization. And it wasn't an invitation to them to get rid of us all, but it was an indication of the depth and the confidence that I've got in the younger generation at Enbridge.

Let me move on and talk about a slide that you've seen many times in the past, and this is a very simplistic indication of the investment proposition at Enbridge. I'm not going to belabor it today, but it is critically important that I put this up again because it really has been the formula of success for Enbridge in providing what we refer to as the triangle of the investment proposition triangle, a very strong and visible growth, a very reliable business model and a growing income stream.

We think that we deliver a very unique combination of those 3 attributes to shareholders. It's very unusual to find the very reliable business model combined with 10% growth, and on top of that, very strong yield. So as a result, we tend to do well in most periods of time, whether they're periods of growth, our 10% growth story is almost as good as anybody's growth story. During a period of time of those investors seeking security or a safe haven, we tend to be that because of the yield and the reliability of the earnings stream of the company. So it's a very important triangle.

And as we go through the discussions today, you can hear a lot about new opportunities. And the key thing to remember is that when we evaluate new opportunities at Enbridge, we don't think how we can adjust that triangle to accommodate the new opportunity, we think more in terms of does it fit within the triangle. And if it doesn't, then we're not likely to pursue it. So it's not that we're trying to adjust that to try to take on a high degree of risk or something that doesn't provide the yield or the safety of investment, we try to work within that triangle only. And we've had such a tremendous suite of opportunities, we've been able to do that and provide significant growth to you, the investor.

Another slide that you are undoubtedly very familiar with is a quick run through the existing asset base of the company. And I won't spend an awful lot of time on this. But to tell you the truth, if there ever was one key to the success of Enbridge, it's really in the form of a map. If you're an asset manager, the map is critically important, and we've got very good strategic positioning in each of our key businesses.

The asset base itself is anchored by the world's longest, largest crude oil pipeline system. And of course, Steve Wuori is going to talk in some detail about the existing operations within Liquids Pipelines and then new opportunities going forward when we get into the presentation.

As you know, we are hard-wired into the second or third largest reserve of crude oil in the world in the oil sands. And we deliver into the best market for crude oil in the world and that's the landlocked U.S. Midwest. And those 2 anchors make this probably one of the strongest utility franchises in the world.

On the gas pipeline side site, once again, 3 distinct gas businesses. One is the long-haul pipeline system basically from Northeast B.C. through into the U.S. Midwest and on into Eastern Ontario -- or in Western Ontario. Again, the proximity of these assets to the liquids-rich gas plays right now makes the strategic positioning of our long-haul gas pipeline system outstanding.

The second part of the gas pipe business is the gathering and processing business, primarily in Texas. Once again, Anadarko, Barnett, Bossier, Haynesville, we couldn't be better positioned in terms of the location of our gathering and the processing assets.

And of course, offshore and we will talk more about that later on, very good new projects under way offshore in servicing, Chevron in particular.

I think it's fair to say that natural gas fundamentally is a commodity that should have a very bright future. And I realize that right now, it's been primarily liquids-rich natural gas that everyone is looking for. But going forward, the fundamentals are very favorable for natural gas.

And the third key part of the business, and by the way, I will get to the renewables and power part of it later on, not on this map but in a few minutes. But the third key part of business is the gas distribution business. And as you know, we operate the largest gas distribution franchise in Canada. And we're better to operate it in a rapidly growing metropolitan area in Toronto, and basically a cold weather climate. So it makes it one of the best gas distribution utilities in North America, if not the best.

So that asset base is critically important, and I spent a lot of time on that slide and I know that you know everything on the slide. But that positioning is what results in this 10-plus percent growth rate that we are able to put in front of you every year.

We're going to talk a lot today about new projects, but the success of the company really lies with the operating success and the ability to provide safe, reliable and predictable operations and service through our customers. You remember that about a year ago, when I was up in front of you, we were announcing organizational changes to support a renewed focus on operational liability within Enbridge. And we're even more steadfast now than we were a year ago in our commitment to that operational reliability and realizing that that is job one at Enbridge.

What I'd like to do is just give you a quick overview of some of the broader initiatives that we've taken in the company to implement this refocus on operational reliability. The prime thing that I've done is that I've implemented an operations and integrity committee as the most senior committee among senior management. Rather than being business development-focused or acquisition-focused, this is an operations and integrity committee. It meets once a month for a full day, I chair the committee. It involves, in addition to the executive team, the heads of the business unit operations and the heads of the integrity units within the business units. We spend the entire day going through every operational incident that we have encountered along the way and making sure that that information is shared from business unit to business unit. We found it to be particularly helpful in doing that and to ensure that absolutely everyone on the executive team is fully engaged in the day-to-day operation of the organization.

In addition to that, we have implemented an operational risk management plan. And this is somewhat akin to our strategic long-range planning process at Enbridge where we've gone through a full and detailed review of the risks that we face in the organization, have put together a very focused risk mitigation plan around any operational issues and have made a commitment to our board that we will be top decile, if not number one in the industry in each aspect of that operational and integrity plan in the company. So we're not even satisfied with just being top quartile, we want to be the industry leader in terms of operation and safety. We've often viewed ourselves that way. This is a reinforcement of that and making sure that we leave no doubt in anyone's mind that we are best-in-class.

Moving on and talking about growth projects, I'm going to just give you a summary and you're going to be seeing a lot of details as we go through the morning. But to give you a year-over-year snapshot from this time last year, we've secured more than $4 billion in new projects, new growth projects in liquids, gas and electric power businesses over the past year. The scale of these projects has tended to be smaller in size individually than what we were putting in front of you in past years. Generally, most of these are no more than $1 billion a piece versus projects in the past like $3 billion Alberta Clipper or Southern Lights projects. However, the cumulative effect of these still provides us with 10% growth, and in a lot of ways is a little bit lower risk as we don't have quite so much writing on one individual project.

Interestingly enough, the longer list this past year has really been the gas business, more specifically on the gathering and processing side. I don't think that would be too surprising though when you realize that most gas exploration in North America is looking for liquids-rich natural gas. So there is a liquids connection even to the gas business that we have today.

I think that $4 billion, obviously, is a pretty impressive number. But that really pales in comparison to the full suite of opportunities that we have in front of us over the next 10 to 15 years. And that suite right now looks like about a $48 billion suite and that's an enormous scope of opportunities and it's right across all of our businesses. Pretty close to a $50 billion number. And by the way, the $48 billion wasn't just a number pulled out of the air. These are individual projects that we have got under evaluation in one form or other in the organization. And you're going to be hearing about just about all of them, if not all of them, as we go through the morning.

We're not going to win all $48 billion of those projects by any means, but we think we will get more than our fair share. And of course, not all are going to fall within the 2011 to 2015 time frame of our next 5-year plan.

However, we already have $8 billion worth of opportunities secured. And they're in a -- they're commercially secured to backlog, and another $11 billion plus between now and 2015 on a risk basis that we would expect to gain access to. So this is much bigger and more broadly based than the opportunity suite that the company has ever had before.

The opportunities extend beyond the 3 platforms that I was referring to, liquids pipelines, gas pipelines and gas distribution. It also now involves a platform that we're referring to as electric power. This isn't, of course, entirely new to us. You know that we've been very involved in the renewable power generation for many years and now have 7 operating wind farms, 3 solar facilities and a geothermal facility.

As a matter of fact, in 2010, the largest portion of our capital program was spent on renewable projects, believe it or not, considering the huge opportunities and construction we've had underway in liquids pipelines and the tremendous gas opportunities that I was referring to. Last year, renewables was the biggest consumer of capital.

Last year at Enbridge Day, we talked about taking that renewable platform and extending it and developing a little bit beyond that into complementary businesses of power transmission because we've identified some areas where there was a need for additional power transmission capacity and then also into gas-fired power generation at some point. As you know, we've been successful in entering the power transmission business with the Montana-Alberta tie-lane project, Richard is going to speak more of that acquisition later on. But we're very pleased with that relatively small entry. We think it will lead to more very good opportunities in power transmission.

We haven't yet secured a gas-fired power generation project, but we've looked at a number. We still find the fundamentals to be very attractive. And based on the price of natural gas going forward and the need for power in a growing economy, we expect that will ultimately be a very strong business as well.

And what I would like to point out, by the way, with regard to all of these opportunities to take you back to the investment triangle that I put forward, all of these opportunities fit within that triangle of good growth, good yield and relatively low risk. We have not had to modify the triangle to accommodate the renewables business, the power transmission business or gas-fired power generation.

Let me change gears and talk for a few minutes about a project that's been very much in the news this year and not always for the right reasons, by the way and I'm referring to the Gateway Pipeline project to the West Coast. And we chatted for those of you that were able to make it to dinner last night, we had a few insights from Bruce Anderson [ph] on public perception on the pipeline industry and some of the issues that we face in public discussion around major projects like this.

Before I get into the specifics on Gateway though, let me just start from a very broad and general sense in that Canada of course has huge abundance of natural resources, we all know that. And primary among those is crude oil. It's our single largest export in Canada, $50 billion a year of crude oil that we export every year.

That resource, the crude oil resource, is generally scarce around the world. And as a result, tremendous opportunities in developing regions to provide Canadian crude oil into those markets. In my mind, Canada should be poised and largely is to be the answer to that driving demand from around the world and the fact that we've got such a huge resource available here.

We think we've got a tremendous opportunity to contribute significantly to the national prosperity at the same time that we develop this project. Independent studies have suggested that it will add $2 to $3 per barrel to every barrel of crude oil produced in Canada as a result of having broader markets and not marketing to one single customer. But in order to do that, we need to gain access to tidewater in order to able to move that product to market.

We've mentioned before that Gateway is not about takeaway capacity from Alberta. We will have more than enough takeaway capacity with all of the pipeline projects being planned right now. However, remember they're all either to provide domestic supply in Canada or to reach the U.S. market, everything that's currently planned with the exception of Gateway. So it's not about capacity and takeaway, it's about market and broadening out the market. There is not another country that I have been able to find in the work that I've done in the world that markets its #1 export to one other country only. And I would challenge any of you if you can think of another country that does that, let me know.

Therefore, we think that this is strategically very important for the company, and a project that in a lot of ways is important to Canada as it is to Enbridge. The project though is important to us, as you know. We expect to be a 50% owner in the project. We're not the only project proponent, we are the major project proponent.

But it still only represents 5% of that $50 billion suite of opportunities I've put in front of you. So I don't want you to think that we're only Gateway, but Gateway is critically important and is critically important for the country.

We also think at Enbridge that we can bring this project to successful completion. And we've realized that it is complex, but we also know that 80% of the crude oil in the world moves by a tanker. So therefore, why can't Canadians move crude oil by a tanker? We know that there are pipeline challenges, but we have built pipelines through more complex terrain than what we will be building through to get to the West Coast.

And as I mentioned, we've now restructured our executive team in order to put an even greater focus on Gateway as we enter into the hearings in January, the public hearings and then into the NEB hearing room in June. So once again, we think this is a very important project and we know it's very controversial, but to this country, there probably have been very few energy projects as important as Gateway.

I'd like to just briefly circle back to something that I spent a lot of time on a year ago when I talk about our remediation efforts in Marshall, Michigan, one year after the leak that we had on our Line 6B in Marshall, as a matter of fact, it was a year and a couple of months ago.

We're very pleased, by the way, by the way, with the efforts and the resolve with which our employees have tackled the Marshall, Michigan incident and to restore that area as close as we possibly can to the state prior to the spill. This picture is taken at the confluence of Talmadge Creek in the Kalamazoo River, and it's just one example of many along the way of the kind of work that we've done. This is one of the access points that we used to get into the river to conduct the cleanup. This is the facility that we're building in response to a request from an individual who indicated there was not enough canoe and boat access to the river. We built a small little community picnic facility with a boat and canoe launch and the parking for vehicles for ongoing access to the Kalamazoo River. We expect that that river will be more heavily utilized for recreational purposes after Enbridge than it was before. And again, this is just one of the many examples of the work that's been done.

The cause of the line rupture and of the break, the pipe break, is still under investigation by the NTSB. And we now anticipate sometime in 2012 there'll be a final report out. As you know, the NTSB has been very focused on San Bruno and some other incidents and therefore, the final report on our incident is not out. So once again, we're not able to speak to the metallurgy and the issues around the reasons for the break.

In the meantime though, we have done significant amount of remediation work on our Line 6B. We've put forward a proposal to replace 75 miles of the existing line and we're very confident in the integrity of the pipeline today. So a dramatic work that's been done. And in the area of cleanup, we have spent a lot of time over the last year on remediation efforts on the Kalamazoo River. We still have some work to do as a result of submerged oil where we're very much near the end of that now and hope to be a complete and have the river open very soon. The submerged oil really came as a result of the fact that the river was in flood at the time of the spill. And with a very heavy oil, we've got a small amount of oil that has submerged into the silts and the river. We've been in the process of working with the EPA and other regulatory agencies to complete that cleanup.

To date, we have spent about $500 million on the cleanup. And we estimate that the total remediation effort could be in the range of $700 million. But we still have work to do in refining that. The creek and the river looked very good. I can attest to that from my last visit. There is no threat to public health, and the state of Michigan has declared that. So there are really no issues. They're basically cosmetic at this point with regard to reopening the river.

Moving on, as you're going to hear through the course of the morning, new projects continue to drive a very impressive growth story at Enbridge. And that growth has come, of course, in the form of earnings growth. But with volume growth now on our mainline system under CTS, we have an additional contributor to the growth story at Enbridge. For 2011, as I mentioned, we've already narrowed our guidance range to the upper-half of the guidance range of $1.375 to $1.475, that's what happens when you split the stock in the middle of the year. Basically, $1.38 to $1.48 and we expect to be in the upper end of that range. But for the longer term, I think what's critically important to you as investors is that we remain very confident that we can achieve a 10% EPS growth rate on average through 2015 and that's on a very conservative project securement forecast, and very conservative mainline volume assumptions, and we will go into that as best we can later on.

So let me just wrap up my introductory remarks by identifying some key points that I would like you to keep in mind as we go through the balance of the morning. First of all, we've got a record slate of liquids pipelines growth opportunities. And when you consider the record that we've had in the past, to be in front of you, saying that we've never had a better slate of opportunities, that's quite remarkable. Steve will go through those and sum them up for you.

A very buoyant gas pipelining and processing picture largely driven by the shale gas plays and the liquids-rich shale gas plays. And obviously, the frac spread, when you've got relatively high oil price, relatively low gas price, that makes that frac spread business very, very attractive. Excellent momentum building on our new electric platform.

I think I've described to you before the people involved in the renewables development within Enbridge are probably some of the most passionate about what they're doing in the entire organization. And our board jokes with us that if we don't have a new renewables project in front of them at every board meeting, they wonder where we've hidden that. So we're bringing forward something new on the renewables side almost every board meeting now.

And with the broader electric platform that includes transmission and potentially gas-fired power generation, we expect that truly to be a fourth leg on the stool of major assets going forward.

No matter what we say through the day today, we're here primarily to talk about growth. But remember, that operational reliability is focused number one for Enbridge. Our intent is to be the best in the business, at least top decile in everything that we do on operations and integrity.

We've got a very strong balance sheet, Richard is going to speak to that and some recent moves in order to further deepen the liquidity for the company in light of some of the challenges in worldwide markets. We probably have never been in a stronger financial position, and all of our ratios are significantly improving as a result of the investments that we made a number of years ago that are now taking out significant free cash flow.

And of course, continued strong EPS growth. We're very comfortable with our forecast of 10% growth through the middle of the decade. And that's based on a conservative estimate of our success rate on that huge $40-some billion slate of opportunities.

So that's a quick run through on the key messages going into the presentation. And maybe what I'll do is pause and take any questions now before I turn it over to Steve to start through the liquids pipeline portion of the presentation. Andrew?

Question-and-Answer Session

Andrew M. Kuske - Crédit Suisse AG, Research Division

Andrew Kuske from Credit Suisse. Pat, you've been CEO now for more than 10 years, and if you can just comment on the visibility of capital allocation 10 years ago to now and what you see in the future? And how you changed the management structure and really the business overall to deal with those changes?

Patrick Donald Daniel

Well, to tell you the truth, capital allocation closer to 11 years ago now, Andrew, was not the biggest challenge. It was lack of growth at that time. And therefore, basically, any opportunity that we had, we were taking. As you may recall, our growth rate at that time, we were hoping to be in that 8% to 10% range, about 5% to 6% of which was organic, and then we were layering on an expectation of 2% to 3% acquisition growth based on our prior track record and we were hitting in that 8% to 10% range. But basically it was at that point, any opportunities that we could find within our investment triangle, we were taking. Now we're in a situation where we are being very, very selective. And it's not that we were just shooting at anything 10 years ago. We've got such a huge slate of opportunities. We're being more selective in what we are able to take on. And we're not in a situation we're really allocating capital, but we're being very attentive to the point where that quick come along the way due to the huge slate of opportunities.

Andrew M. Kuske - Crédit Suisse AG, Research Division

And then just a follow-up, is the selectivity being driven by return in compression?

Patrick Donald Daniel

No, it isn't. Interestingly enough, and I know we've talked about this over the years, we have not seen return compression. As a matter of fact, I think it's largely because of some of the unique parts of our business that we have been able to maintain our returns or in fact, do even a little bit better than what we're able to do going back over that period of time. And I think it's the strategic positioning that's critically important to that. We're able to now to use one of the best examples on the liquids pipeline side, this corridor from Fort MacMurray down to Edmonton. Because of our very strong strategic positioning there, we know what others need to do to make a big entry into that business. So that's allowed us to basically maintain our returns. And of course, the CTS, we think, is going to produce better returns than any of our incentive tolling agreements in the past. I should also add, Matthew, while they're bringing the mic to you, I should also add that even the gas distribution business returns are significantly better than they were 11 years ago, largely because of this 250-basis point uplift that we've got through the incentive tolling deal.

