Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2012 Fourth Quarter Results Conference Call. I would now like to turn the meeting over to Mr. David Moneta, Vice President of Investor Relations. Please go ahead, Mr. Moneta.

Thanks very much, and good afternoon, everyone. I'd like to welcome you to TransCanada's 2012 Fourth Quarter Conference Call. With me today are Russ Girling, President and Chief Executive Officer; Don Marchand, Executive Vice President and Chief Financial Officer; Alex Pourbaix, President of Energy and Oil Pipelines; Karl Johannson, Executive Vice President and President of Natural Gas Pipelines; and Glenn Menuz, Vice President and Controller. Russ and Don will begin today with some opening comments on our financial results and certain other company developments. Please note that a slide presentation will accompany their remarks. A copy of the presentation is available on our website at transcanada.com and can be found in the Investor section under the heading Events and Presentations. Following their prepared remarks, we will turn the call over to the conference coordinator for questions. During the question-and-answer period, we'll take questions from the investment community first followed by the media. [Operator Instructions] Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations or your detailed financial models, Lee and I would be pleased to discuss them with you following the call. Before Russ begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian Securities Regulators and with the U.S. Securities and Exchange Commission. Finally, I'd also like to point out that during this presentation, we will refer to measures such as comparable earnings, comparable earnings per share, interest -- sorry, earnings before interest, taxes, depreciation and amortization or EBITDA, comparable EBITDA and funds generated from operations. These and certain other comparable measures do not have any standardized meaning under U.S. GAAP and are therefore considered to be non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities. These measures are used to provide you with additional information on TransCanada's operating performance, liquidity and its ability to generate funds to finance its operations. And with that, I'll now turn the call over to Russ.

Thanks, David, and good afternoon, everybody, and thank you for joining us for our first quarterly conference call of 2013. Starting with some highlights in 2012 is let's say 2012 was a very positive year for our company as we made significant progress on a number of very important initiatives that I believe will improve the future performance of our existing businesses. As well, we placed into service several strategic capital projects, and we also captured significant new opportunities, which will provide the visible growth for our company for many years to come. Financially, we performed relatively well in 2012 with comparable earnings of 130 [Audio Gap] or $1.3 billion or $1.89 a share. Unfortunately, earnings in 2012 were impacted by lengthy delays in the start up of the Bruce Units 1 and 2, the unplanned West Shift outage of Unit 4, the loss of Sundance A contributions for the year. In addition, the continued low natural gas and power prices, which did put pressure on those commodity-exposed assets that are affected by commodity prices. Looking forward, we did receive positive decisions related to both the Sundance A and Ravenswood issues and we placed $3.4 billion of new assets into service and they started operations. We saw the start up of the Bruce Units 1 and 2 late last year. We expect the return to service of Unit 4 this quarter. The Sundance A issue, as I said, was resolved at this year as well and we expect that Unit to return to service in the fall of 2013. All of those events, along with the startup of other key natural gas pipeline Energy projects that I mentioned, are anticipated to have a positive impact on earnings and cash flow in 2013 and, because of their contractual nature, in many…

Thanks, Russ and good afternoon, everyone. As you know, earlier today we released our fourth quarter results and announced a 5% increase in the common share dividend. Before I discuss our fourth quarter in detail, I would like to reiterate a few of Russ' key messages. The majority of TransCanada's diversified portfolio of high-quality energy infrastructure assets performed relatively well in 2012. However, persistently weak natural gas and power prices, planned outages at Bruce Power and the absence of Sundance A did negatively impact earnings. $3.4 billion of new assets were placed into service in 2012, most of which occurred in the fourth quarter and are expected to contribute to earnings and cash flow growth in 2013. The company has commercially secured $16 billion of new projects over the last year in its 3 core businesses. These projects will further diversify the company's portfolio and contribute to sustainable earnings, cash flow and dividend growth in the future. And finally, we remain well-positioned to fund our current capital program, as well as pursue other growth initiatives. Now, moving to our fourth quarter consolidated results. Comparable earnings in the fourth quarter of $318 million or $0.45 per share decreased by $47 million or $0.07 per share compared to the same period in 2011. Lower contributions from Western Power, Bruce Power, Canadian Mainline, ANR and Great Lakes more than offset increased income from the Alberta System, Eastern Power and U.S. Power. On a per share basis, changes in comparable earnings for the fourth quarter 2012 compared to 2011 are summarized as follows: earnings rose $0.04 from improvements in Eastern Power, U.S. Power and the Alberta System. In Energy, the Sundance A force majeure caused EPS to decline by about $0.06 and planned outages at Bruce Power decreased EPS by an additional $0.01. In…

