Good afternoon, ladies and gentlemen. Welcome to the Enbridge Inc. 2014 Guidance Conference Call. [Operator Instructions] Please note that this conference is being recorded. I would now like to turn the meeting over to Adam McKnight, Director of Investor Relations. You may proceed.

Thank you. Good morning -- or good afternoon, and welcome to Enbridge Inc. 2014 Guidance Call. With me this afternoon are Al Monaco, President and CEO; Richard Bird, Executive Vice President, Chief Financial Officer and Corporate Development; and Steve Wuori, President of Liquids Pipelines. This call is webcast, and I encourage those listening on the phone lines to view the supporting slides, which are available on our website. A replay of the podcast -- a replay and podcast of the call will be available later today, and a transcript will be posted to our website shortly thereafter. The Q&A format will be the same as always. We'll take questions from the analyst community first and then invite questions from the media. [Operator Instructions] Lastly, I would like to remind you that I will be available after the call for any follow-up questions that you might have. Before we begin, I'd like to point out that we may refer to forward-looking information during the call. By its nature, this information applies certain assumptions and expectations about future outcomes, so we remind you it is subject to the risks and uncertainties affecting every business, including our own. This slide includes a summary of some of the more significant factors and risks that might affect future outcomes for Enbridge, which are also discussed more fully in our public disclosure filings available on both the SEDAR and EDGAR systems. With that, I will now turn the call over to Al Monaco.

Okay. Thanks, Adam. Good afternoon, everyone. Hopefully, you've had a chance to catch up with our news release that we issued just a little while ago. And I'll start with Slide 4 here, and this slide just highlights the topics for today's call. I'm going to begin by discussing our 11% dividend increase, which we're very pleased to announce this afternoon. Then I'll talk about 2 developments since our last call, being the Sandpiper throughput commitment for Marathon and the Midcoast Energy IPO. Richard will then review our 2014 EPS guidance range of $1.84 to $2.04 per share, along with an update to our 2013 guidance and financing activities. I'll wrap up with a few comments on the growth program and the outlook in the longer term. Earlier today, as I said, our board approved an increase in the quarterly dividend from $0.315 per share to $0.35 per share or $1.40 on an annualized basis. That's effective with our March 1 dividend payment. That represents just over 11% increase in the dividend. As you can see with this picture, the strong predictable growth we generated over time. In fact, this is our 19th consecutive dividend increase. This significant bump this year reflects the confidence management and the board have in the earnings growth we expect over the 5-year planning horizon, and for us, that's out to 2017. The 11% growth is also right in line with the midpoint of our 10% to 12% EPS growth range, which we talked about at our investor conference, Enbridge Day, when we reviewed our strategic plan. That confidence is based on the strength of our existing operations and the enterprise-wide growth capital of $36 billion from 2013 to 2017, $29 billion of which is commercially secured and in execution. So there's a high degree…

Thanks, Al. So I'll pick up on Slide 9. And we are setting our guidance range, as Al mentioned, for 2014, earnings per share were $1.84 to $2.04. This reflects the combined effect of our 2013 equity pre-funding, which affects 2014 as well, plus the fact that we are carrying a peak level of work in progress into the year and through much of the year before it begins to generate earnings and cash. Also, a large component of this capital is in the tilted return category. So this is consistent with our Enbridge Day messaging about the EPS profile -- growth profile shape that we're expecting over our 5-year plan. And even at that, based on the midpoint of our 2014 guidance range, the 2-year growth rates relative to 2012 base is just under 10%. Moving to Slide 10, that provides some granularity on the contribution of the individual business units to our 2014 earnings per share growth. So starting with Liquids Pipelines, which, having been our biggest engine for growth in 2013, will temporarily be a more modest contributor in 2014. The mainline, excluding the Line 9 component of the mainline, will be essentially flat for 2014 over 2013 with the benefit of stronger volumes, which we are expecting, offset by a lower Canadian residual component of the international joint tool. And that lower tool reflects the flow-through effect on the Canadian tool of peak integrity spending in 2013 on the Lakehead System. Line 9B will no -- will generate no revenue for most of 2014 as it will be shut down while its flow direction is reversed. We will see an increase in contribution from the oil sands regional system and from the Gulf Coast access projects as they come into service, though modest initially in 2014…