Matthew Akman - Scotia Capital Inc., Research Division

Matthew Akman from Scotia Capital. My question is on your recent acquisition of Tonbridge and the move into electricity transmission by Enbridge, which is a new business for the company. Just wondering what opportunities do you see in that business over a multiyear period? What are the things that Enbridge can bring to that business? Because obviously, some of the core strengths of the business are going to be synergistic. And what are the things that the organization may still have to learn about that business and about electricity in order to really flourish in that?

Patrick Donald Daniel

Well, I think, first of all, on the opportunity side, we mentioned this a year ago, if not before, that the result of working in the renewables business we've noticed transmission system shortfalls in various locations in North America. As a matter of fact, one of the biggest considerations in doing a renewables project is whether you're going to be limited by the transmission system. It's one thing to be able to get a long-term PPA. But if you're limited by your inability to get the power to market, then you've got a significant constraint. So in doing our due diligence, we've noticed a number of areas where there were limits. And hence, we've seen the opportunity to get into the power transmission business. Because these involve long linear construction projects, it fits very well with the kind of thing that we're used to doing, going out and acquiring right away, working with landowners. And then just doing a construction project that is linear is very different from doing one in a confined space in a plant. So the skills that we bring are pretty obvious, and I think the Tonbridge acquisition is a perfect example of that. Excellent work done by the Tonbridge people in going out and securing that opportunity, but they don't have the depth of organization to execute and to manage the major project associated with that. As you know, we set up this major project management function in Enbridge years ago to do exactly that, to execute on major linear projects. So I think that that skill set, along with the landowner relationships, the regulatory relationships or skills that we would be able to bring to all of these. And there was a third part to your question.

Matthew Akman - Scotia Capital Inc., Research Division

Just wondering if there's any additional risk or twists to that business that may not apply to pipeline, for example, greater knowledge of electricity markets and how that might affect the cash flow on some of these or the contracting profile?

Patrick Donald Daniel

Well, undoubtedly, there are differences. But having been in the renewables business for a while now, we do understand the power business somewhat. We will get -- become a bigger and bigger part of the business going forward. But realize that we tend to eliminate that risk through the PPAs that we do. And maybe over time, we might be prepared to take a little more risk in the business. But right now, we're looking for long-term PPAs for those facilities. Maybe Linda, and then Robert?

Linda Ezergailis - TD Newcrest Capital Inc., Research Division

Linda Ezergailis, TD Securities. Pat, maybe you could give us an update on some further extensions of your energy infrastructure opportunity set. Specifically, would you see synergies in electric distribution as it relates to customer service overlap with your gas distribution business and lower voltage but complementary to your growing transmission business? And on the flip side, are there some businesses that are a little bit less core? And I realize you don't need proceeds at this point to sell any businesses, but would there be an opportunity to capitalize, for example, on favorable commodity pricing and maybe look at selling something like Aux Sable, which I know years ago, would have been a desired outcome for that asset?

Patrick Donald Daniel

So first part of your question with regard to synergies on electric distribution, as you know, in the past, it's one of the things that we've looked at, we've talked about. We've never found a deal that really works in that regard. And that's largely because both entities tend to be highly regulated, whether it's electric distribution or gas distribution. And if you go in and realize synergies often, the regulator expects you to return those synergies to the rate payer rather than to the shareholder. And hence, we have not been able to find any deals that really work well in putting together both the gas distribution and electric distribution. Doesn't mean to say there might not be going forward. We also, in indicating to you a year ago, that we're going to get into electric transmission. We thought there might be some distribution opportunities in some of those as well. To date, we haven't found anything that works, but that is a possibility going forward. The second part of the question, is there anything that's less core, very, very little. And as you know, we have, over the years, we've had very little asset that we wanted to spin-out or sell whenever we find ourselves in a situation where during the major construction on the liquids pipelines side, for example, that we needed capital, capital markets were poor. We sold a couple of assets that we love, one in Spain and one in Colombia, because we got premium valuations at that time and there was an opportunity to redeploy that capital. So we don't really have anything on the list that we're wanting to get out off. Specifically with regard to Aux Sable, first of all, it's a wonderful business today. But remember, the commercial deal that we put in place with BP provides us with a floor situation that is very attractive to us on Aux Sable. So we do have a fair bit of upside with it and very little downside, and we're quite comfortable with that. Operationally, it's a very important part of the operation of the alliance at gas pipeline, so it's very hard to separate the 2. But in the meantime, we've got the commercial protection and it's a low-risk venture for us.

Linda Ezergailis - TD Newcrest Capital Inc., Research Division

And just as a follow-up in terms of capital deployment decisions. How does the board and the executive management team think periodically about share buybacks? I mean, one of the challenges of having such a great quality mix of assets is finding new assets that are that good. So how has the board and the management team thought about share buybacks?

Patrick Donald Daniel

Well, we're asked that a lot, and generally speaking, we have not been big on the share buyback concept. And I start off with kind of a tongue and cheek response, I have a friend who said shares are meant to be issued, not purchased by companies. And I am somewhat of that theory. Generally speaking, the way in which Enbridge is tended to reward investors is through dividend growth. And we think that, that is more, I guess, you could say reliable, predictable, consistent way to provide return to shareholders rather than doing a share buyback. And particularly with the growth opportunities that we have in front of us, that would not be a wise way at this point to redeploy capital. We've got excellent growth opportunities. Robert, I think, was next. I'm sorry, I probably shouldn't get into the microphone management business. Juan, go ahead.

Juan Plessis - Canaccord Genuity, Research Division

It's Juan Plessis, Cannacord Genuity. One thing that was absent from your growth platform was a return or reentry into international assets. Can you talk a little bit about your thoughts on international?

Patrick Donald Daniel

Yes, I'd love to be back in international. And we -- this company was highly successful because of what I will call the Enbridge way that we applied to being involved in international in the first place. We went out on a very targeted basis, looked for projects that fit within the investment proposition of Enbridge, hence got involved in Colombia, I guess, it was 13 or 14 years ago, very successful project, very low-risk. And I know that sounds surprising in Colombia, but it was a very low-risk project for us. And I won't go through all of the attributes of that because you've heard me speak to those in the past. And then we've got involved in Spain. We went at it very slowly and methodically and conservatively and we would like to be back in that business now, not because we need the growth but we believe in having a good, broad platform of growth going forward. We know the Canadian companies are very well recognized internationally. Enbridge brings a very unique opportunity as an independent liquids or gas pipeline company, able to construct own and operate in international assets. So right now, we've got activity underway in Colombia, looking at an opportunity there, a liquids pipeline opportunity in Colombia. We also have looked at a number of gas pipeline opportunities in conjunction with the LNG facilities that are being built around the world to supply the Asian market. And we don't have anything to put in front of you yet, but we're hopeful that in the not-too-distant future that we will.

Robert Kwan - RBC Capital Markets, LLC, Research Division

Robert Kwan, RBC Capital Markets. Pat, some questions about your approach to the capital plan right now given kind of the global uncertainty. And if you think back to the last downturn, you took a more conservative approach to the capital plan trying to avoid common equity using some noncore asset sales to help shore up the plans. So as we're in this uncertainty right now, what is your approach? Are you taking more stringent view in making sure that your financing plan is very tight?

Patrick Donald Daniel

Well, even though we're in uncertain times right now, they're of course a lot better than they were in the 2008, '09 time frame when access to the equity markets would not have been wise at all. We have no need with this plan that we have to go to the equity markets. As you know, we did a pref share offering recently and Richard is going to speak specifically to the financing plan going forward a little bit later on. But I guess if your question, Robert, is -- are there things that we would sell rather than issue equity? Well, if we've got to that point, I guess, we could face it at that time. We don't have anything that we're anxious to get out of. But we don't have any need to go to the markets. And we've got good, deep liquidity so we don't think that should be an issue even in the volatile times that we're in. And remember again, at the time even though we had not traded off much relative to the overall market, we still had traded off during that 2009 time frame. It would not have been good for shareholders, for us to be issuing equity then. Even though just about everybody else did it, we chose not to.

Robert Kwan - RBC Capital Markets, LLC, Research Division

I guess it's a little bit more of are you looking or trying to maintain a greater "equity surplus" than you might have, if you went back say a year or last Enbridge day?

Patrick Donald Daniel

I think it's fair to say that we're trying to maintain a little greater liquidity, rather than equity surplus. We're quite happy with the debt equity in the balance sheet, but it's the liquidity that we're making sure that we have in the event that we don't have access to the capital markets for a period of time.

Well, if there are no further questions, I think, Steve Wuori, you're next.

Stephen John Wuori

Well, thanks very much, Pat, and good morning, everyone. Pleasure to take you through the Liquids Pipeline business, as you refill coffee and stretch your legs and so on. I'd like to spend some time on the supply-demand fundamentals. You know that we -- from previous sessions, we talked about the fact that we work on supply-demand fundamentals in the oil business a lot. And we find that that instructs our point of view. It also helps us develop our strategic planning and so I'd like to talk about those and also how that bears on the positioning of our assets, as well as specifically the opportunities that it gives us in Alberta, in the Bakken Shale as an example, and then in the Newmarket extension projects that we are working on, some of which you've seen announcements on already.

So just to quickly to work through that, a couple of pretty basic slides. First of all, world oil demand. If you consider that we are working with a base of somewhere between 80 million or 90 million barrels a day of global oil demand, you can see that between now or 2009 and 2025, the view is that the industrial countries, which of course include and especially the U.S., are actually going decline a little bit in their demand. And that's, I think, something to be very sober about because that also helps us as we think about the need for other markets for Canadian crude.

Emerging markets, of course, being the big story. And of course, you can take your own point of view on exactly how far that's going to go and just how far the Chinese and Southeast Asian and the Indian economies are going to drive global oil demand. But the current forecast, and this is a PIRA forecast, is that about 20% growth in global oil demand is going to be realized by the year 2025. Of course, the U.S. is the biggest, most important market for Enbridge and for Canada, we expect that it will remain so. But this is just a warning that you cannot rely on that market alone and it's important that Canadian production be able to diversify the supply growth in China and elsewhere in Southeast Asia in order to maximize netbacks and, I think as Pat mentioned, to lift the value of all Canadian barrels simply because a separate and a different bid from a different market is available to the crude.

If you look then at OPEC and non-OPEC supply, clearly non-OPEC, which includes Canadian supply, is going to be the main driver. Non-OPEC supply accounting for 60% of supply growth expected over the next 15 years. One of the little-known factoids though is that by the year 2017, the largest producer of oil in the world will be United States. And that's an expected answer when everybody is of the conventional wisdom that the U.S. has to import so much oil, it's going to have to import more and more and more and that has actually turned around completely in the last 2 or 3 years with shale oil growth in the Bakken, in the Eagle Ford Shale in the South Texas, the Niobrara. Now, we're hearing of the Utica Shale in Ohio in Michigan being explored and drilled up.

So that is a very surprising turn of events when you consider that the U.S. who we have long thought would be dependent on imported crude completely and increasingly actually will not be. I think the U.S. bottomed out at about 9 million barrels a day of production, maybe 8 million, a little bit right around in that area. At what point in time, of course, the U.S. produced around 13 million, and the expectation is it's going to return there. And that is remarkable especially when you consider that that is in spite of declines in Alaska North Slope production, which continue on and on.

So the non-OPEC countries, North America, especially oil sands, the oil shales, deepwater Gulf of Mexico. And also the point, I think that's important, as we look at the global construct is that North American production, U.S. and Canadian especially, is not state-owned or controlled, which is very unusual when you consider where oil generally comes from in the world.

So then looking specifically at North America and where the crude growth is going to come from, of course, you see the oil sands and Pat talked about it being the second or third largest oil resource -- proven resource in the world. You'll notice it's already just shy of 3 million barrels per day and the growth is mainly going to be in heavy crude. And there's something very striking about this chart because. We look at the key areas of growth in North America, the oil sands, the Bakken, the Eagle Ford, the Permian and the Niobrara, all but one are light oil growth areas. Every one of those is producing light. Bakken is very light, sweet crude oil. Eagle Ford is very, very light crude oil to the point where something like 80-degree API crude is coming out of the Eagle Ford. It's very much like natural gasoline.

The Permian is the old West Texas oil field that everybody thought were done and gone, and yet they are resurging tremendously in West Texas and in the areas of Oklahoma, the Permian light-medium production, and now the Niobrara in Colorado and Wyoming, which is just getting started. That's also a light crude production story.

So you have a lot of growth in heavy, but only from the oil sands. You have a lot of growth in light everywhere else. And the oil sand projection is to grow by about 1.3 million barrels a day by 2020. Light crude is expected to grow even faster at 2.1 million barrels a day by 2020. So you have then growth of about 3.5 million barrels a day combined light and heavy in North America between now and the year 2020. And that leads to a very important question and that is where is all of these heavy and light crude going to go? And this is one of the fundamentals we spend a lot of time on. Because it isn't good enough just to talk about crude oil growth versus demand. You have to understand where the markets are for heavy crude, where heavy crude can be processed and where the light crude must go in order to attract its best price.

So a quick chart that talks about upper PADD II demand, and I think I remember showing this chart last year and it's worth just listening through again, because there are 3 very important refinery conversions underway in upper PADD II. You have the ConocoPhilips Cenovus Wood River conversion near St. Louis coming onstream in the year 2012, early in 2012, I believe. You have BP Whiting coming on in 2012, '13. The massive reconfiguration of the Whiting, 405,000-barrel a day refinery to run a very, very heavy slate of Canadian crude. And then you have the Marathon Detroit refinery conversion coming on in late 2012, early 2013.

And so that presents a challenge in the left column on the right-hand side and an opportunity on the right column on the right-hand side.

The challenges, you got 430,000 barrels a day by about the year 2013, early 2014, coming off of the upper PADD II market. That's a very serious thing to think about when you think about all of that light production coming on, especially in North Dakota, Saskatchewan, and Alberta, including upgraded synthetic light.

But there's also 's tremendous opportunity for Canadian heavy in upper PADD II and that really supports our thesis that the cokers in PADD II will fill first, they simply must. The investment has been made and therefore, the heavy crude barrel will flow first to PADD II to fill those cokers and then it will flow to places like the Gulf coast, not the other way around.

So what's interesting is that then that presents a tremendous challenge for the light crude because the danger is that you're going to find a deterioration in light crude pricing on product that really deserves to command a premium price. Bakken crude superior in quality to WTI, to Brent, to LLS and to virtually every other crude in the world, ought to attract a premium price. It ought not to price at a discount as it is today. And so therefore, that really leads us to a lot of work on the oil flows and where this crude needs to go.

This map is one that we've just created. I have a feeling we're going to improve on it. There's a couple of my slides as I whiz through them last night that I realized there a tiny bit of improvement. This one is a little confusing, but basically says, here are the keys areas of growth that I talked about earlier, oil sands and then all of the light crude production areas and notionally, where those crude need to go. Generally speaking, oil sands, heavy crude production heading into the upper PADD II area and also upgraded light production that needs to go East and I'll come to that in a moment, and then at South, going into Cushing in the Gulf coast.

The Bakken, again, cannot simply, in our view, dump into the pricing sewer that is Cushing and it really needs a better market. And therefore, our philosophy is that that crude really ought to go East to refineries that are currently paying Brent pricing out on the East Coast.

Niobrara will head for Cushing because there's a pipeline to take it there. But we also believe it's going to help to fill PADD IV refineries and possibly even make its way across to PADD V, perhaps by rail as some Bakken crude oil already is working its way across to Anacortes, Washington. And of course, the Eagle Ford is destined for the Houston refining complex and virtually no place else. And so that is going to in turn put pressure on barrels that we want to bring in from Canada or from the Bakken into the Houston refining complex.

To the left-hand side, and we haven't shown the arrows, of course, there is some oil sands crude that moves west on the Trans Mountain system and goes off the dock and about 80,000 barrels a day on average this year principally moving to Washington State and down to California. You have Alaska North Slope crude coming down, feeding the Anacortes refineries in Washington, but that is in decline.

And one little factoid also is that the Trans-Alaska pipeline flowed less than 600,000 barrels a day last year. It's on track to continue that decline. At about 400,000 barrels a day, it shuts down. It can't be run because of the wax and the crude and the huge diameter of the Trans-Alaska pipeline.

There's some case that you might run it as low as 350,000 barrels a day, but there is an issue with the decline in ANS production and the ability to move crude below a certain level off the North Slope. So that's just a fundamental to keep in mind. But you'll notice a lot of arrows going east on this map, and there's a reason for that. And that is because the light crude in our view, again, needs to go that way.

The much-talked about Brent-WTI spread or LLS, Louisiana Light Sweet, to WTI spread is shown on this graph. And you'll see, of course, that we're at about $25 barrel discount of WTI to Brent pricing. And then, of course, the Canadian producer takes another haircut off of WTI for most grades of crude. So you have the double-whammy effect of coming off the Brent world pricing and then taking another hit off WTI when you get to the Canadian pricing.

And you'll notice that PIRA says that's going to be solved largely in 2013. Somebody or some somebodies are going to build a pipeline from Cushing to Houston and solve that problem. So PIRA says that virtually by 2014 or '15, we have parity there.

The forward curve says no such thing. The forward curve says this is not going to get solved until about 2018. That's the way the market is carrying the discussion forward right now. So that's an interesting fact. And of course, that does drive our Wrangler project announcement with Enterprise that we announced last week, and I'll come to that a little bit more later.