Thanks, Don. Just a reminder, before I turn the call over to the conference coordinator, we'll take questions from the financial community first followed -- and once we've completed that, we'll then take questions from the media. With that, I'll turn it over to the conference coordinator.

[Operator Instructions] The first question is from Paul Lechem with CIBC.

My question's with regard to the Komie North project that was denied by the NEB. I was just wondering, what was different about this application than others you've made, number one. Number two, what now? Do you go back with a different proposal to get this project complete? And finally, does this potentially impact any of the extensions into the North Montney that you proposed to build out?

Let me start with the first part of the question, what was different. I think there's one area here that the Board paid particular attention to that is a little different than our other application and it was really the commercial backstopping of this project. The Board did agree with us that the facilities that we proposed were proper. The Board agreed with us that our stakeholder consultations were proper and correct. And they also agreed with us on the total reserve estimates that we had in that area. What the Board didn't accept was our commercial underpinning for the project. We had one customer on that project and we did -- when we initially did set up that project, we expected more customers to come. But with the Horn River development slowing down, with the low gas prices, they never did materialize. So the Board did come back to us, suggested that we would have to relook at the commercial backstopping on this. They suggested that we either get more volumes on the system, longer-term contracts or more customers just in generally, to backstop the system. So how that plays in the future is that TransCanada's still interested in the Komie North project. We are, right now, in the marketplace. We will be talking to our customer on there. And we'll be, over time, gathering new customers to resubmit that application in due course.

I think just, Paul, just to I guess remind you as well that part of the application was approved, the Chinchaga portion of the application, which had sort of a more traditional underpinning to what we've seen in the past on the NGTL system. So your other question, how does it affect our business going forward. I don't think anything really changes with respect to how we move forward on NGTL. They didn't suggest that there's any issue with our tolling methodology or anything like that.

Okay. So the projects that you're suggesting, your build out in the North Montney related to the LNG pipe service wouldn't be affected by this decision?

No, I think as Karl pointed out, I mean, there's multiple customers and much larger volumes for those projects. So I fully expect that they will be approved similar to our system that we've operated under in the past.

The next question is from Juan Plessis with Canaccord Genuity.

I noticed that your expectations for the Keystone XL approval has shifted a bit to the first half of 2013 from the first quarter. Can you take us through the process as you see it for the Department of State approval for Keystone XL? And more specifically, do you expect there could be another comment period after the State Department issues its supplemental EIS?

Sure, Juan. It's Alex. Just in terms of the Keystone XL process, obviously, the first thing we're waiting on now is the issuance of the supplemental EIS, which will be largely focused on the reroute in Nebraska. Certainly, what we've heard, I think, what everyone has heard is that the State Department intends to issue the SEIS quite quickly. I mean whether that's 1 week, 2 weeks, it's hard to say, but they've certainly led us to the view that it is imminent. Once the SEIS has been issued, we are of the view that the State Department is in receipt of absolutely every piece of information they could require to make a decision. There are a number of sort of statutory notice periods in the remaining process. I would expect that we would be in a position anywhere between 2 and 3 months to get a decision from the State Department once that SEIS is issued.

And just as a follow-up here, there was mention in the MD&A that the Bruce Units 1 and 2 were expected to operate at lower utilization rates in 2013. Can you talk a bit about your expectation for utilization rates for those units? And does the 90% expected utilization for Bruce A in 2013 take this into account?