Okay. Thanks, Richard. Bringing this back now to the bigger picture. Slide 13 emphasizes that, really, what we've been saying, it's a foundational year for Enbridge and what further enhances our confidence in the longer-term outlook. Our fourth quarter success in winning both the Wood Buffalo and Norlite projects, totaling $3 billion, brings us to a secured capital of $6 billion of new investments this year. If you look at the list on the slide there, these were mostly driven by Liquids Pipelines growth. But they also include attractive renewable and gas projects. Importantly, the vast majority of these projects are underpinned by long-term commitments, so they fit very well with our investor proposition. They're also highly strategic and solidifying our already strong position on the continental liquids business, including, and this is important, our regional positions in the oil sands and the Bakken. If you look at the next 5 years, total growth investments now sit at $36 billion, of which $29 billion is secured, and all of that is planned to be in service, the $29 billion, by 2017. That capital plan drives the earnings and dividend outlook you see here on Slide 14. We're expecting to generate average annual EPS growth of 10% to 12% through 2017, and that $6 billion in new projects secured this year that I referred to gives even more confidence that we'll achieve that goal. It's the same picture, really, that we've been showing that includes the lumpiness of the EPS profile that Richard described earlier, which stems from the magnitude of spending associated with the level of capital coming into service in 2014 and '15 and the pre-funding activities related to the secured projects. We're also confident, on the right-hand side of the left chart, that we can extend the growth…

[Operator Instructions] Our first question comes from Linda Ezergailis from TD Securities.

Appreciate the call and the update. Even since Q3, you guys have been busy. I have a question with respect to your kind of flat mainline -- Canadian Mainline earnings outlook. Does that include Flanagan South?

No. No, the mainline would basically be anything up to Chicago and Sarnia. The -- anything extending beyond those areas is market extension earnings. And then the Canadian Mainline, of course, is only from Alberta to the border at North Dakota.

Okay. Thank you for that clarification. And then looking at the CTS model, can you maybe give us an update on your expectation of scale factor for next year?

Sure. I think we're going to continue to see scale factors in that sort of 1.20 area, Linda, for those that are kind of tracking that. That's reflecting a higher proportion of long-haul of versus short-haul volumes that we've been seeing of late. And I think that will continue to be the case as we work our way through the quarters of next year, with some variability quarter-to-quarter. But that 1.2 is about as good as a stable average as we can see.

Okay. And your cost structure, will that change materially or is it all -- like you said, the IJT and volumes would be the main variables?

It would be IJT and volumes are the 2 primary drivers.

Our next question comes from Robert Catellier from Macquarie.

I was wondering if in your discussions with Marathon on Sandpiper, if there was any discussions towards them taking an investment in some of the Eastern Access Projects? Or have you pretty much taken care of those needs through Midcoast Energy drop-down and other means?

Robert, it's Al here. As I said in my remarks, the partnership on this project, Sandpiper and the Southern Access Extension is a very good fit, a very good partner for us, and hopefully, we see -- they see it the same way. Other than that, though, I think, we're pretty well set in terms of our funding requirements, both in EEP and Enbridge, and we've got that managed within the funding plan that Richard has mentioned. So there's no plans for anything other than that at this point.

Okay. And then as you address the eastern Gulf Coast access, can you just give us an update there how you're planning to attack that market? In particular, are you considering any other options in addition to the Trunkline project?

Well, we're looking at all kinds of things. We're always surveying the market. Obviously, we think the Trunkline project is still a good project. We tend to think that timing is the only issue there in terms of being able to get volumes to the head of that system. So we think it's strong. There's also some other opportunities that we could look at. Nothing that's been advanced to this point that we can discuss.

Our next question comes from Steven Paget from FirstEnergy.

Could you please update us on further progress on the new U.S. co-funding vehicle you discussed at Investor Day? Or is -- did that really refer to Marathon?

Go ahead, Richard.