So that's the outlook right now, and there is a need certainly to clear the Cushing bottleneck and to bring better pricing and to reestablish WTI as a legitimate world benchmark. And I never thought I'd say those words after all the years in the business to say, "Let's reestablish the WTI as a legitimate world benchmark." Whoever heard of such sacrilege? But the fact is that WTI is a compromised world benchmark at the moment. And there's much more focus on Brent as the marker, which is waterborne and able to get around the world.

So what does that do then from an overall perspective? We'll look at supply first. This chart is pretty familiar. It is an overlay of our forecast and the 2011 CAPP forecast, the Canadian Association of Petroleum Producers. And you'll notice that CAPP is a little bit more bullish. I think they have a 5.2% growth rate for the Western Canadian basin over this period of time to 2020. Our forecast is a little more muted, 4.4% is what we are forecasting.

The main difference is that there's difference in assumptions between how much diluent blending there is going to take place. I think CAPP assumes a little bit more synthetic will be used for diluent, which increases volume of overall production, and I think -- than us. And CAPP is also showing a lower decline rate for conventional light and heavy crude production.

But you'll notice a huge amount of growth in DilBit, diluted bitumen. And that bodes well for projects like Southern Lights, that we put into service a couple of years ago, flowing condensates from Chicago up into that market in Alberta. So a very strong growth picture.

And there's no question there that Fort McMurray is a very optimistic place. Alberta is a very optimistic place. There are more men and women in the camps now than there were at the peak in 2007, 2008. And so there is a tremendous amount of optimism around the growth there. And that's all well and good and important. But market, market, market, we have to think about if we are going to produce this kind of volume of crude.

So just in terms of concluding on the fundamentals, lots of oil sands growth, rapid oil shale growth, Midwest crude diet clearly shifting to Western Canadian basin heavy, the projects -- the conversion projects having been underway for several years. And also, there's an opportunity created for pipelines by these spreads, the arbitrage between WTI and Brent, between Western Canadian Select heavy crude and Maya. There are pipeline opportunities to help clear that arbitrage.

So now let's walk through, starting in Alberta, a number of the assets that we have. Here is the chart showing the Athabasca Pipeline in blue and the Waupisoo Pipeline in yellow. We are currently in the process of expanding those to their full capacity of 600,000 barrels a day on Athabasca and 580,000 a day on the Waupisoo Pipeline.

And these are the 2 backbone trunk lines that Pat talked about earlier that really give us an advantage in terms of being able to offer people space on those lines as their production ramps up until the point where they need to have a dedicated pipeline. And so that has served us well by having those 2, frankly, oversized when they were built, lines, 30-inch diameter lines that were bigger than they were needed to be at the time. But that has served well now as we see the demands increase.

And you can go to either of the key pipeline hubs in Alberta to the Edmonton refinery market. You can get on to the Trans Mountain system to go to west to Vancouver if there is space on that system or you can go to the Hardisty hub, where you can get on the Enbridge mainline, the Keystone pipeline or the Express/Platte system, which is a holding of Kinder Morgan.

We also have a number of secured expansions on this, and there are 7 that I've listed on the right-hand side of this chart: the Athabasca and Waupisoo expansion; the Wood Buffalo Pipeline for Suncor, which is from basically our Athabasca terminal down to Cheecham. And recently, we announced the twinning of the Athabasca pipeline from the Kirby Lake area down through the lower half or so of the Athabasca line into Hardisty. And that's to serve the growing Kirby Lake SAGD volumes, primarily for Cenovus ConocoPhillips, but also for the other producers that are active in the Kirby Lake area.

And then, gathering system expansions include Christina Lake, the Cenovus project, the Woodland Pipeline for Imperial Exxon Kearl, and the Norealis Pipeline for Husky Sunrise. And I always joke about the creative names we come up with, and they get worse as time goes along as we run out of good names. But the secured capital expansions total about $3.6 billion coming up, and these are projects we're actively working on.

In terms of the future in the oil sands, there's a number of things that I think we are working on that are very interesting, some of which are contracted to us when they are sanctioned, such as Kearl Phase II or all of the future phases of the Christina Lake complex expansion. So pending sanction of those expansions by the sponsor companies, those volumes would come to us and we have pipeline arrangements in place for those.

Potential growth include -- that are not necessarily dedicated to us at this time, could come from the second phase of the Husky BP Sunrise project; Statoil at Leismer; ConocoPhillips at Surmont with its partners; Suncor's additional leases at Firebag; and then new development projects like the Suncor Total Fort Hills and Joslyn projects in Northern Lights; Athabasca Oil Sands at MacKay; and also the lease holding called Borealis, which is a Cenovus holding that is sitting there, waiting for development. So in terms of potential capital, we see about $4 billion beyond the secured expansions that I talked about earlier.

Moving then to the other important regional area before we talk about mainline and markets. The Bakken infrastructure is a fascinating story and a fascinating question. You see here in dark blue, the Enbridge forecast, which we have increased since last Enbridge Day, from peeking out at 600,000 barrels a day to 1 million barrels a day. But Raymond James is more bullish than that, to show one example, and they show it peaking out at 1.2 million barrels per day. So that is a tremendous growth picture no matter how you look at it. They are more bullish than we are. I think probably the key difference there is that we look at land access and permitting and other things, a little bit more stringently perhaps than they do in their forecasting. But either way, there is a lot of crude coming out of the Bakken, with some 180 rigs actively drilling there every day.

So the bill to this slide is, at the bottom, you see the existing pipeline and refinery capacity, about 50,000 barrels a day goes to the Tesoro refinery at Mandan, North Dakota. You have the Enbridge mainline system, which is now at 185,000 barrels a day or so the North Dakota mainline that is that feeds over into the larger mainline system. And then you have the Bridger/Butte, the True Companies pipeline systems that are exiting the area. And that all totes up to somewhere around 200,000 barrels a day.

You have the Enbridge expansion underway, the Bakken Expansion program and other expansions that we have underway. By Q2 2013, you can see the next line up is where we expect to be. We have an expansion of the Bakken expansion that we are considering, and that would be about 180,000 barrels per day.

And then you have a tranche of other proposed pipelines. You have the Bridger/Butte expansions. You have the Quintana pipeline expansion that's been announced. All of those hoping to feed into the Keystone XL pipeline at Baker, Montana, basically moving crude to the west and then down into the Cushing market.

Beyond that, then you have a host of other ideas in terms of rail export. And the shocking thing is if you look at all of the rail exports that people have talked about, you will notice that top dotted line there, there is a tremendous enthusiasm for rail. And I want to talk about that a little bit because it is clearly a force to contend with when it comes to movements of crude in areas where pipelines are either nonexistent or are constrained.

We have Bakken crude showing up in Philadelphia. We have Bakken crude showing up in St. James, Louisiana, New Orleans. It's being railed in different places because of the pipeline constraints that we are working on. And through our Bakken access -- rail access program, we're actually participating in facilitating that for the interim period until we have our pipeline capacity built up.

We do view that rail is generally an interim solution. We do not view that it is the best permanent way to move crude oil in large volume over long distances. But there is no question, it plays a good role right now. The issue is there's so much enthusiasm that it's the Wild West out there right at the moment.

I hear stories of rail cars being loaded by men standing on top of the railcar, holding the hose like this, with a 55-gallon drum cut in half for their firewater protection system. It is a real, real Wild West cowboy type of thing that's going on, as people scramble to get crude onto rail in any possible way that they can. There are much more organized unit train concepts that are being worked on and of course those are much more efficient and so on.

However, I will also point out to you that rail is generally viewed as nimble -- it's expensive but it's generally viewed as nimble, and you can go to different markets. It's very flexible. But now we're finding that the rail car companies are actually demanding long-term contracts. Who would have thought such a thing a few years ago?

But they are -- I've heard stories of 7- to 9-year contracts being demanded for rail cars to be built and for rail cars to move crude. And so you have the same issue then, and that is signing up for long-term capacity. Our belief is you sign up on pipelines for long-distance, high-volume movements. But it is interesting to see how rail has come along so strongly, and there's a lot of enthusiasm as that dash line on top would imply.

Just in terms of the Bakken itself, the pretty familiar blob of the Bakken shale formation and a number of things that are going on, including the mainline system that goes over to Clearbrook, Minnesota. That's maxed out at just under 200,000 barrels per day right now. We've taken that from about 60,000 barrels a day capacity when we purchased the system in 1995.

The Bakken Expansion program, shown in green, moving over -- when that's completed, moving crude from the Bakken in North Dakota up into the mainline at Cromer. And an interesting one that you've not seen before is that it's estimated that something like 10% to 25% of all the Bakken reserve may be held in the Fort Berthold Indian Reservation, which I've shown on a box there, and that's south of the Missouri River. And so the yellow line there, indicates the work that we are doing to secure south of the river production, bring it up into the system and then disperse it to get out to the mainline and to the market. So that's a new element to this whole thing.

The gray line that cuts right through there is an important one, diagonally from northwest to southeast. That's the Alliance Pipeline, the positioning of Alliance. And Al is going to be talk about exactly what we're doing on the gas and gas liquid side using the Alliance Pipeline. Because as you know, there is a tremendous problem in North Dakota and that is far too much gas is being flared in order to enable crude oil production, a tremendous amount. Actually, I'd say a shameful amount of gas is being flared off, and our aim would be to capture that and move it into the Alliance and Aux Sable system.

Here's a netback calculation as we move to the mainline. You've seen a calculation like this before. And what we decided to do this year is to take a post-XL view. Let's assume that Keystone XL gets its presidential permit, which we support by the way. And let's take a view that it's in service by 2014, and that the flows had then equalized around the presence of that system, which is notionally shown in the orange arrow.

If you take $100 Maya barrel at the Gulf Coast and transport it to Chicago, that provides you with a Chicago price of $102.50. Take the $3.85 now under the CTS deal on the Enbridge mainline, and you have a net back in Hardisty or in Alberta of $98.65. If you take that same $100 Maya equivalent barrel and transport it on the XL system back to Alberta, you have a $93 netback. So there's a $5.50 netback advantage for heavy crude to move after XL is in service into the upper PADD II market. Why? Because the cokers in upper PADD II will be fed. The cokers in upper PADD II will be fed by Canadian heavy crude. That's what they were designed to do, and so that's how the pricing will work out.

The U.S. Gulf Coast remains an important market for heavy crude but not for unlimited volumes, not for large and unlimited volumes, because you do have one of the best supplied markets in the world on the U.S. Gulf Coast. And so that's why I think a measured approach to moving Canadian heavy to the Gulf is important when we consider that the barrel will first fill all of what's happening in upper PADD II.

In terms of the CTS deal that Pat mentioned earlier, that really was an important one. It built on 3 previous ITS, Incentive Tolling Settlement deals starting in 1995. And it really pulled together everything that we and the industry had learned about incentive tolling on the crude oil system in creating now the longest deal that we've ever done, which is a 10-year deal. And it provides toll certainty to the shippers, which was extremely important to them.

There was this question. What will happen to the Enbridge mainline toll to Chicago if volumes start to drain away to other systems? Is that toll going to be $6? Is it going to be $5? What is it going to be? And CTS answers that question. It will be $3.85 for heavy oil to Chicago, escalated at 75% of GDPP annually. That's it.

And so that was really important to them as a part of the discussion, and it was important to us. Because to have market extension discussions, there needed to be some level of certainty around what the toll is as far as Chicago before we could talk a lot about what we're going to do beyond Chicago to the south and to the east.

The bulk of the toll is common carrier, when you think about market extensions. You can ride the common carrier with no balance sheet commitment as a shipper all the way to Chicago or further to the east and then, and only then, may you have to sign up for as with Flanagan South and Wrangler or with Eastern Access. You may need to sign up for committed contracted capacity. But your balance sheet commitment only starts at the end of the common carrier system, and that's an important distinction versus having to sign up for a full balance sheet commitment all the way from Alberta.

Attractive returns under conservative assumptions. We've model this conservatively. We've put in a lot of money for integrity spend, a lot of money for opt cost and other things. And we feel very comfortable with where we are on the 10-year outlook.

A substantial upside based on the fundamentals that I talked about and really then, also a strategic tool to support new market access using the international joint toll framework that is a part of the CTS to be able to thread up volumes through with a single toll all the way from Alberta to wherever the new market is. And so that, I think, gives us just generally more tools in the toolbox as we look at market extensions.

The 2 that I'd like to talk about will be to the east. So far, we have announced the Line 9A reversal as far as Westover, Ontario. That's basically to feed the Imperial Oil Nanticoke refinery with light crude sourced from Western Canada. And that is accompanied by our Line 5 expansion that we announced yesterday. I guess it was the Line 5 and the first -- the western part of Line 9 reversal combining for about 120 million for 50,000 barrels a day of incremental capacity all the way through to the Nanticoke Refinery.

And it generally supports the thesis we have, as I said, that incremental light crude production needs to go to the east. All of the refineries on the East Coast and in Montréal are basically paying Brent pricing. And that is a disadvantage when you consider that all of the mid-continent and mid-west refineries are paying WTI or WTI minus pricing. And so therefore, there is a tremendous amount of interest on the part of refineries in the east to access the cheaper Western barrel, the Bakken barrel, the light upgraded synthetic barrel from Western Canada.

So generally speaking, that is the direction that we are going in. There will be more to say and more to hear about that, but I want you to know that Eastern Access is certainly supported by the belief that light crude incremental production does need to move to the east.

In terms of mainline expansion, a number of different things totaling possibly about $3 billion of capital, driven by the Eastern Access projects and the Southern Flanagan South and Wrangler expansion projects. There's a lot of different ways that we're looking at this. Some of the examples that I've shown there on the key on the right-hand side but basically, beefing up the capacity all the way from Western Canada.

And who would have thought we may think about expanding Alberta Clipper so soon after it went into service? But we are considering that. And also the Southern Access pipeline shown in blue between Superior and Flanagan and other mainline expansions, all to make sure that there are no upstream constraints on throughput or capacity as we look at the new market extension projects.

So then going to the south, and this does get into the Spearhead Twinning or as it's called in our open season, the Flanagan South project, which starts at the hub there at Flanagan where the Southern Access line comes in. It goes down to Cushing, probably paralleling our existing Spearhead Pipeline that now moves crude to Cushing.

And then the joint venture piece is the Wrangler Pipeline, the 50-50 JV with Enterprise that we have announced to move about 800,000 barrels a day of light crude between the Cushing hub and the Houston and also Port Arthur markets. Port Arthur is mainly a heavy crude market, and we are accessing that market from Houston with a leg to accommodate the pull-through Canadian barrel coming all the way down that needs to end up in Port Arthur.

But what's important about the Wrangler project is that the 2 companies have come together, having worked on this concept for years independently, neither one of us quite having everything that it took to put the project together and still achieve an acceptable risk return ratio for our shareholders. But now we've discovered that with the powerful position we have at Cushing, where we're connected to every pipeline in and out and we have tremendous storage capability, the ECHO terminal that Enterprise is building in Harris County, south of Houston on the Ship Channel, that -- those combine to offer tremendous flexibility for shippers in being able to move crude to and from those hubs.

The ECHO terminal will also receive Eagle Ford volumes coming across on an Enterprise line so there's even more flexibility for producers and refiners in that area. It's an exciting project. The open season is open until early November. We'll see where that goes. We're interested in barrels to clear the Cushing market. That's the reason for the big capacity, but also interested in pulling the Canadian heavy barrel all the way through using the international joint toll feature of the CTS.

Pat talked quite a bit about Northern Gateway. And in the future, you're going to hear Janet Holder talking a lot more than me about Northern Gateway, as she is clearly in the chair and is really looking at focusing on that. And by the way, she'll answer any Northern Gateway question today, I think, rather than me.

But we do have, as we announced last month, full commercial support for all of the capacity of the line that's been filed. Pat mentioned the community hearings in January and then the final hearings in June in front of the joint review panel. And so I won't spend too much time on that. We know -- and I think we've been clear about what the concept is.

But what I do want to spend a minute on in the moments that I have is the importance of this project to the Canadian producing industry when you consider that our only market today is the United States. I came from there. I love the United States. I've spent 31 years of my life making my living moving oil from Canada to the U.S. So I have nothing against the U.S. market, believe me.

But there are some warning bells that are ringing pretty loudly when you think about relying on that market alone. And they are as follows -- and keep in mind, that it is all in the context of total Canadian exports to the U.S. of about 2 million barrels a day and that includes everything that's moving from Hibernia in the East Coast down to the Philadelphia market. Those are counted. So something under 2 million barrels a day coming out of Western Canada being exported to the U.S.

First of all, you have flat demand in the U.S. Demand peak for fuels and crude consumption in the U.S. in about 2007, 2008, and it's been declining ever since. You have rapidly rising supply that I talked about from the shale plays: the Bakken, the Eagle Ford, the Niobrara and others. That rising supplied within a few years will be 2.6 million barrels a day, again, juxtaposed against the total Canadian exports today of under 2 million barrels a day to the U.S. You have a rising production in the U.S., which by definition will displace foreign barrels, including Canadian barrels. It will have to because it will not leave the U.S.

You have the, in my mind, much-hated ethanol mandate in the U.S., the biofuel mandate, the insane course of trying to take food, corn and make fuel out of it. Food in short supply in the world, fuel not in short supply. It's reprehensible. But yet, here we are with an ethanol mandate that today has corn-based ethanol at 925,000 barrels per day, every day of production.

That will displace not one barrel of crude but it displaces 2 because that's refined product, the biofuel, the ethanol. And so therefore, when it goes into the displacement equation, it actually is displacing 2 crude oil barrels, more or less, if you take half the crude cut as a transportation fuel so -- or as gasoline.