Yes, it does. And it'd probably be helpful just to give a little background on that. When we brought those units into service, really, for the first time in their life, they have a -- first and only time in their life, they have a full load of brand-new fuel, and that results in a very energetic core. And just from a safety perspective, what happens is that the units are slightly derated and then over a period of about 3 months, they ramp-up to full power. So that 90% is a good full year number.

The next question is from Linda Ezergailis with TD Securities.

I realize it's still somewhat early days in your Mainline Conversion project, but you have had some very encouraging conversations recently. So I'm just wondering if you can give us a sense of what the views are on potential ultimate end markets and how the interest is for various terminus points of the pipeline, whether it be Québec City, Montréal or St. John? And what the customer mix is like in terms of shippers that have expressed interest, whether it be mostly producers versus refineries?

Sure, Linda. Happy to do so. With respect to the Eastern conversion project, as Russ said, we have been advancing discussions with potential shippers, and we are quite pleased and optimistic about how those discussions are going. I think there's a great deal of interest in moving towards those markets. From our perspective, when we look at the markets, there's obviously, there's about a 400,000-barrel a day domestic market in Québec. There's about another 400-odd thousand barrels a day refining capacity in the Maritimes, largely underpinned by Irving. We would see that domestic markets would be largely the focus of the pipeline and potentially I guess, down the Eastern Seaboard. I think initially, those would be the lion's share of the markets. We have talked about a number of termination points for the pipeline, and what I would tell you, there are sort of pros and cons from each of them from our perspective, and they go anywhere from points in Québec to going all the way out to the East Coast. And at the end of the day, we're going to listen to our shippers, and so we haven't reached final conclusion on that aspect of the project yet.

Okay. That's very helpful. And in terms of your business development costs, they've moved around in your various business units. Can you maybe just give us a sense of how they might be trending over the next couple of years?

Sure. I can talk to mine, and maybe Karl can talk to his, if that's of interest. But I would expect, there's obviously been a downward trend in BD costs on the power side. I think that probably we're at a reasonably good run rate for a period of time, maybe a little potential downside. I -- given all of the opportunities we're seeing on the oil side, I would continue to expect to see some reasonably robust BD numbers come out of the oil side, of course subject always to our desire to capitalize them if we think they're leading towards projects that are going to come into service.

And I think on the natural gas side, I think similar to the Energy, I think what you see today is a pretty good run rate for BD cost. We have -- we were expecting some more business to come up to Mexico, so we'll be concentrating our resources there and any further LNG-related projects that we have on the Alberta System.

The next question is from Carl Kirst with BMO Capital Markets.

Just a couple of questions on the -- going back to the Eastern conversion, and I guess with sort of as the project may be focused more on serving domestic markets rather than perhaps heavy oil export, has that given you a sense, a better sense, of what the magnitude of the pipeline that this is honing in on, and specifically, trying to get a better sense of maybe what size line you'd be lifting out of the Canadian Mainline?

Sure. Depending -- we've said publicly that we have a number of options with what pipes to take out -- to buy out of regulated service, and that would give us a range of between about 500,000 at the smaller end and possibly up pretty close to 1 million at the upper end. Our gut feel is we'll probably be more past the middle of that range than the bottom end. But as I said, we're still waiting to hear back finally from a number of our potential shippers.

Carl, I agree with Alex. It's Russ. I suspect it will be at the larger diameter pipe to give us the optionality going forward of being able to expand in the future. I think we're seeing a minimal interest in at least sort of the 500,000 to 600,000-barrel a day range. But as you sort of look out, that kind of import level that Alex mentioned would lead you to believe that on the whole Eastern seaboard, in total, between Canada and the United States, we're importing something close to 1.5 million or more barrels a day, which suggests that there's a market out there for domestic production to attach to that market.