No, that doesn't refer to Marathon. Marathon's in a little bit different category, I guess, of co-funding. No, it refers to a vehicle that would involve a financial institution investor or investors. And no, I can't really update you on the progress of that, and I think I might have mentioned on the third quarter call that, that's not something that we're going to sort of report on as we go. If and when we get something in place there, we'll announce it. But it's not something that progress is made in a month-by-month basis.

Do you still see a 10% annual growth post -- in 2018 to 2022 as possible?

Maybe I'll take that one, Steven. Yes, the base 5-year plan, strategic plan outlook is for us to have an average annual 10% to 12%. In fact, yes, we think we can extend that beyond 2017 for the reasons that we alluded to briefly earlier. Obviously, the tilted return profile of that $14 billion in projects that we have that fit that category comes into play beyond 2017 in a nice way. And as well, we have some other opportunities on the other platforms that we're thinking of, along with the potential, at that point, for the drop-downs. So I think we feel pretty good about being able to extend the 10% to 12% beyond that horizon of 2017.

And if I may follow up with that question. Your counterparties really seeming to prefer the tilted return profile. It does seem to be more the way in the industry.

; Yes. I think that's a good point. Although we don't always see that. I think we've seen it in instances where -- the oil sands is a good example, whereby, obviously, you've got phased-in growth rather than 100% of the volumes coming onstream on Day 1. So that's 1 aspect of it. In addition, you often see a toll ramp lighter in the front end then stronger in the back end or higher in the back end. So it's really a facilitation, I would say, of the customer needs, particularly in the oil sands. But not always the case. Anymore to add on that, Richard?

Yes. So I think we're standing at about 50% of our growth capital in the tilted return and the other 50% in the more conventional flat return. And we're quite happy with that balance. It's nice to have instant gratification of the flat return profile. It's also nice to have the built-in embedded growth of the tilted return profile. I think, as Al said, it varies from case to case, and maybe we'd just point out that the most recent $3 billion is essentially flat returns. So the Fort Hills and the Norlite projects are -- they have a tiny tilt to them, but not enough to really be thought of as tilted-return-profile projects.

And if I could follow up on the follow-up, do our counterparties look -- are they willing to have interest rate pass-through? Or do they look for baked-in interest rate and then Enbridge assumes whatever risk there might be?

I'll take that one, too. I think, again, it varies from project to project. We do have still a few that are sort of pure conventional cost of service where everything is passed through. But most of the projects are fixed toll supported by throughput agreements. And so in those cases, we do take the interest rate risk and we do take operating cost risk, although operating cost tends to be a pretty small variable in the total equation. And we do manage that interest rate risk through our corporate interest rate risk management process, which, at this point, has most of our forward exposure, both on incremental funding and on refinancing, hedged.

I think that latter point is really the key, Steven, in that. When we look at this long-term investments, we really want to make sure we're locking down as much of the risk as possible. So taking out the interest rate sensitivity and volatility where we can with the hedging program is something we strive to do in most cases.

Our next question comes from Robert Kwan from RBC Capital Markets.

Just, I guess, if you look into 2014 range, are you able to give the 2 or 3 main drivers that would cause some volatility within that range?

Richard, you want to handle that one?

Sure. Well, mainline volumes would certainly be one. Notwithstanding the fact that we are pretty significantly locked down on interest rates because of the volume of funding that we have, that still can have some impact. Same thing would be true with respect to foreign exchange rates. Largely locked down, but still we have enough U.S. dollar earnings and cash flow than that can make a difference. At the moment, the direction that the foreign exchange rate seems to be taking, it would make a difference for the better, but obviously, there's many things that can move in either direction. And probably next after that would be the level of opportunity on our Energy Services business, which we've seen, in 2013, in the early part, open up to be much more plenteous than would normally be the case. And then, actually, in the fourth quarter, it's closed down quite significantly. So that would probably be the next in order.

Maybe another one with -- if you think about Aux Sable and generally the -- some of the NGL exposure, we try to hedge that out. But given ethane rejection, I think we're pretty well. Got that to a point where we're happy with it, but I guess it's possible that, that moves around as well.

Okay. And just the last question I've got, small in here. What's the assumption in the guidance with respect to the first phase of the Clipper expansion?

We've got that in on midyear, Robert. We haven't change that assumption.