So you have that mandate. And they're now trying to push E15 instead of just E10, trying to push the blend wall all the way out to the 15% blend level. The engine manufacturers scream bloody murder and everything else, but you have an undeniable corn lobby in the U.S. that is displacing crude oil demand.

You have the threat or the opportunity, depending on your point of view, of the truck fleet, the heavy truck fleet in the U.S. converting to NGV. And that actually is an attractive proposition when you consider the abundance of natural gas in the U.S. If that were to occur, the general calculation is that would displace 2 million barrels a day of crude oil demand. So there you have the Canadian number repeated a few times in terms of the threats to the Canadian barrel in the U.S.

Now will the Canadian barrel be displaced out of the U.S.? No, because it has to move there. There is no other market. But what is the victim? The victim is price. And that's really what Northern Gateway pipeline is all about. It is not about whether you can move the barrels to the U.S. We can do that, of course. But it is the price punishment that takes place when you have no other market available.

I've stepped down off my soapbox now, and I will proceed on to things of more gravity with your operational strength. Last year showed this chart. We're now a year into this organizational structure with very clear -- as Pat said, very clear mandates. We focus upon operations, safety, pipeline control, pipeline integrity. And we have very senior leaders named to each one of those components, including leak detection, including integrity, control -- pipeline control, control center, very senior leaders. And that has worked out exceptionally well, having that kind of senior singular focus on those areas, I think, has really shown itself well in the last year.

In terms of operational reliability, we are the largest user of inline inspection tools, I think, in the world, but I know in North America, clearly in North America. We have 150 smart pig runs planned or having been completed in 2011, and it really is the best leading indicator. It is the way of the future in terms of diagnostics on pipelines, as we search for the frontier of being able to find smaller and smaller features, corrosion in cracks, minute cracks, things like that, that have heretofore not been able to be found by inline inspection tools. The picture shows one of the latest crack inspection tools that travels in with its onboard computers and sensors through the pipeline.

In terms of fieldwork, we replaced the St. Clair River Crossing successfully with a directional -- hydraulic directional drill. We did that in the winter months. We have examined over 1,000 sites along the Enbridge system, including Line 6, but also all across the system. We replaced 14 segments of Line 6B, and we are applying to replace 75 miles of Line 6B in 2012, finishing in early 2013.

So just a tremendous amount of focus, and this dovetails with Pat's comments about the Operation and Integrity Committee, reporting on the progress every month as to what we're doing and what we're focused on.

So my last couple of slides then give you a sense for the overall opportunity set in Liquids Pipelines; the secured projects on the left; the projects that are under development on the right; close to $25 billion of opportunity coming in the next year 2 or 3 or 4 years. And those are risked conservatively. We've taken a conservative view of our success rate on some of the projects that you show -- that you see along the right-hand column.

I now have a slide that is full of useful information and data. And this basically tells you that the future is very bright, as Pat would have implied at the beginning. I can't imagine what else it tells you beyond that, and I rely on Richard's wrap-up slides to give you some meat around that.

So my last slide then is just key takeaways. And that is that the evolving fundamentals of oil supply and demand are really driving investment opportunities. We use those fundamentals analysis to instruct ourselves on our point of view, on our

strategic planning, on our view of the markets and on our view of where we need to go and where the next pipeline access point needs to be.

The CTS agreement is a tremendous backdrop for that. It gives certainty. Not being in the hearing room for 10 years or even the threat of it, it is a tremendously strong win-win for ourselves and the industry. And I have to say that since we announced the CTS, our business development discussions, which were ready very robust, have ratcheted up even more with the certainty, again, that the CTS provides to the industry. A continual focus on operational excellence and superior earnings growth, as that last slide showed you so clearly.

So that ends my portion. I'd be very pleased to take your questions.

Winfried Fruehauf - Fruehauf consulting

I have a 3-part question. Winfried Fruehauf, W. Fruehauf Consulting Limited. First one is on your Slide 4. Why did you do not include the Monterey formation? That's the first question. The second one is, can you show how combination of electric vehicles, NGV, non-petroleum liquid fuels would impinge on the supply prospect for Canadian crude petroleum? And thirdly, what is your view of petroleum supply from the Arctic area for Canada, U.S., Russia, Norway and so on?

Stephen John Wuori

Okay. Winfried, the Monterey -- are you talking about the Northern Mexico formation or the San Joaquin Valley?

Winfried Fruehauf - Fruehauf consulting

The one in California.

Stephen John Wuori

Yes, it's there. Clearly, a lot of the California market is supplied by that heavy oil formation. We don't see a lot of growth at this time in that formation. And I think that California, being a particularly challenging place for oil development especially, I think the Bakersfield, San Joaquin Valley formation area is an important one. It is heavy -- it's as heavy as oil sands crude. We just don't see at this point compared to the other areas of great growth, a rig count or anything else that's really climbing there.

Winfried Fruehauf - Fruehauf consulting

But it's not the San Joaquin Valley. It goes really to the Pacific Coast and extends east to Monterey.

Stephen John Wuori

Yes, exactly. The problem I guess is probably land access and permitting. I just think that in that area of the country, proposing more oil development as opposed to more renewables development is a very tough equation. The second thing you had was NGV. I think there is a lot of optimism around natural gas vehicles, not to convert the whole passenger car fleet. We've tried that in Ontario. And frankly, it doesn't work. It just isn't -- there isn't enough infrastructure to support it. But it is fascinating to think about the heavy truck fleet converting, particularly in the U.S. And as I said, the rough calculation is that if the entire heavy truck fleet converted to NGV along the major interstate highway systems, about 2 million barrels a day of demand for crude would come off the market. So that is pretty significant. You could probably play with those numbers in a few different directions and to what degree will there be this conversion. But I personally think there's a great opportunity there to convert the truck fleet running along established interstate routes. There is the possibility of infrastructure for that.

Winfried Fruehauf - Fruehauf consulting

And what -- I asked about electric vehicles also.

Stephen John Wuori

Yes. If they went any place, they'd be great. I think that's the main problem. And that is that in our society, to go 150 miles and then have to be looking for a plug-in station just won't do. And of course, the Chevy Volt has solved that by having a little onboard motor, which sounds a lot like Pat's and my Priuses, where we've got hybrids that are electric, but by golly, they got a little wee motor hidden in there whirring away. And I think hybrids are the answer. But ironically, Winfried, hybrid sales are in decline. Hybrid sales peaked in 2009, and they've been declining ever since along with fuel prices. And so that's the frustrating thing is that fuel prices, gasoline prices being where they are, do not incent people generally certainly in the direction of electric vehicles, which are just like the zoo exhibits right at the moment. They're just very odd. There's no mass market penetration. And the hybrids would be the classic example of a car you can drive like a normal car, but they just don't penetrate. So I'm not, frankly, very bullish on a mass market appeal of electric vehicles.

Winfried Fruehauf - Fruehauf consulting

But what about EV mandates, for example, which would go far beyond the impact at the petroleum [ph] price?

Stephen John Wuori

Right. Well, 0% chance of that in the U.S. until at least 2013. There is no way that any such mandate or anything else around the climate change file will proceed until after the presidential election a year in November from now. And I really don't see Canada moving to any kind of an EV mandate either. And your last question was around the Arctic. I wish I could be more bullish but I'm not. I think that the prospects for natural gas moving off the Alaskan North Slope or off the Mackenzie Delta are a long way off. There's just too much shale gas and more everyday being discovered across the Lower 48 and Canada for that.

Winfried Fruehauf - Fruehauf consulting

But what about Arctic petroleum? I was really asking about that.

Stephen John Wuori

Yes. The old saying with Gulf Canada was something like it had lots of oil and lots of gas but at the time it was $4 gas and $40 oil. There's a lot there. Our Norman Wells pipeline penetrates the furthest up of anything, moving the production from the Northwest Territories down, that's been generally in decline. There is exploration, seismic activity that goes on every winter in the Mackenzie Valley. But again, you face the prospect of going head-to-head and colliding with Bakken shale production, low cost, can be produced a lot cheaper than where the prices are today. I think it's expensive petroleum for today's environment.

I think -- is Andrew next?

Andrew M. Kuske - Crédit Suisse AG, Research Division

Steve, Andrew Kuske from Crédit Suisse. Could you just put into context the competitiveness of the U.S. refinery network, especially those on Tidewater, irrelative to what we see globally and the implications it has for your crude dispersion version in particular out to the east? Are the Atlantic refineries, in particular Delaware River and other areas really competitive on a global basis, given the size and really the lack of scale right now? And then also looking southward, how do you think about the refineries in Texas and Louisiana and how competitive they can be on a global basis?

Stephen John Wuori

Yes, it's a great question. And you noticed that the Delaware River refineries are generally in the process -- several of them are closing or being sold and they are caught in kind of a classic squeeze where they have the Colonial affect, I'll call it, where the Colonial pipeline moves 2 million barrels of refined product from the Houston Gulf Coast refineries, feeding off of fairly cheap crude up New York Harbor. So you have that issue for the PADD I refineries in Philadelphia in that area. You have the Irving effect coming in from the north. You have -- they have 60% of the New England fuel market right now. I suppose that squeeze coming in from the north as well. And so I think, Andrew, that my answer to that would be that if there were good access and reliable access to lower-priced Western Canadian upgraded synthetic and Bakken crude in Philadelphia, the competitiveness equation for those refineries would shift. Just as you look further north, the refineries in Eastern Canada also have an interest in accessing that crude because they are paying Brent pricing or West African. So I think the general notion is that the Philadelphia refineries are challenged because of the refined product movements up from the south from the high-efficiency refineries running on cheaper crude in Houston along the Gulf Coast. That could well change if there is access developed to get crude, light crude to them from the west.

Andrew M. Kuske - Crédit Suisse AG, Research Division

And then on a slightly different but related question. When you think about all the crude terminals you've got sitting at Cushing and generally speaking, most of those you contracted out between 6 to 9 years on term contracts, when do those contracts start to roll and to what degree have you actually got back your capital?

Stephen John Wuori

Yes, well, the contracts generally run from 5 to 7 years. It's hard to get a longer contract for storage especially among those who just want to play the arbitrage market. That's something we pay a lot of attention to as we add tankage at Cushing and other places. What is the duration of the contract? How much of the capital has been recovered? Of course, the issue being that as far as being -- its financial performance, you're depreciating those over, say, 20 years anyway. So your depreciation charges are still there even if you have recovered a lot in the early years. It's a great question. At what point, in a 55, now climbing toward 60 million barrel complex, the Cushing complex, at what point are there too many tanks and at what point will that capacity be surplussed and obviously prices go down? It doesn't appear that's going to happen anytime soon because you have the Permian Basin crude, which is basically pointed at Cushing, coming up the Plains basin system. You have the Niobrara from Colorado coming down on the White Cliffs pipeline that Plains has and that will be increasing. You have Canadian and Bakken production. And if XL goes ahead and they take Bakken from Baker, Montana, it's pointed straight at Cushing. So the Cushing hub is always going to be a serious waypoint and clearing point for crude and so that's where our analysis as we've added tankage there has been that the risk of having underutilized facilities is fairly low if you're connected to everybody, if you have full connectivity. I think the ones that could be compromised, though, the tank farms that do not have good connectivity to the in and out pipelines at Cushing.

Linda?

Linda Ezergailis - TD Newcrest Capital Inc., Research Division

I was wondering if perhaps you could give us some sensitivity for CTS with respect to a few key variables. I guess I realized you can hedge power costs over the near term. But looking out to the other years of the CTS, what would be your sensitivity to changes in power costs? And then also with respect to -- I guess it depends on what -- how heavy the crude is but given your expectation of a product mix in the system, what a good volume sensitivity would be? And I realize it's not linear but if you could help us out with that, that would be appreciated.

Stephen John Wuori

Okay, I can be partially helpful, Linda. We've already hedged virtually all of the Alberta power demand for the length of term of the CTS. It's harder to do in other jurisdictions but we have hedged that. We've also hedged the interest rate and FX affect throughout the term. So we've tried to lock those in and take those variables off the table. I don't have an easy and memorable power cost variability, although we have run scenarios of different power cost in the CTS calculation. Volume wise, of course, everything will be distance and commodity adjusted. So the $3.85 will go down by 20% if you're moving light crude and so on and then that will be distance-adjusted. The $3.85 is just a memorable number to Chicago for the heavy barrel from Hardisty. And I actually don't think that I'm prepared to give a sensitivity as to what volume means. It does mean a lot. I would not want to put out anything that would cause someone to try to back calculate things that CTS is not intended to generally reveal competitively. But volume is important to us. We have the volume floor that we've established, of course, that we're nowhere near and that's a protection measure. But above that, volume will be important and that's why the market extension projects are important. It makes CTS more attractive. I wouldn't want to put out a sensitivity as to exactly how to quantify that.

Linda Ezergailis - TD Newcrest Capital Inc., Research Division

Okay. Can you maybe give us a sense of how non-linear the costs are as the volumes go up?

Stephen John Wuori

Generally speaking, as volumes go up they will be relatively linear for quite a while as we fill capacity. As we get close to capacity, then power costs, of course, start to ramp up as you near capacity on all lines. So -- and that's where we're looking at, say, an Alberta Clipper horsepower expansion and Southern Access. So I don't have a good off-the-cuff ramp up sensitivity for that. But as long as we are well within our capacity, which we are at the moment, generally speaking, it's a fairly linear progression.

Chad Friess - UBS Investment Bank, Research Division

I wonder if you could speak to the advantages or disadvantages that Wrangler might have over a potential expansion of Keystone XL once it -- if it gets approval and assuming it's built?

Stephen John Wuori

Yes. Maybe I'll try to find the map there. So generally, Wrangler -- I think the key advantages are that, first of all, Wrangler is designed to clear the Cushing bottleneck. So that is a clear for the mid-continent producer and those that have significant interests in crude at Cushing moving to a better-priced market. That's what that's designed to do. In terms of the pull through effect of the Flanagan South portion of that, I think there's several advantages. One of the issues with Keystone XL is that it passes past no refineries of any size or anybody that can run heavy crude until it hits Port Arthur, Texas, and that removes optionality. There is no optionality to that barrel leaving Alberta for 2,000 miles. And by passing Minneapolis and Chicago, there is far more optionality for that barrel especially when you're thinking out 20-year commitments -- 15- to 20-year commitments. There's a lot more optionality to the barrel to ride the common carrier past all of those refinery doorsteps, big cokers at Minneapolis and Chicago. I think that's a very serious advantage for the pull through effect of using the common carrier to Flanagan and then getting on the Flanagan South and Wrangler system. And then the other advantages, as I mentioned earlier, the balance sheet commitment is about half to one who would commit to move that crude from Alberta to the Gulf Coast because the balance sheet commitment only starts at Flanagan. You don't have any commitment up until then on the common carrier. I think, Chad, those would be the 3 things that I would really point to.

Carl L. Kirst - BMO Capital Markets Canada

Carl Kirst from BMO. Actually, maybe keying off that question, just given the size of Wrangler and the challenge that Double E faced, what's the size of commitments that you think you would need to make that go forward? Is that something that you could do it at half contracted or would have to be 85%, 90% contracted? That's the first question.

Stephen John Wuori

Yes, I don't think it's 85% or 90%. Half might be a little bit light. We're working that right now, and we have been working with potential shippers and now looking at what the open season unearths. We will obviously have an assessment in early November as to where we stand. Having talked to virtually every barrel that potentially could move or should move or may want to move in that quarter, I think we understand who the players are and what their drivers are pretty well. The important thing is that they understand that they do need to commit, either to see the project go forward or to secure access and the lowest toll. And that's really the offering as opposed to just saying, "Well, let it be built on other's backs and then we'll just ship on a spot basis." They will pay more than the committed shippers. So that's why we need a certain level of commitment. I don't have for you today exactly what that's going to have to be.

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

And I appreciate that. And then maybe a follow-on question. I guess, maybe you can help me if this is a concern or if this is not a concern. If in come late 2013, we do happen to have both XL, Wrangler built, do we wind up with any kind of full path overcapacity such that we get a pancaking effect and basis, I mean, assuming the net back from Hardisty and the Gulf Coast as kind of being of a full tariff net back of sort of our experience, obviously, in the gas pipes as you build a new line and basis class is to 0. Is there any risk if that happens in the early days in which case, it might have a feedback effect to Chicago. You get a greater net back going down to the Gulf Coast.

Stephen John Wuori

Yes. I don't think so, Carl. And the reason basis collapses in gas is because gas is gas. Gas is fully fungible. It has no personality whatsoever. Crude oil has multiple personalities, like schizophrenia or whatever. But crude oil is very, very different than natural gas because the refineries tool themselves to run on specific slates and blends and assays of crude. And therefore, when the PADD II cokers all our tooled for the most optimum blend, even changes in the dynamic -- the pricing dynamic to the Gulf Coast aren't going to rest away those crudes from those refineries. In gas, exactly what you described has happened. There's no basis anywhere anymore because there's so much gas every place. But I do not see that happening in crude oil because there is a tremendous differentiation in crudes and in exactly the blends that the refineries want to run. That's why we move 80-plus varieties of crude in our system, and it's frustrating. We'd rather move 30 or 20. But we move 80 to 100, actually, just because of these specific blends that the refineries want to tool for. And once they're on that diet and the pots and pans are all tuned for that, they don't shift very quickly.

Juan Plessis - Canaccord Genuity, Research Division

Juan Plessis, Cannacord Genuity. You outlined a number of secured expansions and future opportunities around your Alberta regional infrastructure division. In recent weeks, you've seen some weakness in the price of oil. At what price of oil would you expect to see a slowdown in the development of oil sands activities and what impact might that have on both the secured expansions and the future opportunities?