Is it still -- I mean I think in prior discussions we thought maybe about, depending on the size of that pipe, between a half and a mil, that we'd be looking anywhere from 1 billion to 2 billion buying out from rate base. If we're looking at a larger diameter piece and we are again locked to settle out here, but if it does go that route, is it possible even to say of that overall 2 billion amount, say for instance, how much of that is associated with what you might call the problematic piece of the mainline right now?

I guess my first comment is that I don't think there is problematic piece of the mainline, it's an integrated piece of infrastructure. I think what we're working through right now -- I'm going to let Karl talk in a second, but what we're working through is ensuring that we have sufficient capacity to meet the needs of our gas customers going forward. And as we've said before, it's a needed piece of infrastructure. So depending on what we do, there's varying amounts of work that we'll have to do to ensure that we can continue to meet their needs going forward. And as you pointed out, it's a dynamic sort of changing environment. But I think the key would be -- is ensuring that the facilities that we repurpose to oil, if they impact our ability to deliver gas, that we can meet the needs of those customers that are actually willing to sign up and pay for that capacity. So I'd say it's early days, Carl, on exactly how that's going to work. But the numbers that you pointed out, we haven't changed our views on those numbers at all.

Okay. Great. And then lastly if I could, just with respect to, Russ, your comments I guess on perhaps following this with an open season. I just wanted to make sure I understood that correctly. Would that be sort of market or customers giving you soft indication and then you'd go to an open season to firm everything up? Or would you only go to an open season if there were minimum commitments that you knew it was going forward and the rest you were just trying to kind of get icing on the cake, so to speak?

Carl, it's Alex. We're out right now seeking commercial support. And I think at the end of that, as a matter of course, we will follow up with an open season. A, it's a requirement that we do so, and we want to make sure we sop up all the potential barrels that are out there. But we're not -- we wouldn't go to an open season unless we're very comfortable of getting a minimum level of commercial support for [Audio Gap].

[Audio Gap] to that, Carl. Is that we're all seeking right now some indication of the questions asked earlier, of receipt points and delivery points. Once we have that, then we know where the project needs to go. And then we have to commence stakeholder discussions along the route. We want to engage with those communities that are [Audio Gap] by that route as quickly as possible, we don't want to [ph] sort of get the cart before the horse here. Because I think it's very important to engage with those communities first and those stakeholders first as well as our shippers in determining what an appropriate route would be to the marketplace. So there is that activity in addition to the open season activity that will take place concurrently. And I guess the third activity that you can think of is when we get into that next phase would be the preparation of a regulatory application, which, assuming all things going well, we'd like to be in position to file by the end of the year.

The next question is from Matthew Akman with Scotiabank.

Don, you mentioned $1.9 billion of CapEx on gas pipes in 2013, and I'm just wondering if any significant portion of that at all relates to the LNG pipelines? And then as a follow-up to that, what are the steps that are necessary that we should be following that need to get put in place before you guys can start putting in significant capital into those projects?

Yes. The $1.9 billion in gas pipes is broken down roughly as, there's about $600 million to go into Mexico, on the 3 projects we have there. Probably around $600 million, $700 million on the Alberta System, which is regular maintenance capital plus some of the expansions we have on the go. And then we will have some development spend on Coastal GasLink and Prince Rupert. Then to top it all off, there would be maintenance capital across the rest of the portfolio. In Alberta, we would expect to file regulatory applications -- and, Karl, jump in if you wish here, for the expansions related to serving Prince Rupert over the course of this year, and then start some spend probably late this year and then more concentrated in '14 and '15.

Yes, our goal would be the end of the year for applications.

So the stage gates on the Alberta System facilities for the LNG would, I guess, be signing agreements with the shippers there and getting through that regulatory process. That's -- it's really separate from the actual approval processes of Prince Rupert.

How do your contracts work with your counterparties, with, I guess, Shell and PETRONAS, in looking at the significant amounts you might be spending in development over the next year or 2, leading into regulatory approval?

Yes. The -- we will spend some amount, in the couple of hundreds of millions of dollars, on those projects to get them to that regulatory phase. If the projects don't proceed, we would get reimbursed for those amounts. And if they do proceed, they would form part of the rate base on those projects.