Our next question comes from Paul Tan from Crédit Suisse. Andrew M. Kuske - Crédit Suisse AG, Research Division: It's Andrew in for Paul. Just on -- following up on Robert's question on Clipper. Just the timeline procedurally, what are your expectations for the presidential permit amendment and that being granted?

You want to take that, Steve?

Sure. Basically, the -- what's required is the supplemental environmental impact statement to move the volumes from the 450,000 barrels a day in the original EIS to the 800,000 that we've applied for. A third-party environmental contractor will be working to prepare that SEIS on behalf of the state department. There are a public and government comment periods built in to that. So all of that timeline is built into assumption of midyear in service, and we are under construction on the facilities themselves, so those should match up quite well from the way the timelines look right now. Andrew M. Kuske - Crédit Suisse AG, Research Division: And so there's no real risk on you proceeding with the construction, just given the nature of really increasing the pump capacity at the pump stations on this from a regulatory perspective at all?

Yes. I mean it's never without risk. But certainly, the physical construction is very straightforward, adding pumps at existing stations. In the case of the presidential permit, those would apply to those stations that are in Minnesota. There are 3, so that's very straight forward. There's no new pipe to construct or anything else. So it is a very straightforward amendment as opposed to a new application.

In Minnesota state, the approval is provided.

Yes.

We need the approval for the Canadian side. Andrew M. Kuske - Crédit Suisse AG, Research Division: All right. That's helpful clarity. And then just if I may on Norlite, what is the timeline or time frame that Keyera has on their option for 30% interest in that pipeline?

I think they announced a day or 2 ago that they're extending or taking advantage of an extension of that option period that they have. It will be the end of the year, basically. And they're going through their own analysis of the Norlite opportunity, and we're prepared for either outcome. We welcome them as a partner. They're a good partner. However, if they decide not to participate, we are prepared to move forward with Norlite without them. Andrew M. Kuske - Crédit Suisse AG, Research Division: And if they elect not to, I mean, there's really nothing financially meaningful from your perspective? I mean, it would be nice if you did all of it, but it's not make or break, either way?

No, it isn't. We're quite happy with the 30% option that they have for interest in the project and the assets that they would bring on the Edmonton end of Norlite to that. But we're also fully prepared if they elect not to do that.

Our next question comes from Pierre Lacroix from Desjardins.

Steve, I just wanted to get a bit of an update on Southern Lights and related to the Cochin presidential permit that they got a couple of weeks ago. Any readthrough either for Southern Lights and your mainline presidential permits that you'll be seeking?

I think the action where they got the presidential permit approval to actually take a propane pipeline and reverse it into diluent service is positive. It shows that the market is working and the regulatory environment is working along with it. Looking for more diluent condensates in Alberta, we will be expanding Southern Lights, as I think we've mentioned. And so I think that all fits together very, very well. I view their approval as a positive.

Our next question comes from Paul Lechem from CIBC.

Just going back to the mainline and the residual benchmark toll under the IJT. Can you just give some thoughts on how is that -- how does that move around the Lakehead System? So what are the inputs to that? And then therefore, your residual amount how -- are there inputs that could vary in the year depending on various actions that we should know about?

I'll take that one. The main impacts that factor into that toll is the cost of service inputs associated with certain types of capital that they undertake. And it's basically a flow-through of what's gone into service over the prior year. There's basically 2 Lakehead toll adjustments in the course of the year, one comes at the end of the first quarter and one comes at the end of the second quarter. The first quarter adjustment is the annual FERC index adjustment to the Lakehead toll. And at the end of the second quarter is the adjustment that relates to those cost of service overlays that I mentioned. So at this point, there's relatively little uncertainty as to what that toll impact is going to be for the coming year.

So at the end of Q3, your residual toll was $1.80 [ph]. What do you expect it to be by the end of Q1 and the end of Q2?

I don't think we're going to get into that level of granularity of guidance.

Okay. And these are all denominated in U.S. dollars, I believe. Is that correct? If so, how much of that have you hedged? Can you benefit if the Canadian dollar moves lower here? Or have you substantially hedged away that risk or that opportunity? And for how long?