Stephen John Wuori

Yes. That's kind of the perennial question, and that is at what point does oil sands become uneconomic. I guess conventional wisdom today is hovering around $60 to $70 a barrel for new projects go, no go, at a very -- and it be a gut check call to do it at a $60 a barrel to do a new project. It depends on the projected cost per flowing barrel of the lease. But I would say that crude going to, staying around the $60 level or less, would certainly cause projects that are not sanctioned at this point to be evaluated or reevaluated. Of course, with existing projects, it doesn't much matter what the price is. You don't shut in an oil sands plant. You don't shut in a mine. You don't shut in a SAGD operation. They will produce oil at virtually any price point because they simply must. Unless, of course, you go to the point where you are literally bleeding cash, in which case the world stops. But there is no shut in, there is no shut in. And that's why these decisions are so important for the producers because they are ratchets. They recognize that once you ratchet and sanction, you're going to produce oil. And you will then -- painful or not, you will continue producing oil through all of the cycle. It's the new projects and the decision points. And my guess would be that at about that, that's where you would see a depressive effect, I think.

Does Pat have a remark on that or?

Patrick Donald Daniel

Juan, it looks like you had a follow on to that?

Steve, I was just indicating we're running a little bit late. If there are further questions, if we can maybe hold them for later for Steve and move on with Al. And probably, what we're going to do is cut the break down a little bit so those of you that need to grab a coffee or washroom break, do it as Al sets up, please.

[Break]

Al Monaco

Okay. Good morning, everyone. It's always a challenge to follow my colleague Steve because of the number of projects he has on the horizon. Also challenging because he says gas has no personality. But we are equally excited about our gas business, which I'm hoping to convey in my discussion.

So I'll do this in 2 parts. I'll begin with an overview of our gas business, the fundamentals, then discuss our priorities and strategies. And after the break, we'll do the same for green energy. I'll give you a snapshot of international and energy services. And at the end, I'll bring that together with our outlook for capital investment.

So this Slide is a 50,000-foot view of our natural gas and green energy footprint. Alliance and Vector long haul pipes connect about 1.6 Bcf of liquids-rich Western Canadian gas to the Midwest and Eastern markets. Aux Sable, which was talked about in our question period earlier, is situated at the end of Alliance and is growing in importance.

As you'll see, we've got a dominant gathering and processing position on the onshore Texas region. And our offshore system moves about 40% of the gas in the Gulf. Most notable, though, you can tell by the yellow shading here, the assets are ideally positioned on top of the most prolific unconventional plays, the Montney, the Bakken and the Granite Wash. All exceptional NGL-rich areas that are still in the very early part of their growth cycle.

As I'm showing on this pie chart here, our earnings are nicely diversified within the mid-stream value chain, an area of excellent growth potential given positive gas and NGL fundamentals. The green energy and energy services slices here are expected to grow. And international, although not part of the pie today, is likely to be in the future.

Our objectives for this business are pretty straightforward. Most important, ensuring the safety, integrity and operational reliability of the assets. Everything else is second to that. We're going to continue to pound home that message. The goal, though, is to capitalize on the asset position you just saw and expand on it so that we contribute sustainable earnings to Enbridge overall. Now those strategic and financial objectives will be achieved within the existing business model or that triangle that Pat referred to earlier on.

So that is the very, very big picture. Now let's move into gas transportation and processing. Let me begin with the role of natural gas and how we think of it at Enbridge. We've heard of gas being the transitional fuel. In fact, we think it's going to be much more than that the most critical part of meeting North American and global energy demand.

A major reason for this is intensified concern over other forms of energy, and that means coal and nuclear. At the same time, the fundamentals of gas as a reliable and plentiful fuel source have improved markedly. The issue with natural gas used to be the price volatility for end-users, which has now being diminished considerably.

So now proven reserves stand at about 330 Tcf or that's about 12 years worth of production, but that's only part of the story. With the advent of shale gas, what's more important is the total resource picture, which is shown here. That's because there's very much higher degree of predictability with shale reserves, with much less exploration and development risks. So it's more like a manufacturing operation, much more akin to oil sands than it is exploration.

You can see gas resources have driven -- risen sharply here since 2004, making an abundant and low cost fuel, particularly since the drilling for natural gas is highly responsive to demand, so that keeps the prices in check. And at forecast prices and heat rates for combining cycle plants, gas is very competitive with coal. And finally, of course, it's the cleanest of the fossil fuels.

Now shale is expected to drive U.S. gas production from 60 to 80 Bcf per day over this time frame I have here. The key areas of supply growth in the lower 48 will be the mid-Continent, the Permian, the Rockies, Appalachia, and the U.S. Gulf.

Over the last 2 years, a consensus has also emerged on the WCSB. We'll see pretty much flat volumes over the next 3 years due to conventional declines followed by a steady increase from there. Near-term WCSB growth will come mainly from Northeast BC.

Now there's a few reasons why production growth makes sense with current price projections for gas. First, the nature of shale reservoirs drives much better recovery and initial production rates from wells, which significantly enhances producer economics. In terms of cost, there's been a step change in the application of horizontal drilling and huge economies of scale from multi-well PADD and multi-stage frac-ing. This is though a very big player business. Some multi-well PADDs can range between $200 million and $300 million, so you need a lot of capital, and as I said, it's a big producer game.

The biggest game changer however, though is the value of NGLs in the gas stream and I'm going to illustrate that in a moment here. On the consumption side, U.S. consumption is expected to grow due to higher power generation load for the reasons that I mentioned earlier around natural gas, particularly for coal replacement. There's less debate about the coal replacement story today, that's because if you look at the coal-fired fleet, the vast majority of plants are reaching new retirement age of 45 to 60 years.

By 2017 in fact, 17,000 megawatts of capacity will be more than 60 years old and 65,000 megawatts will hit that age by 2025. So the point is with increasing emissions regulation, which is a fact of life and given the massive investments required to convert coal plants and meet those emission requirements, some coal capacity is going to be displaced. And because of that, the key areas of gas growth will be the U.S., Midwest, and Southeast. And on the Canadian side, growth is going to be coming from the oil sands.

So based on that outlook here, I'll walk through our view of changing gas flows over the next 5 years. So the blue arrows are going to show increases in flows, and the red show decreases in flows. Now the key area will be rapid growth in Marcellus. And that production is going to grow, a lot to do with the fact that its proximity is very close to the U.S. Northeast market.

In the near term, Marcellus volumes are going to displace gas from Western Canada, the offshore Gulf Coast, and the Rockies. We're already seeing reduced flows on Iroquois cost as a good demonstration of that. More Rockies' gas is going to get pushed west, which also puts pressure on WCSB flows. Growth in Western Canadian sedimentary basin supply is partially absorbed though by increasing oil sands growth.

Now there's 3 implications of this that I think are important to discuss. First of all, the abundancy of gas and location of gas, the new shales in particular, will transition the marketplace from a demand pull to a supplier push. There will be near-term excess capacity of long-haul capacity on certain routes. And most important, increasing WCSB supply will put pressure on Alberta prices, and that's going to result in a wider basis differential to the Midwest prices, which bodes well for our line's pipeline.

We also see in the longer-term beyond 2015 the need for LNG export capacity from Northeast BC, and the arbitrage here between North American gas prices and oil Indexed gas prices is just too large to ignore. And the bottom chart here shows that Asian gas prices are more than sufficient to cover the full cycle costs of Northeast BC gas, even without full indexing the oil prices that we see in the Japan cocktail, the mix for LNG.

The fundamentalist for NGLs are equally important. Now the chart on the top right shows very strong NGL supply growth, and we've all been through price volatility on NGLs before, so the question is what sustains that kind of profile? Now as you can see from the bottom right chart, global demand for light-end products is expected to grow at about 1.5% annually. The biggest component of growth will be petrochemical demand, including NGLs. And that's the middle slice of that bottom right-hand chart.

Now ethane, which accounts for about 40% to 50% of NGL, the NGL stream, is a key export petrochemical feedstock for polyethylene, which is used in the manufacture of plastics and other products. And as you know, these products will see significant growth in China and Southeast Asia.

Now because ethane competes with NAFTA as a feedstock and is correlated to gas prices, this creates a very strong competitive advantage for North American ethane. So in a high crude price environment, coupled with growing North American gas supplies that are relatively disconnected from the rest of the world, NGL prices should continue to be strong.

So that left-hand chart on the bottom is very important. If we had shown that 7 or 8 years ago, the red which is the competitiveness of the U.S. ethane supply, would have been on the very far-hand side to the right and that's simply because we had a very low crude to price -- crude to gas price ratio back then.

Now the second part of that equation is NGL infrastructure constraints. This chart here shows the concentration of ethylene cracking capacity in North America, about 80% of which is located at Mt. Belvieu. That's at the bottom down on the Gulf Coast.

Now due to the location of liquids-rich gas plays there's a significant lack of pipeline capacity to move Y-grade or NGL mix, and this is illustrated by that chart you see alongside thereby the Conway Mt. Belvieu basis for ethane, which has widened out considerably over the last couple of years. Now this is very similar to the situation that Steve described in terms of oversupply pushing. So solving that Conway Mt. Belvieu connectivity problem presents a good opportunity, which I'll talk about.

So based on those fundamentals, this is our price forecast range that we're using, essentially a strong gas supply and a gradual return to economic growth results in a medium-term outlook of about $5 to $7 in MMBTu. And as the oil to gas price ratio is expected to remain relatively high, C3-plus margins should be stable and attractive over the next few years. All of that bodes well for our U.S. gathering and processing business and our Aux Sable facility.

So that's a quick review of the fundamentals that are driving our strategic priorities. The priorities are labeled here. First of all, we're aggressively attaching new liquid-rich gas from the Montney, the Bakken, the Granite Wash, and East Texas, to our long-haul pipelines and GNP assets. We'll capitalize in growing supply in Northeast BC through our lines and vector pipelines. Growing Northeast BC supply also drives our goal to establish a Canadian Midstream business. We're working on expanding our NGL position, both in the Midwest and the Gulf Coast region, and finally the strategy is to optimize and grow our offshore business.

So on the first strategic priority, we've made good progress in attaching liquids-rich gas to our systems over the last 18 months. In the Montney, we acquired the 2 plants there that you see in the Septimus area, which we then connected with the new 20-inch pipeline to Alliance. We were actively pursuing more liquids-rich gas in the region and we actually have a planned 60-kilometer loop of alliance that you see there in the dotted blue.

In the Bakken, we recently acquired the Prairie Rose pipeline and the Stanley Gas Plant from EOG and last week, we announced the Tioga lateral. That's an 80-mile line that will connect liquids-rich gas from SS complex. All of these projects are underpinned by long-term producer commitments, and they position us very well to capture initial growth.

Steve mentioned some growth south of the river. You can see here our extension into the Bakken is going to help with that. In addition, part of the thinking here is to capture some of the flare gas and NGL volumes that you heard about. Now these investments are attractive in their own right but the strategic upside here is really from drawing more gas and NGL going to Alliance and Aux Sable, which I'll cover now. And just before I get into that, if you look at those 2 fingers into the Bakken on the bottom chart there and you -- I remember Steve's discussion about the oil side, we really do cover a significant strategic position in the Bakken oil, gas, and NGLs overall now at Enbridge.

What's unique about our Alliance Pipeline is its high-pressure dense phase design, which lines up extremely well with the liquids-rich gas growth that we just talked about. That volumetric toll that's used in Alliance is cost-effective for producers and that the higher BTU content of gas, the lower the effective transportation cost.

What's evolved here though is an even bigger advantage in that Alliance sits atop the highly liquids-rich Montney and Bakken shale plays, and possibly, quite possibly, another future liquids-rich play, the Duvernay, and that's all expressed those blobs that you see in this map.

The impact of Alliance's proximity to these plays is shown by the bottom 2 charts. Now the BTU content of Montney and Bakken gas is significantly higher than Alliance. So you're talking about 1,160 and 1,400 BTU versus 1,070 for Alliance. In addition to the higher BTU content, the volume profile in those 3 plays is set to take off over the next few years reaching in the 5 to 6 Bcf per day.

Alliance is fully contracted at 1.3 Bcf until at least 2015. As you can see from the chart here, the current Alliance Vector toll is very comparable to the Chicago and Dawn hubs to the competition. Equally important, the Alliance and Vector path provides producers with direct access to the Midwest and Eastern markets. And this allows for producers to achieve superior netbacks. Those factors are expected to keep Alliance full for many years to come.

Now despite being contracted until 2015, we are taking a proactive approach with producers to understand their needs as we look to re-contract the line. And if you go back to a couple of slides ago, the Montney and the Bakken connections that we've recently made with Tioga and the Prairie Rose pipeline, that I talked about, along with those long term commitments that come with those, provide some good early evidence that we will be able to extend the term of the Alliance contracts beyond 2015.

So based on what we've discussed to this point, it's evident that Aux Sable will benefit from NGL fundamentals and the Alliance advantage. Volumes are expected to increase to 90,000 barrels per day from about 72 this year in 2012. Now that's primarily reflecting the Montney and Bakken connections I described earlier.

Aux Sable is also able to cost-effectively expand and attract new volumes through rail-loading facilities, which we now have in place. There's also very good opportunity to extract NGL from refinery off-gas streams and the construction of the off-gas recovery project in Edmonton with the Shell Scotford refinery was recently put in place.

Now over the last year, we've been talking to you about a strategy to establish a Canadian Midstream business, which is driven by a confluence of factors. The most obvious ones are production growth from Northeast BC, and the huge need for Midstream infrastructure in that area. This region is also very much underserved by large well-capitalized companies and there's now a willingness by producers to have Midstream players involved. That's because at low gas prices and given the value of NGL, it makes sense for them to deploy capital to the drill bit rather than Midstream.

Now the biggest driver by far that we found is that producers are very much focused on ways to counter the higher cost of transportation from Northeast BC to market, which is where we think we can create some value. Now given the nature of shale reserves I described earlier, and with the right commercial structure, we're able to bring our low-cost of capital to bear on that Midstream business and that ultimately should help producers enhance their competitiveness for Northeast BC reserved development. Also the combination of our existing Alliance and NGL position, and our low-cost to capital, make us an attractive partner for those upstream players.

As you see by the bottom map there, there's a sizable opportunity set in the Midstream area. I can't comment too much on the status of potential investments in this area, but I can say that we are assessing a couple of opportunities, and we're optimistic about something coming forward in this area.

Now the ability to get into the Canadian Midstream business is really anchored by the experience we have in the U.S. GNP business through Enbridge Energy Partners. We're one of the largest gathering and treating processing players in Texas, handling about 15% of production. We're concentrated, as you can see on the map in 3 areas, the Granite Wash, the Barnett shale and the Bossier-Haynesville plays.

Once again, right atop a very significant shale growth plays. Right now, our priority though is to capitalize on the foothold we have in the Granite Wash. As you, know that's a very prolific liquids-rich play. Now I put the Haynesville actually here second to that only because it's a dry gas area but significant activity actually going on there right now.

Now closely related to this is our goal to expand from purely a gathering and processor business to NGL transportation, fee-based fractionation and storage. But let me spend just a minute now on the Granite Wash, which is mainly in the Texas Panhandle region. The Granite Wash is experiencing explosive growth. The blue bars that you see on the top right there show that growing number of rigs, which now stand at about 100 in this area, there are several things that make this play one of the most prolific in North America.

First, producers have a very good understanding through their history on the liquid-bearing zones in this region, and they've now used horizontal drilling in order to really bring out the reserves. Wells come with very high recoveries at 4 to 8 Bcf per well, and initial production rates between 4 to 20 million cubic feet a day, and sometimes beyond that.

Another factor in this area is that it has well developed infrastructure, in particular our Anadarko system. What really drives this play though, is in the NGL value of the gas stream. As illustrated here on the chart at the bottom right, a typical well yields about 2x the value of dry gas, plus, and this is often missed, this region is very rich in condensate. You could almost say that the gas part of the equation here is a bit of a bonus on top which really the target here, which is NGL and condensate. So you can see from that math why this area is so attractive to producers and to us. And the aerial extent of this play is just now being delineated, and there are other horizons being explored.

Finally, gathering and processing capacity in this region is very tight as is NGL takeaway capacity. So all of this provides a great opportunity for us to capitalize. Now we were very fortunate to recognize the uptick in that activity at a fairly early stage, we acquired the Elk City assets, which are shown there in blue, which includes gathering lines, treating facilities and processing plants. We got it at a fairly attractive EBITDA multiple, and more importantly though, it extended the reach into the Granite Wash that we already had.

But most attractive were really the synergies that we have with the Anadarko system, which is shown in red there. We quickly utilize the Elk City excess plant capacity to address a lot of the volumes that were coming at us in this region. On the Anadarko system, our system shown in red there, we move quickly to construct the Allison Gas Plant, 150 million cubic day -- million cubic feet per day plant, which is -- should be operational later this month. Last month, we announced a twin to Allison the Ajax Plant and that should be available beginning in 2013.

So we went forward with these 2 plants because we feel very strongly about the Anadarko. There are many years of development potential in these plays, some 10,000 locations to be drilled on our footprint alone.

Now as I alluded to earlier, growing NGL supply is leading to transportation bottlenecks and that always results in producer netback to clients. So to address that, we recently announced the Texas Express Pipeline, that's a new 20-inch line that will have initial capacity of 280,000 barrels a day and is going to run from Skellytown down into Mt. Belvieu. Our partners here, which we're very pleased to work with, are Enterprise and Anadarko. Including the gathering system, the total capital here will be about $1.1 billion, and will have a 35% interest in this project.

Volumes are going to converge at Skellytown, and you can tell that through the direction of the arrows there, that will happen through Enterprise's mid-American system from the Rockies, West Texas, and from Conway. So you got this convergence of volume coming from all of the prolific NGL plays.