So the answer is yes and yes. We can benefit, but we have substantially hedged out for, at least, the first 5 years of -- not the first -- the first 5 years of our 5-year plan. So we're -- I think I went through that at Enbridge Day. I don't have it right in front of me. But generally, we're 90% hedged Enbridge-wide for the first 2 or 3 years of our 5-year plan and about 80% for the next couple of years after that.

At this time, we'd like to invite members of the media to join the queue for questions. [Operator Instructions] And your last analyst question comes from the line of Steven Paget from FirstEnergy.

Could you please comment on the forces pushing Energy Services earnings lower in the fourth quarter?

Sure. It's basically -- that business is a physical arbitrage business. It's taking advantage of location differentials, time differentials on the forward curve and to a certain degree, the differences in values of crudes, where it's possible to develop a tailormade crude for a particular refinery and source the inputs to that crude at advantageous differentials. And basically, it's the coming and going of those arbitrage opportunities that generates margin in that business. And almost by definition, the bigger arbitrage opportunities are ones which disappear over time because people find solutions to the imbalances that give rise to those arbitrage. Sometimes those solutions come pretty quickly as there's nothing special required to solve it, just some logistical knowhow. Sometimes it takes a little longer as types of infrastructure have to be constructed. But sooner or later, they generally all vanish. So differentials, basically, across the board pretty well closed up in the fourth quarter, at least the ones that generate margins for this business.

Final question, could you please comment on what CapEx looks like in 2014?

Not beyond the level of granularity that we've disclosed externally, which is the volume of capital that's coming into service in 2014, which is about $9 billion. So there will be some additional capital that's spent in 2014 that isn't coming into service. There'll be some capital that's already been spent in 2013 that's within that $9 billion, and that's the level of granularity that we've consistently disclosed.

Our next question comes from Jeff Lewis from The Financial Post.

Perhaps this one is for Steve Wuori. There's been a lot apportionment on the mainline of late, and I guess some of that was due to maintenance being higher than normal, I think. Do you expect that to clear up before you get new capacity or the Clipper approval? Or is that sort of choppiness more of what we can expect until there's additional capacity?

I think, Jeff, on the third quarter call, I talked a little bit about this and the fact that in some cases, in some weeks, there's -- it's hard to find a good home for the heavy barrels, especially if there are downstream disruptions. And I mentioned the refinery fire that took place in late October in the Chicago area. So I think that's an example of -- and the volatility that we see then is an example of trying to balance the system with some downstream constraints caused by refinery issues, some upstream constraints and some restrain -- constraints within the pipeline itself, including maintenance and other things. I would expect there to be some choppiness until a couple of things happen. One being -- well, maybe 3 things. One is the full return of that refinery to full service in Chicago. The second would be, of course, the big BP Whiting conversion to -- that they've been working on and are now turning on. And then the third would be the opening of our Flanagan South pipeline in the middle of the year, which is going to provide another path for, especially, heavy crude to move towards the Gulf Coast, but light crude as well. So those things -- and then Line 9 later in the year, are really the drivers that I think will stabilize things and make sure that there aren't any downstream constraints that impact the pipeline system. Meanwhile, we'll continue to work on issues along the mainline, maintenance, lifting of pressure restrictions and other things that we've talked about. But I think the apportionment that you've seen has been largely lately driven by those downstream disruptions.

Okay. And then just a quick one as a follow-up. Did -- the plans for Flanagan South and Sandpiper, are those contingent at all on the Alberta Clipper approval? Or in other words, are you trying to sequence those pipelines?

No, not necessarily. We're -- those are both -- Flanagan South is due to come on in the middle of the year. As we've said, that isn't dependent on the Alberta Clipper amendment outcome by the middle of the year. And then Sandpiper, of course, is further off. That's a 2016 in service, so that really doesn't play in.

As there are no further questions, I would now like to turn the call back to Adam McKnight for any closing remarks.

Thank you, John. We have no further -- nothing further to add at this time. But I would remind you that I will be available for any follow-up questions that you may have. Thank you, and have a good day.

Ladies and gentlemen, this concludes today's conference. Thank you for participating. You may now disconnect.