In addition to that, we're going to collect volumes on the way down through the Granite Wash and the Barnett shale, all areas with substantial wet gas development. Now we have enough long-term commitments to proceed with the project so we're going to move forward. Strategically though, this project really checks a number of boxes for us. First, it provides long-term transportation for about 100,000 barrels per day of NGLs we actually control in the partnership.

We're leaving that Conway bottleneck that I referred to and having direct access to Mt. Belvieu is also going to improve our competitive position. And Mt. Belvieu access will boost customer netbacks and our NGL margin. But the same benefit will extend to our Aux Sable facility as a portion of the volumes that we generate out of Aux Sable are priced as of Conway. So we're leaving that bottleneck should improve the netback. We're also looking as I said, at extending the value chain to fee-based fractionation at Mount Belvieu, which will allow us at the end of the day to offer a fully bundled NGL service to our customers.

On the offshore business, as you know the Macondo incident resulted in more or less a complete shutdown of drilling. That really has hampered production throughout the Gulf. This has pressured short-term results but we remain bullish on the prospects for the businesses Pat alluded to. And that's really because the offshore is essentially an oil play today and for many years to come. We've seen increased activity over the last few months, drilling permits have been issued and we're seeing new discoveries announced. I'd say that the array of new permits and well starts is about half today than it was pre-Macondo, but it's starting to ramp up nicely. Now we've undertaken a review of where we are with this business given the Macondo incident, our plans are really to optimize the existing assets and then grow the business from here.

So we have 3 priorities, the first one is to improve the utilization of gas on the shelf infrastructure that we have. This will occur naturally of course, as volumes come back through increased drilling but we're also assessing consolidation of the onshore and offshore facilities where we can, and we have announced abandonment of a small pipeline, the UTOS pipeline that's on the Western side of the Gulf.

Part of this could also be to convert existing gas lines to oil. The second objective is to capture deep and ultra-deep water opportunities that are shown here by the ovals on the map. The key driver here is that offshore oil production will be increasingly important as far as U.S. supply. I think Steve referred to this with volumes reaching about 40% of the total by 2018 as you can see with the chart there.

Significant new infrastructure is required to support development of deep water plays and a great example of that is the recently announced Marcason [ph] development by Chevron. Chevron is very active and we see the need for at least 1 or 2 more major pipelines in that area, the second oval to the right starting from the left on the map there. We believe we can capture a good share of these opportunities as we are a good partner for the upstream constituents as evidenced by our Walker Ridge and Big Foot project.

Finally, as we are focused on executing our secured projects, these projects actually form the foundation of the new business model we are now applying to offshore projects. The model essentially is based on minimizing capital cost risk, throughput risk while retaining some upside if our volume targets are met. And under the model that we have now, the $800 million or so that we have, we're going to invest over the next little while, will generate a very strong and importantly, a very predictable earnings stream beginning in late 2013 early 2014.

Just a quick update on the status of these projects at Walker Ridge were laying about 190 miles of gas pipe from Jack Saint Mallow and Big Foot connecting to our Nautilus and Manta Ray systems. We're in the final stages of detailed engineering, and pipe, and lay vessel procurement. Construction will take place next year and we'll be ready for Chevron to begin its connection work about the second quarter of 2013, and the 20-inch Big Foot Oil line will follow the same timeline.

And finally, our onshore condensate handling facility expansion at Venice is in the detailed engineering phase, and we're projecting that to be in service Q3, 2013. So all in all, when you look at these 3 projects, we expect that they'll contribute in the order of $30 million once fully operational.

So that is a quick review of the gas transportation and processing side of the business. We will now take questions just before we go to break.

Robert Kwan - RBC Capital Markets, LLC, Research Division

Robert Kwan, RBC Capital Markets. Al, just a couple of questions on the Canadian Midstream. Last year, you talked about the likelihood that you would want to get involved on the Greenfield build side rather than acquisitions, is that still the case? And then secondly, just looking at the map you've pointed into kind of the Montney foreign region but there's also an arrow on the West Coast. Is there something that you're trying to indicate with that as well?

Al Monaco

Well on the Canadian mainstream side, call it on the upstream side, yes, I would say Robert that we're probably focused, probably 50-50. We prefer to be Greenfield as I said, last year but the reality is in that neck of the woods, producers tend to want to get things going and invest in the midstream on their own to start out to make sure that they've got the infrastructure in place and then monetize after that. So prefer to be in the greenfield side, the reality is a lot of the packages that we're seeing are for assets that are already underway or close to that. In terms of the West Coast, yes, if you look at the Alliance position and the Aux Sable position, if you look at the desire to get into the Canadian midstream in Northeast BC, a natural extension of that would be to look at NGL projects, LNG projects -- export projects rather, and we are in the process of discussions with potential producers on that side as well. So that is probably a little bit longer term than the initial foreign to Canadian midstream given where permitting is and some of the offtake discussions that still need to occur between producers and the demand side of the market. But we'd certainly be interested in LNG export as well. Right from the midstream part, the upstream area, midstream pipeline side right all the way to the LNG export facility itself.

Robert Kwan - RBC Capital Markets, LLC, Research Division

And just on that LNG front, is that something in terms of trying to put together a project that maybe isn't out there right now or is that potentially just buying into something that's in the approval process?

Al Monaco

There's a couple of projects out there being developed right now. Maybe all I should say at this point is that we're familiar with both of those opportunities and we'll be looking to put proposals together to see whether or not we can add some value to those projects.

Unknown Analyst -

Al, could you please reconcile your Slide 8 and Slide 22? Slide 8 shows decreases in gas flows from the offshore area, but Slide 22 speaks about increased utilization of the gas infrastructure.

Al Monaco

Maybe I'll just do it this way rather than go back to my book. Slide 8. Okay, so try that again [indiscernible].

Unknown Analyst -

Slide 8 shows decreases in gas flows from the offshore area. Slide 22 says increased utilization of gas infrastructure.

Al Monaco

Right, well I think this slide shows that you're going to see a reduction in gas from the offshore area. And that makes sense simply because of the issues that we described earlier around offshore Gulf coast. What we're talking about in Slide 22, which is -- okay, so increased utilization. I think I'm following you now. Essentially what we're talking about increased utilization is they're going to be a new oil projects in the Gulf coast that will go beyond 2015. So the initial picture that you saw there with the arrows is the gas flow picture out to 2015. The oil infrastructure projects that are going to occur in the offshore Gulf coast go beyond 2015 and will eventually lead to a resurgence of gas that is in trained with the oil.

Matthew Akman - Scotia Capital Inc., Research Division

Matthew Akman, Scotia Capital. My question is on Trans Canada and the mainline and how it relates to Enbridge. Enbridge is obviously both a customer of the mainline at the gas distribution and a competitor on Alliance and you shelled the toll on Alliance's and Vector's as advantageous to TransCanada today. I'm wondering what Enbridge's position is there's on the mainline with the filing and then what your expectation of outcome could be, and how that could affect Alliance over time?

Al Monaco

Well, I don't want to comment too much on TransCanada's lost application. First of all, as you know it needs to be amended. There's a lot of information that still needs to be part of that application. But at a very high level, really the cost of the TransCanada system haven't really changed. This is a matter of dividing out the cost differently to load it on to different volume picture as they are proposing. I don't feel we're in an any immediate panic as far as what we're doing on the Alliance system. As you saw, our toll is very competitive. Our cost structure is highly predictable on the Alliance system and the system is very cost effective. NGLs, as you know, will be a significant driver of our system going forward and potentially could be part of the equation going further down the road. And we have I think, demonstrated as I said earlier, an ability to re-contract Alliance with our work in the Bakken so far. So I think, you know, at the very high level, we feel we're in pretty good position. The toll aside from being cost-effect today will come down as we add more liquids to the system because of the nature of the system. And finally, I think we're in probably a pretty good position to offer a higher degree of toll certainty going forward on Alliance relative to what appears to be a much shorter term deal on the recent TransCanada proposal.

Matthew Akman

Follow-up question, one of the projects that, or potential projects, that seem to be absent from your presentation was gas pipeline to the West Coast. I'm wondering whether if there's work going on that at Enbridge vis-à-vis to the math LNG?

Al Monaco

I think I was may be referring to that a little bit earlier on with what we're planning to do in the Canadian midstream business and natural extension of that when you add on our ability to potentially work gas volumes into Alliance in the interim would be an advantage that we would hold, but certainly extending a midstream position with a long-haul pipe to the West Coast would be something we would be interested in. And we are looking at those opportunities right now.

Patrick Donald Daniel

Al, you might just comment on the synergies with Gateway on the LNG pipeline.

Al Monaco

Thanks, Pat. Certainly, with the work that's been done so far on right of way related to Gateway as far as design that will add some benefit to how we look at LNG export pipelines and how that's been part of discussion that's occurred so far with the producers we've been talking to. So that's a benefit as well. But I do think once again, given the timing of LNG exports, which we don't expect will occur before 2015, a significant part of what producers will be looking for is what happens in the interim and that's where having a long-haul pipeline that accesses the Chicago market will be a good advantage in terms of offering a long-term solution to the export LNG issue.

Okay, so we are at the break, 5 minutes. I've been directed by the front here to say that we have a 5-minute break, so we'll see you back in 5 minutes.

[Break]

Al Monaco

Okay, we have to get going again. So can I get everyone to take their seats, please. Okay, I'm going to spend the next few minutes discussing the green energy business followed by a brief snapshot of Energy Services and International.

And with all the opportunities in liquids and gas that Steve and I just went through, the questions why we're in this business, in the green business. To answer that, let me first say that there's no doubt that traditional forms of energy are going to continue to represent the major source of our energy supply and economic growth. In fact, Enbridge is going to be a big beneficiary of that growth outlook. At the same time though, it's pretty clear that we are transitioning to a lower carbon-intensive economy.

We think it makes good sense to establish a position in green energy now for the future, and importantly, to supplement all of the other growth we have already. Along those lines green energy is anchoring our goal to establish a new electricity platform. Pat talked about gas power generation and Richard will talk about transmission.

No w as you can see, we've been able to generate a meaningful earnings contribution from green energy over a short period of time. Importantly though, we've established an organization as well that is focused on operations and allows us to grow the business from here. Our green energy footprint has grown nicely over the last 2 years reaching about 900 megawatts at the end -- will be the end of 2011, with about $2 billion invested, we now have 7 wind projects and 3 solar projects.

Our business model is to invest in advanced stage projects, which significantly reduce development cost and risk. Projects are supported by long-term PPAs and another variable less important to us is access to transmission, not just for the initial project but for expansion.

And finally, we used top-tier turbines and solar technology. Three drivers behind the strategy, the first is that despite the recent economic downturn, strong supply and demand fundamentals for electricity remained intact. There's not much doubt out there about electricity demand and the fact that it will grow. As you can see from the top of the chart here, a disruption obviously in demand during the economic downturn but annual growth is expected to resume at about 1% to 2% annually.

Importantly, as you can tell from the chart, the mix of supply sources are going to change over the next 2 decades. Coal is still going to account for a big chunk of supply but it declines because of aging plants and stricter regulations. The vast majority of new supply will come from renewables and gas fire generation. Couple of points to note, we are not assuming that we get any sort of global or federal climate change initiative here. We'd all agree that's not on the table. The major emphasis is going to be state and provincial legislation. There's 33 states that have implemented renewable portfolio standards that requires them to add renewable generation and interestingly enough, that's been pretty sticky even through this downturn that we've seen.

Regarding renewable incentives, there's no doubt that we're experiencing a greater degree of public scrutiny on electricity prices. But I think we're ways away from where Europe is on this issue in terms of saturation of renewables and we have some room to run on that. Also our view is that the requirement for incentives is going to begin to decline for a couple of reasons. First, steadily improving technology. Secondly, developers and manufacturers and EPC service providers have done very well during this recent boom in green energy, and we think there's room for those premiums to come down to make renewables more competitive.

And the increased cost of fossil fuel regulation will narrow the gap between green and brown power pricing. This is an update of the green energy strategy, we're focused on the red regions shown here which provide a good combination of the wind resource, PPAs, legislative support and transmission.

We haven't changed that much since last time we were here but we have elevated Quebec and California. Now that we've established a good base as well, we're looking to expand existing sites where we know the infrastructure. We have access to transmission and we know the wind resources or solar resources and the communities.

A key objective has been to build a strong project pipeline. The table on the bottom left shows that we've been able to do that well, and that there are a number of projects that are possible over the next little while. In terms of gas fire generation, Pat alluded to this, we've looked at a number of opportunities. We've actually submitted final bids on 2 fairly large projects.

In the end, we weren't successful as we couldn't meet these seller's expectation on valuation, I guess, is the best way to put it. But in both cases, both projects were very strategic. But we're not about to make a bad investment just to launch that strategy. 2 of our target areas are Quebec and California. Quebec is ideal in that it's the second fastest growing market outside of Ontario with a target of 4,000 megawatts by 2015.

We also like Quebec's strategy to diversify generation to wind and expand their export capability. So they're looking to block up wind power and hydro in order to improve their export capability. We're also looking at California, which has a massive population base and growing demand for electricity. It also has very good wind and solar resources, and they've got 15,000 megawatts or so in the pipeline. And of course, there's broad government and public support for reducing emissions in the state. All of these gets reflected in very good PPAs. And they have the highest renewable portfolio standard of 33%.

Most importantly though, California offers sustainable growth for renewables because there's a narrower gap between green and brown power pricing than any other jurisdiction. So we are assessing projects in California but ultimately, the investment, as usual will depend on whether we can achieve our risk return objectives.

Just to give you a quick update on where we are on our projects, Tilbury and Amherstburg in Southwest Ontario were completed last month on budget and ahead of schedule. Including Sarnia now, which is the one shown in the photo, we now have a 100 megawatts of solar capacity. We're pleased with the operational performance, this usually gets asked, which is how are these things actually performing, and you can see in terms of availability and energy yield, we're actually ahead of where we thought.

Also shaping up to be a big year for our wind business by the end of the year will have brought in 3 projects at just over $1 billion in capital. The Talbot project to 99 megawatts located on the north shore of Lake Erie that was completed on schedule earlier in the year. Greenwich, which is a look-alike project, will be completed in the next few weeks.

We're most proud of the Cedar Point project, 250 megawatts located just east of Denver. We officially opened up Cedar Point a couple of weeks ago. The wind was blowing hard and we're very much looking forward to that project came in ahead of schedule and below budget.

Let me now switch gears to energy services. Now we haven't talked about this one before. We've had the energy services group in place for about 10 years and it's more or less focused on the oil side of the business, although we do have some gas operations as well. Over this period, we've been able to build very strong relationships with customers particularly on the refinery side of that equation.

The business is essentially focus on 2 things. The first is to maximize the utilization of our pipelines and terminals. We do that by marketing capacity or nominating capacity on our systems when it makes sense to do that, which generates margins and importantly, it pulls volume through the system and if you go back to what Steve said about the CTS structure we have in place right now, that will be an important factor going forward.

Second, we built up some very good knowledge of crude oil infrastructure in North America and that allows us to capitalize on low risk physical arbitrage opportunities that are associated with our core business. For example, we utilized storage tanks to capture [indiscernible] and the oil market when it's there. We also used storage to blend different grades of crude to create higher value products, and we've seen a very strong interest lately in the crude supply business, which is a fee-based source, a fee-based business that sources feedstock for refineries. And of course, location arbitrage, which is driven by pricing differentials at different pricing points.

So those opportunities involved entering into physical buy-sell transactions at the same time, which means that we essentially lock in a margin without taking price exposure. You can see that we've generated positive earnings in the last few years. Earnings were up in 2009 due to strong storage premiums. This year, we've really benefited from the WTI-Brent differential by moving oil into higher priced markets. And a wide light heavy differential has helped too, in that it's created a lot of blending opportunities for us.

That's a quick snapshot on energy services. Moving now to international. Over the last year we've really been focused on ramping up our inventory of possible projects to work on. We've had a good set of prospects here that we can now go forward on. We're taking a targeted approach to this and focus on projects where we can actually bring something to the table rather than trying to be all over the place.

So for us, that means we're good at project development, we're good at executing projects from a construction point of view and our operational experience. So that's where we're focused on. We're looking at pipeline and terminal-ing opportunities in regions that have strong supply-demand fundamentals and a good climate. Of particular interest is Australia. The investment climate there, I like to characterize as very Canada-like, and the gas supply outlook is strong as you can see from the chart there.

Australia, I would say, is doing a fantastic job of monetizing their unconventional reserves through LNG exports and of course, Asia, which is a target there, represents an excellent market outlet. So when you put all that together, there's some very good midstream opportunities there for us to attack.

The other prime target is Colombia. We talked about this a little bit earlier. Through our investment in OCENSA we've been involved there since 1995. So we're very familiar with how business is done and what we need to focus on. A number of factors are contributing to, I'd say, an absolute bloom in exploration and development opportunity that's in Colombia. Good business environments, much improved from years gone by. Strong GDP growth, low inflation, and I would say the biggest factor is a very supportive regulatory and royalty structure.

[Audio Gap]

Unknown Analyst -

I'd like to know the future for price of natural gas. Where's it going?

Al Monaco

The question was gas prices and where are they going. My view is that there is so much supply out there that we're really in that $5 to $7 zone. And as I said in my earlier discussion, the responsiveness of drilling to prices is almost immediate. People drill very quickly these days. Very large gas projects can be brought to bear very quickly, so I think that basically keeps the price down. I actually think that's very positive for the gas business in that, as I said earlier, the concern for gas, including the implication to NGVs, has always been a little bit suspect because people were concerned about the volatility of gas prices. I think the reserve base is so large now and it's so predictable that I think gas is very well positioned to be in a stable range of $5 to $7 at least over the next 5 years or so.

Yes?

Maria Berlettano

Maria Berlettano, J. Zechner Associates. My question has to do with operational safety and integrity and emergency response. What has been the year-over-year change in the spend in that area? How much in capital resources are you allocating? And also in relation to that, given the intensity and severity of the types of natural disasters that we've seen, how is the whole insurance market -- availability of insurance coverage for those types of emergencies?

Al Monaco

So I will hit the first question. In terms of our capital spend and operating spend, actually on the integrity side in the gas business, we're currently at about $18 million per year. That's related mostly to the gas processing business in the U.S. We're going to increase that to about $24 million in 2012. So I guess that's about 1/3 over last years' spend. On the insurance side, Richard, do you want to address that? Richard's close to that area, so we'll let him speak about it.

J. Richard Bird

So the insurance market has been tight over the last year with a number of big claims around the world. We're currently carrying $575 million of third-party liability insurance. That compares to the $650 million that we were carrying beyond that. So we have had to scale the insurance program back. We'll continue to monitor that market and look to be getting back up to that $650 million level as soon as we can economically place that level of insurance.

Al Monaco

Any other questions? Okay.

D. Guy Jarvis

Well, good morning, everyone. It's been good to come out last night and this morning, and see a bunch of you again and joke about how I'm the only Investor Relations guy that never had to manage Enbridge Day, so that's quite an accomplishment for myself. But I'm really excited to be here to talk to you today and represent our 19,000 gas distribution employees to give you an overview of what we see forthcoming in our business in the next few years. Pat mentioned, when he was speaking, that we know a lot of you are customers and, interestingly, in my Investor Relations days, I was contacted by a number of you about individual natural gas service matters, which we were able, through Janet's leadership at the time, to deal with. So I know you are customers, and I hope what I've got to say to you today interest you not only from an investor perspective but from a customer perspective as well.

So to follow on Al's theme about personality and/or lack thereof in natural gas, natural gas does have a personality, and at the Gas Distribution level, it has 2 million of them. So we have a very active and growing retail organization here on the end of Enbridge Gas Distribution, St. Lawrence Gas, Enbridge Gas New Brunswick. In 2010, that business contributed about 16% of the overall earnings for Enbridge. And as the slide is showing on the upper left, while customers additions haven't quite found their way back to the levels that we were seeing prior to the financial crisis, they have stabilized in that 35,000 range annually. We're still quite pleased with this. And within Enbridge Gas Distribution itself, we are expecting next year to welcome our 2 millionth customer in Ontario, which will be quite a milestone for the utility.

Despite that customer growth, you can see that the send out over our system in that period has not really been growing. And that's a real reflection of newer homes coming on, better efficiency, as well as some of the demand side efforts that we at Enbridge Gas Distribution are promoting ourselves. While that on the surface doesn't seem like a growth story, it does hide the fact that we are growing, and we do have a growing peak day requirement that is going to require us to look at some additional system investment.

So growth on our system -- and not only the growth but the density of the growth in the downtown Toronto area is leading us to look at a project to reinforce our system, both to introduce more sources of high-pressure natural gas across the system, but also to provide us with more reliability and redundancy in the event of some form of an event either on our system or upstream of our system that forces us to reroute our gas. We're looking to make sure that we have enough flexibility to handle a number of circumstances without disrupting our service. As the slide indicates, this project is likely to range in the $300 million to $500 million range to address these distribution system needs. We will have to seek approval of the Ontario Energy Board for this project, and it's going to come into service in a number of phases, probably starting in 2014 through the 2015 timeframe. While the need and the rationale for this project is solely a distribution need, a secondary feature of what we're looking at in terms of designing the scope is to ensure that we have access to multiple upstream supply sources. We're trying to take care of the reliability on the system and part of keeping the reliability on the system is to make sure we've got reliability upstream in the system as well.

Speaking to system integrity and safety, the reinforcement project will go a long way to dealing with the reliability issues that we're facing with the growing system. But the integrity of our assets and the safety of our employees, contractors, customers and the public, pardon me, is our top priority. We're committed to fostering the 0 incident culture within the organization and following on the board's mandate for Gas Distribution to be a leader in this area.

On the integrity side, throughout 2011, we've begun our first program to run inline inspection tools on our transmission-like parts of the system. We're aggressively tackling this need to establish a baseline for the health of our entire system by the end of 2012. Currently, some of our system we are unable to run inline inspection tools in, and we are also undertaking an effort to ensure that 100% of this high-pressure part of our system can be inspected by inline tools. We expect to have that work done and those tools run by the end of next year.

As part of that process, we're going to gain some near-term benefits from the integrity side because oftentimes when we're retrofitting some of the system to enable it to accept an inline inspection tool, we're doing work on that system that is -- actually making repairs on repairs that were done historically. So as we're setting the stage for these tools to be run, the system itself is already getting better.

Now the high-pressure parts of our system, if you looked at the percentage of our system that, that represents, it's going to be a small part. So the biggest part of our system in terms of our pipe is lower pressure distribution system. We're also very actively looking at new technologies that might help us get a better read on the health of the system. There's new technologies emerging in terms of inline inspection tools that might be able to change their size and therefore be able to move through certain valves in our system that the current technology wouldn't allow it to occur. So it's aways away, but we're very aggressively pursuing it.

On the safety side of things, just in the last couple of weeks, we officially broke ground on a $40 million training and technology center up in Markham, Ontario. Key feature of this facility is that we're actually constructing in the backyard, if you want, of this facility a streetscape. That streetscape is going to have built-to-scale residential, commercial customer applications. It's going to have many of the street features that our staff would have to deal with in terms of piping and metering and whatnot. So it's really going to allow us, in a live setting, to take our people in and train them in terms of what they're going to face when they're out on the streets of Toronto. Our initial focus is going to be our employees, but over time, we also expect to begin offering some training opportunities to the regional first responders in that setting as well.

Finally, on this topic, we're very active in terms of trying to address issues of third-party damage. So we're a driving force behind the Ontario Regional Common Ground Alliance, which is advocating for legislation in the province for a mandatory one-call number. There have been a lot of progress made on this prior to the call of the election. We've been active throughout the election, making sure that our voice is heard in terms of the candidates that are running. And we certainly hope that after the election it's something that's going to gain steam once again.

So 2012, as many of you know, is going to be the final year of our current incentive regulation settlement. As this slide indicates, earnings in excess of the allowed return have lead to upside in the range of 225 basis points being realized in the latter stages of the agreement. On the flipside of this, our customers are forecast to realize about $75 million of earnings sharing over that same 5-year period. In a minute, I'm going to talk about the steps that we hope that will lead us to a new incentive regulation model, but before I do, I wanted to highlight that with the OEB's decision in early 2010, a new formula and higher starting point return on equity will be the foundation of our new plan.

I've mapped out here a series of regulatory filings that we'll be executing in the next 12 to 15 months. So first at the top, we've already filed our 2012 rates per the current incentive regulation settlement, and we expect approval prior to January 1. There are a few items that we need to deal with in this application, but for the most part, it's a straightforward mathematical exercise based off of the incentive arrangement. And for our customers in the audience, that represents about a 2.5% increase in rates for 2012.

By year end, our current incentive regulation settlement requires that we have submitted our rebasing cost of service for 2013. As the term applies -- implies, this application will see the bulk of the benefits that were realized by Enbridge Gas Distribution and our customers through incentive regulation, become the foundation cost-of-service upon which a new incentive regulation methodology is expected to be developed. About this time next year, we expect to file our next-generation investor relations plan for the 2014 through 2018 timeframe. As you can imagine, we're evaluating a number of different approaches at this time and may not have fully selected our direction until we see how the rate -- the rebasing filing plays out. We've had some early customer discussions in terms of the likes and dislikes of the current model and what customers might like to see in the future. There's not a lot of preference being expressed. The only consistent feedback we get is that they do like the alignment that our earnings sharing mechanism creates, which was a bit of a contentious issue, actually, at the early days of our current settlement. Customers clearly are less focused on what's the model look like, more focused on what does it mean for rates and the expectation for increases going forward.

Moving on to this financial outlook. The stable expectations that we have for customer growth related to new capital is the foundation of the expected $1 billion of secured investment over the next 5 years, while the system reinforcement project that I have spoken about is conservatively risked at this time in this chart.

While not included here, it is also worth noting that we do have a significant amount of ongoing annual maintenance capital related to asset relocations, reinforcements and integrity. On the earnings side of things, we expect to continue to contribute to the overall growth rate of the company but not at a comparable rate to some of the other business units. Based on our current long-range plan through 2015, Gas Distribution will represent roughly 12% of Enbridge's overall earnings by the end of that period.

So in terms of our key takeaways, we continue to experience solid growth across our customer base. We have a very significant and exciting project to reinforce the system. Our next-generation incentive regulation model will be underpinned by a stronger allowed return, and we're committed to establishing an industry-leading position in the areas of safety, system integrity and leak detection. And with that wrap-up, I'll be happy to address any questions.

Andrew M. Kuske - Crédit Suisse AG, Research Division

Andrew Kuske, Crédit Suisse. Guy, what's your outlook for new natural gas-fired bills within the GTA because obviously that would have a significant impact to rate-based bills.

D. Guy Jarvis

Right. I think, as Al mentioned, we believe in Enbridge that there is a large opportunity for new natural gas-fired generation, not only in the Ontario mix but elsewhere in North America. The current plan in Ontario is really relying on natural gas generation, largely from a peaking perspective. It's going to have to -- time will tell whether the plan of a large renewable portfolio, offset by the peaking, is going to be the right mix or not, but certainly, we believe there's a bigger role that it can play.

Robert Kwan - RBC Capital Markets, LLC, Research Division

Robert Kwan, RBC. Guy, you had mentioned something about upstream reliability. Can you talk a little bit about that? Is that a plan to try to bypass the mainline to some of the import points or is there something different you're looking at?

D. Guy Jarvis

No, this -- and again this is a distribution system reinforcement project. There is no design or intention for this to be a bypass. We're going to be looking at being able to accept gas from multiple points, which is not, in my view, a bypass.

Unknown Analyst -

I guess this is a follow-up to that. I realize EGD is not intending to bypass any systems. What about -- do you view there being any risk of large industrials or other players bypassing EGD system at all?

D. Guy Jarvis

I'm not aware of any at this time. Anybody that would be in the situation where they could economically do that and bypass our system, I'm not aware.

J. Richard Bird

Good morning. For this last section before Pat wraps up the morning, I'll pool together the financial dimensions of the plans and prospects you've just heard about. Before that, I'll touch briefly on a few aspects of the corporate act initiatives that supplement our business unit activities.

Enbridge's indirect investment in Gaz Metro, the gas distribution utility for Québec, which is held through Noverco, contributed $21 million to Enbridge's earnings in 2010. This is a stable source of earnings with good growth prospects as well. Natural gas does enjoy a significant cost advantage over competing residential, commercial and industrial heating alternatives, supporting steady organic growth within the Gas Distribution segment. Gaz Metro is also well positioned to participate in Québec and Vermont's wind power development objectives, and it will see near-term earnings accretion from its acquisition of the Central Vermont Power System. Gaz Metro is in a unique position to capture value from combining Central Vermont with Green Mountain Power, the other major power utility in Vermont, which Gaz Metro already owns. Gaz Metro is a limited partnership, owned 29% by Valener, a public company and the other 71% by Noverco. Earlier this year, GDF SUEZ sold its 18% interest in Noverco to Enbridge and the Trencap Group, which is led by the Caisse, thereby simplifying the ownership structure and providing an opportunity to recapitalize Noverco and enhance its tax effectiveness.

The larger interest that we now have in the increased tax efficiency will enhance Enbridge's earnings from this business.

As indicated in the diagram, Enbridge holds its interest in Noverco, primarily in the form of high-yield preferred shares. While Trencap holds theirs primarily in the form of subordinate debentures. This results in a highly tax effective structure and therefore, an advantageous cost of capital for Enbridge's investment in Gaz Metro or any other infrastructure assets, which either Enbridge or the Caisse may choose to hold through Noverco.

Last year at Enbridge Days, we indicated an intent to develop a new electric power-based growth platform revolving around renewable power, gas-fired power generation and power transmission, as Pat has already touched on, and Al has updated you on the status of our renewables and gas-fired power initiatives. For the time being, our power transmission initiative is being undertaken through our Corporate Development Group.

Power transmission represents an attractive opportunity for Enbridge. The industry fundamentals are strong, with electric power being an energy commodity, which is still enjoying continued growth in demand in our mature North American economy, and with significant additional transmission infrastructure required in both Canada and the U.S. to support this growth, replace aging facilities, overcome grid bottlenecks and move power from remotely located renewable sources to central markets. The commercial models regulatory processes and permitting and land-use aspects are similar to our Crude Oil and Natural Gas Pipeline businesses. For the last year, we've been examining different possible entry points, discarding some and continuing to explore others. The acquisition of the Montana-Alberta tie line project is a good entry point for us. It's manageable in size. It has great fundamentals in terms of the Montana to Alberta power price differential. It's fully contracted, and it has low-cost expansion potential. We plan to build on this initial base to continue to penetrate the power transmission sector.

The last corporate development area I'll touch on is our alternative and emerging technology initiative. And this is not something that is intended to drive earnings per share in the next few years. It's intended to explore potentially significant new technologies that may shape the energy future, to encourage those which appear to have promise, and position Enbridge to participate in and benefit from such technologies. We run it like a small sector-focused venture capital fund. I'm not going to cover the entire portfolio, but I'll give you snapshots of 4 of our current initiatives.

The upper-left picture is a drilling rig, but it's not drilling for oil or gas. It is drilling for geothermally superheated high-pressure water. We currently have a 20% interest in the Neal Hot Springs Geothermal project being undertaken by U.S. Geothermal. Among the renewable energy alternatives, there's a lot to like about geothermal.

Unlike wind and solar, it's a constant ratable source of power, with a capacity factor of about 90%, so more attractive and economic from a grid stability perspective. The Power Purchase Agreement for Neal Hot Springs is at $96 per megawatt hour, just as an indication of that.

Moving to the picture on the upper right. What you see is a 1/2 megawatt, very low head, run-of-the-river hydro unit, like the 3 that are being installed at Wasdell Falls, Ontario, by our joint venture with Coastal Hydropower, which holds the franchise rights for this technology in all of Canada and much of the U.S. The VLH hydro technology is a nondisruptive power technology, which requires a drop of only a couple of meters and is designed to be installed on existing water-controlled weirs and dams, typically adjacent to existing grid infrastructure. Capacity factors typically exceed 90%. There is a total potential generation resource of 100,000 megawatts from low head sources across North America.

We're also investigating the potential that new technologies may have to improve our ability to detect very small hydrocarbon leaks. For example, as depicted on the lower left, we are currently evaluating the effectiveness of a helicopter or light plane sensor package that analyzes the unique reflection signature created when sunlight interacts with specific types of hydrocarbons. This technology was originally developed by the space program to enable satellites and probes to perform atmospheric analysis. Potentially, this technology can be modified so that patrol aircraft can provide early detection of gradual oil leaks that may not be visible to the naked eye.

Another potential high-value technology we are investigating is unconventional energy storage. And the picture at the bottom right shows a hydrolysis unit, which is designed to convert time-of-day surplus electric power into hydrogen, which can be stored and then subsequently run through a gas turbine to produce green power during peak load conditions. The key to increasing the proportion of the power generation mix from renewables is to be able to smooth out their nonratable production profile with economic storage.

As I said, none of these technologies will necessarily drive Enbridge's earnings per share within the next 5 years, but they and others we are exploring may shape the future of our energy economy over a longer timeframe.

I'll move on now to a financial overview of the future for Enbridge. And you won't be surprised based on what you heard from our business units that our investment opportunities are deeper and broader than ever. The fundamentals driving our traditional businesses are strong, while at the same time, we are seeing opportunities to extend our business model to new platforms within the energy infrastructure sector.

On the chart, the bars represent the total opportunity set currently under development in each business area in aggregate, as Pat mentioned, to begin with $48 billion of identified opportunities.

We believe that each of these opportunities has the potential to generate attractive returns with manageable risks, consistent with our existing asset base. Some of these opportunities won't materialize. Some won't meet our financial and risk management criteria. Some will be taken by competitors and some will not fall in the immediate next 5 years. The green segments at the bottom are those that have already made the cut and will be in service by 2015, about $8 billion in total as we stand today.

The next segment up, in gray, represents capital investment opportunities not yet secured, but which we assume for planning purposes, that we will be successful and putting in place by 2015. That's another $12 billion enterprise-wide. And based on progress so far this year, I would say our success rate assumptions are beginning to appear increasingly conservative.

To support our investment and growth plans, we continue to place a very high priority on strength and flexibility, ensuring we have access to capital when we need it and at the lowest possible cost. A key ingredient of this is maintenance of the strong investment grade credit ratings of each of our 5 issuers. Our funding plans for our growth investments are designed to achieve this objective.

A second critical ingredient in our financial strength and flexibility recipe is maintenance of substantial liquidity. This enables us to withstand periods of capital market instability and choose our timing to access capital at favorable rates. At present, we are carrying enterprise-wide committed facilities and cash balances aggregating over $9 billion, of which $6 billion is currently unutilized and available to temporarily fund new investment. This reflects credit facility additions totaling $1.8 billion undertaken in the last few months to further reinforce this liquidity reserve.

This next chart is similar to the format that we've used in the past to depict our funding plans. It focuses on Enbridge Inc., exclusive of the Sponsored Investments as it has in the past. However, I've included here both the secured growth capital and the risk growth capital, which is a change in the framework relative to the way we've looked at this chart in the past. So combining those sources of those growth capital amounts together with maintenance capital, we are looking at a total of just $18 billion through 2015. Of this, we can fund about $8 billion of it internally, leaving a little over $9 billion to be funded through capital markets. The reason for the range on the chart is different potential dividend payout policies, which could be adopted ranging from our current policy of 60% to 70% of earnings to a higher payout policy reflecting the stronger cash flow expected during this period. And I'll come back to this in a few minutes.

The debt funding side on the left is pretty straightforward with a remaining requirement of $9 billion, which is well within the issuance capacity of the 3 issuers, including the flexibility that we do have to access the U.S. market. The equity requirement of a little less than $2 billion reflects our objective of maintaining our investment grade ratings, as I mentioned earlier. As you can see, based on the equity to be sourced from our renewables drop-down to Enbridge Income Fund, plus our recent preferred share issuance and our dividend reinvestment program, we would actually have a modest surplus of investment capacity based on this plan. This surplus is available to support a higher securement success rate than the conservative level that we are currently assuming. In the event that we secure even more opportunities than this surplus would support, the supplementary equity sources we would first look to are additional asset monetizations as well as additional rate reset preferred shares.

As most of you would know, we hold a significant portion of our asset base in our sponsored vehicles through which we operate and control the assets while sourcing the capital required to fund these assets from low-cost capital market niches. The low cost of capital provided by these vehicles is a significant contributor to Enbridge's overall financial effectiveness and growth. And this chart depicts the earnings contribution growth rates of both Enbridge Energy Partners and Enbridge Income Fund. In both cases, Enbridge receives a disproportionate share of the earnings growth from these vehicles as a result of the operator incentive mechanism, which each has. As a result, we will see a healthy growth in the contribution from these vehicles with minimal capital injections by Enbridge. This growth contribution is reflected in the business unit earnings growth perspectives you've already seen, those charts that Steve and Al are so fond of.

And this chart depicts the evolution of the mix of earnings being contributed by each of our business units over the 2010 to 2015 period. Although we expect the contribution of each one to grow, the growth rates differ enough to produce a slight shift in mix over the 5 years, but not a terribly large amount. The contribution from the new platforms grows fastest of all, but still only represents 70% -- pardon me, still only represents 7% of the total by 2015. This may not seem like much, but the new platform strategy has a significantly longer horizon than 5 years.

As Pat has already confirmed, we are quite confident that we will be able to achieve a 10% average annual growth rate in earnings per share through 2015 based on conservative mainline volume assumptions and conservative investment opportunities securement assumptions. For now, we are not going to commit to how far into the second half of the decade we think we can maintain that 10% growth rate, other than to point out that the greatest benefit of our mainline CTS agreement will fall in that second 5-year period.

This brings us to a topic which I know is of interest to most of you, and that's dividend growth. As you can see from the chart, Enbridge has a long track record of very strong growth in dividends. The chart also depicts a range of potential growth rates for the 2010 to 2015 period, depending on payout policy. The bottom end of that range would correspond to a holding payout at the midpoint of the current 60% to 70% policy range. In which case, dividend growth would parallel earnings growth, and the top end illustrates what the growth rate would look like based on a more generous payout rate reflecting higher cash flow growth.

We will continue to monitor investor feedback and market valuation data as we formulate our dividend policy for recommendation to our board.

So that completes the perspectives that I wanted to cover for you this morning. And so I'll just quickly summarize the main points that I hope you've absorbed.

The first is the remarkable array of attractive investment opportunities, which Enbridge has before us. We also have ample financial capability to undertake the opportunities we expect to be successful in securing and more, and with an advantageous cost of sourcing the required capital. The resulting earnings growth will be unmatched in both velocity and reliability, and the dividend growth could be even stronger than that. Pooling all that together, we continue to see lots of further room to run on our share price. Thank you, and I'll take your questions now.

Maria Berlettano

It's Maria Berlettano, J. Zechner Associates. I have a follow-on question regarding insurance coverage. And my question is, given the size of your organization and the diversity of your portfolio of assets, how have you arrived at that target level of insurance as being adequate? That's the first question. My second question relates to liquidity. Could you give us a sense for the diversity within the liquidity pool among the European financial institutions, U.S. financial institutions, Canadian financial institutions and what you see potentially as at risk of falling away given the crisis -- the financial crisis that we see?

J. Richard Bird

Okay. So in terms of the magnitude of the insurance program, that's an annual exercise that we would go through looking at the magnitude of the asset base that we're ensuring, its exposure to both property laws and public liability exposure. I can't say that there isn't a fair amount of judgment involved in that and certainly the 400-year storm that we experienced in 2010 wasn't something that we would have expected and has caused us to rethink the magnitude of the exposure. So that's something we will do on an annual basis. As I said, we're at $575 million of liability coverage -- third party liability coverage at the moment, which is down from $650 million. We'd like to get it back up to at least the $650 million level and probably a little larger as the market is prepared to extend that kind of coverage to us.

And with respect to the liquidity side, it is a large group of banks. I think we are 23 or 24 in total. We would have representation, certainly, from some European banks, U.S. banks. The Canadian banks, of course, would be a mainstay of our facilities. We also have some Asian banks involved as well. I'm not anticipating that any of that is going to drop away, but certainly, there is enough room in that liquidity cushion to absorb some loss of facilities if we saw some of our lenders unable to meet their commitments.

Okay, we got a couple of different -- why don't you go ahead?

Stephen Dafoe

Steve Dafoe, Scotia Capital. Richard, earlier today, Steve Wuori declined to tell us the volume sensitivities on the CTS, which is kind of understandable. But when the CTS was first announced, it was a very big deal for the rating agencies, and the maintenance of low business risk remains important for the volume investor. So how do you reconcile the maintenance of low business risk with abandoning the comforts of cost-of-service regulation on your biggest asset?

J. Richard Bird

Okay. Well, I think the key point there is the off-ramp that's built into the CTS. And when we did announce it, I think we indicated that were we to penetrate that volume off ramp or at least to approach it, we would then go back and renegotiate that agreement, and the default case would be cost of service. So I think under cost of service, that's still reasonably attractive returns, but not the premium returns that we would expect to be able to earn under the CTS. That's the main risk underpinning. And certainly from a lender's point of view, from a credit rating point of view, I think that's a very safe position to be in. Just with respect to the volume sensitivity on the CTS, we're not unmindful of the fact that analysts are all trying to divine what our performance is going to be out into the future on CTS. And we are working on some rules of thumb that we will be able to give you. We're just not in a position to give them to you just yet, trying to figure out how to translate what's now a fairly complex cash register, which does depend on the specific types of liquid hydrocarbons that are shipped and the point-to-point destinations of those hydrocarbons. We're trying to translate that into a few simple rules of thumb that we will provide. And I anticipate we will be able to provide them on our third quarter reporting cycle. So not quite yet, but we'll soon be able to provide that information to you all.

Winfried Fruehauf - Fruehauf consulting

Winfried Fruehauf, W. Fruehauf Consulting Limited. Pat's Slide 8 shows secured growth and risk growth capital of $20 billion. Yours shows $14.5 billion. Assuming the difference is sponsored investments and assuming the number total is $20 billion instead of $14.5 billion, what would the debt-to-equity requirements be? And what would your debt equity ratio be like at the end of 2015?

J. Richard Bird

Okay. Well, I think you've correctly reconciled the difference between the $20 billion, which is enterprise-wide, and the $14 billion or $15 billion, which is within Enbridge Inc., excluding the Sponsored Investments that's primarily due to growth that's occurring in those Sponsored Investments. The capital -- and if I got the question correctly, the capital structure that we had anticipated at the end of the period is consistent with the capital structure that we have today. So I don't anticipate any change in the capital structure, either of Enbridge or any of the sponsored vehicles.

Winfried Fruehauf - Fruehauf consulting

The other part of the question was, what are the debt and equity requirements corresponding to the $20 billion instead of $14.5 billion?

J. Richard Bird

Okay. So because both of the Sponsored Investments are high payouts vehicles that pay out virtually all their cash flow, they will need to fund significant amount of their growth through the issuance of additional equity. So I guess you could do that math, there's a fair bit of equity that each of them would need to be issuing over that period of time.

Matthew Akman - Scotia Capital Inc., Research Division

Richard, Matthew Akman, Scotia Capital. And my question is on how you can take advantage of the preference in the market for high dividend payouts and for income, and in particular, the balance between using Enbridge and this payout ratio versus the high income side cars, Enbridge Income Fund and Enbridge Energy Partners. Lately, I've seen that the decisions taken by Enbridge is that it's more advantageous to get that leverage through maybe the side car vehicles like Enbridge Income Fund with the transference of -- transfer of assets into it. But how do you think about, I guess, the pros and cons of getting that lower cost of capital by increasing Enbridge's payout ratio versus using, say, Enbridge Income Fund or Enbridge Energy Partners to achieve higher growth rates at Enbridge throughout the monetization?

J. Richard Bird

Okay, well, that's a very Matthew Akman-like question. But you're right, we do -- that's an area of financial management and financial strategy that we think about a lot. And we do have both levers, which is taking advantage of that high income orientation yield preference by shifting our asset mix towards our Sponsored Investments, and we are doing that to some degree. And this latest drop-down of the renewables, $1.2 billion worth of renewables assets into Enbridge Income Fund is part of that strategy and part of proving out that strategy, so to speak, and part of building up the capacity of the Income Fund to be able to play that kind of role in the future potentially in a bigger way.

At the same time, we're not entirely convinced that this high valuation being attached to high income payout is a long-term capital market feature as opposed to a period that we're going through. So when we look at Enbridge Inc.'s dividend policy, that's certainly one of the factors that we're looking at is the very high valuation that's attached to higher dividend payouts than lower dividend payouts. And it's one of the things that we've taken advantage -- into consideration as we look to secure the most advantageous cost of capital to move forward

Unknown Analyst -

This is a follow-up, I guess, to kind of Win's and Matthew's question. Maybe another way of looking at it is, in a high valuation environment for high payout vehicles, we could see potentially Enbridge's ownership of these sponsored funds declining. But if the capital markets get tough, the nice benefit to having an affiliate parent is if you could back off any sort of equity financing needs. So how can you help us think of what the book ends might be of a possible range of ownership levels by Enbridge of these funds?

J. Richard Bird

So I think you're right in the current environment that we're in. And as Matthew also indicated, the greatest value seems to be in taking advantage of the sponsored vehicles to find as much capital as they can absorb. And that would mean that Enbridge wouldn't participate or would participate to the minimum that it could in the equity that's being raised by those vehicles and our percentage interest would drop down. In terms of the book ends, I think, generally we've said we want to be in the 15 percentage area as a minimum. There was a time on the Enbridge Energy Partners master limited partnership where we're actually down a bit below that. I think we bottomed out at about 12%, if I recall. We're back up in the mid 20s now. And we've always said on the income fund that we would be quite comfortable to be down in the 15% to 20% rate. So the book end is somewhere probably in that 15% territory.

Unknown Analyst -

And the max? 100%?

J. Richard Bird

And the max. No, I don't think there is a max. I mean directionally, we would prefer to be going down than up. The max would be -- we would -- if we were back into a world, which I guess was part of your question, where those capital programs required additional investment by Enbridge to support them, we would undertake that additional investment. Our preference would be not to, but generally speaking, they are attractive projects, whether they're financed on either balance sheet. And so rather than see them go wanting for funding, Enbridge would put additional equity and if required to.

Unknown Analyst -

A follow-up question on the committed facilities. Could you remind us of what the commitment period is on those facilities and how much flexibility you have around that? And in the context of the level of available capacity and the secured growth projects that you have, how much flexibility on those secured growth projects do you have in terms of timing in flowing those down?

J. Richard Bird

Okay. So in terms of the term of the commitments, we have a mixture of difference facilities. We have -- that one end of the spectrum would be a 5-year facility, a fairly significant 5-year facility, which is in that mix. And at the other end of the spectrum would be 364-day facilities with a one-year term out, which is effectively a 2-year facility. And with respect to flexibility on timing, generally, once a project is secured, there's not a lot of flexibility on timing. The way our business works is typically our shippers hold off until the last moment till they're sure that they really want something. And once they want it, they want it really bad. And we're under pressure to get it in place pretty quickly. So there's not a lot of flexibility and timing or delaying expenditures with respect to capital that's already secured, and hence the reason for that big $6 billion liquidity buffer, which is to give us lots of ability to fund those projects, while waiting the right windows for capital market funding. And yes?

Andrew M. Kuske - Crédit Suisse AG, Research Division

Andrew Kuske from Credit Suisse. Richard, just on the last point on your slides, substantial share price upside, I guess, I'll put it this way, what do you think the street is missing within the value of the shares today? And then what get the shares to a higher level in your view?

J. Richard Bird

We often ask ourselves what the street is missing, so I'm not sure what the street is missing. So we do our best to tell you the story. I guess I've seen some analytics that would be consistent with our view of where the share price is, but the street obviously isn't all the way there yet. But maybe after today, we'll start moving in that direction. What do you think? Any other questions? Okay, I'll turn it back over to Pat.

Patrick Donald Daniel

Okay. Thanks, Richard, and I would just like to do a 2 or 3-minute wrap-up. I know we've got lunch available, and hopefully, most of you are going to be able to join us for lunch. You don't want to look at your screens. And it's not a beautiful day out there in the market, so sit back and enjoy and have some lunch with us.

About 11 years ago, I stood in front of you as a rookie CEO with Enbridge, confident that I could tell you a story of 8% to 10% growth going forward over the next 5 years. Today, 11 years later, on the base a little more than twice the size of the base that we had back 11 years ago, I can stand in front of you and say that I am very confident of 10-plus percent growth over the next 5 years. It's been a remarkable story. The growth that we have today is even more transparent than it was back 11 years ago, and we are very pleased, particularly with the transparency around that growth. And there are 7 reasons that I've jotted down as to why my level of confidence has gone up even more over the years, and I'll just very quickly run through these.

First of all, it's the diversity of opportunity in front of us. It's not just the Crude Oil Pipeline business. It's not just the Gas Pipeline business. It's not just the Distribution business. In addition, it's Renewables, its International, it's some of the new opportunities that Richard has talked about. So we're working off a much broader base than we were 11 years ago. And hence, when one piston is firing and the other maybe isn't, we still get a very good growth story in Enbridge. So very broad base, that's reason number one.

Reason number two is asset positioning. As I indicated in my introductory remarks, if you run a crude oil pipeline system in the world, if you can find a better one in terms of asset positioning than we've got, please let me know. Similarly, in the Gas Pipeline business, what better gas pipeline than the liquids-rich dense phase Alliance Gas Pipeline project or gathering and processing assets in the Anadarko, in the Bossier, the Haynesville, the Barnett. We couldn't have better positioning with regard to these liquids-rich gas plays that are occurring in North America right now. So -- and similar, if you run a gas distribution franchise, tell me where better to run one than here in the Metropolitan Toronto and the Ontario franchise. So reason number one, diversity; reason number two, the positioning of the assets; reason number three, the management team. I think as has been shown to you through the day-to-day great depth in this management team. They have been with Enbridge for some period of time, know the business well, and that really makes a big difference as we -- as our confidence in the growth goes up.

Finally -- or not finally, but fourth, the track record. If you look back over, I would say, anywhere from a 10 to 20 to 40-year period, you will find very few major corporations in North America that have had the quarter-over-quarter, year-over-year success of Enbridge. There might be a handful. There might be 3, 4 or 5 in that category, so the track record is something that should give you every bit of confidence and it gives me confidence in the sustainability of the growth story.

Next, discipline. We are what has been described by some investors as a conservative but aggressive management team. And those 2 things maybe sound a little contradictory, but they're not. We're very conservative and disciplined, and we really do our homework on opportunities in front of us, but we don't think we miss anything. We're very aggressive in getting out after every midstream and pipeline opportunity that comes before us.

Number six, the balance sheet. We've got a very strong balance sheet. It has grown in strength over the past decade. And as just indicated in the discussion around liquidity and the track record that we've had of capital management through good times in bad is very hard to compare to.

And I guess finally, I consider us to be the best operator in the business. And if there are any questions on that, we are out to prove that we are top decile to #1 in the business as an operator in North America and very committed to that.

So those 7 reasons give me a very high degree of confidence in our ability to sustain the growth story, and more importantly, I guess, to provide that whole triangle of investment proposition to you of growth, of security and safety in the investment and of yield. As Richard said on the yield side, nothing but upside from the policy that we've followed in the past.

So I'm very confident in where we are and where we're going. And with that -- and by the way, I should add and I implied this, but I've never been more confident in terms of the operational integrity of the system. Maybe it's been in part to trials and tribulations that we've gone through over the last year and a quarter at Enbridge that's given me that confidence, but I find out about every single operational incident. That information is shared throughout the organization and, to the extent possible, with the industry. And I've never been more confident of the integrity of the system that we operate than I am today.

So that is all I have to say by way of concluding remarks. I'll maybe now just throw it open for any final questions or comments, and then we will adjourn, I guess, next door for lunch. But questions, comments, thoughts?

And by the way, Andrew, with regard to the -- what the market is missing, I don't know that it's so much missing anything, but we've always felt that we're bumping up a ceiling -- against a ceiling with our multiple advantage over the rest of the business. That doesn't fully give us credit for the fact that -- maybe it gives us credit for being the lowest risk in the business, maybe it gives us credit for being the highest growth in the business or having very strong in growing yield and track record, but it doesn't give us credit for all of those things together. And that's what we're trying to point out with the substantial upside comment.

Questions, comments or lunch? You've got 3 alternatives. And I see a vote for lunch. So thank you all very much. We really appreciate your time, and I look forward to any follow-ups that you've got. Thank you.

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Source: Enbridge Inc. - Analyst/Investor Day
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