Okay. Just one other question in the area of power, and then I'll get off the call here. In Northeast power, I noticed that you commented in the fourth quarter that low hydrology impacted there. I'm just wondering if you're seeing that bounce back towards normal at the start of the year as we've seen in some of the other Eastern areas, I guess this is for Alex. And part of my question is also, we've seen very, very robust power prices out there, so I'm just wondering, to what extent you're capturing that in the first quarter here?

Yes. Thanks, Matthew. I don't have the volumes in front of me. My recollection was that the volumes have -- or certainly are forecast for the full year, is that we're going to bounce off those very, very low hydro volumes that we saw last year. That was kind of a sort of a 1 in a 30 or 40 year event in terms of volumes. In terms of pricing, we are, certainly with the prevailing relatively low prices, we are much less hedged than we typically would be at this time of year. So whenever we see those robust prices, you can imagine that we're going to be capturing a fair chunk of it right now.

The next question is from Robert Kwan with RBC Capital Markets.

I'll just come back to the Mainline conversion. I'm just wondering if you can give us some sense as to the various timelines as you move forward here, as you move to the open season and how long do you think you'd leave that open for and then be able to finalize the commercial terms? How long do you think political/stakeholder discussions would be. And then last 2 would be regulatory and construction.

Sure. Happy to do that, Robert. I think you heard Russ say that we would be -- hope to be in a position that we would be filing our various regulatory applications late this year. And if -- you can kind of count backwards from that, if we're hoping to do that by the end of the year, that means we have a significant amount of stakeholder work in preparation of that -- preparation of those applications. I probably -- you would see an open season somewhere between 30 and 60 days. And we're probably going to need a little time here to get through the engagement and the discussion with shippers that Russ had talked about. So probably, you would see an open season, assuming that we're successful in those discussions with stakeholders and shippers, I'm kind of thinking about something towards the end -- near -- in the latter part of Q2, maybe a little earlier.

And then, regulatory you expect to run for a year?

I think the -- because of the implications of the new bill that was brought into force, the NEB application, once complete, would be 18 months. I'm kind of -- 18 months to 24 months to get through the regulatory process. And then probably think about another 2 years for construction. So looking like 2017 in service.

Okay. And just -- the 18 to 24 months in regulatory, that includes both the facilities application and the removal from rate base?

Yes. That would be our hope.

Okay. Just a last question as it relates to the Mainline, just the toll rate case. I know it's pretty tough to speak of the future ahead of the upcoming decision. But given it only relates through 2013, what are you thinking with respect to a 2014 and beyond process? Are you going to just allow the 2013 to fall and try to use that as a framework? Or is there something greater with some of the developments that we've seen that you'll be pushing for?

Well, I think first of all, we're going to wait until we get the '12 and '13 decision here near the end of quarter, early next quarter, and then we'll make a decision from there where we'll go. Clearly, we have to start, we have to turn our mind to 2014-and-on rates, which we're doing right now. But we really can't address that early until we see the guidance and the decision from the board later this quarter.

The next question is from Andrew Kuske with Credit Suisse. Andrew M. Kuske - Crédit Suisse AG, Research Division: I guess just a point of clarity on, I guess, the last answer on the potential conversion project. Will you be filing specifically a first application on the Mainline conversion on just withdrawing from rate base and then there's a second application for the actual reversal and any other equipment or new pipe that's needed?

Yes. There are -- I mean in the past when we did this on base Keystone, there were 2 separate hearings. We are still taking a look at that, and we're thinking there's probably some opportunity to streamline that process from when we went through it the first time. But as we know more, we'll let the market now.

We're in early days, Andrew, of our conversations with stakeholders. As we mentioned, there's a lot of conversation that yet has to occur between -- amongst regulators and amongst federal and provincial jurisdictions in a pipeline that traverses Canada. So we have to do our work as to exactly how we want to make this application, and we're in those discussions as we speak, and those will become more pronounced as -- over the coming months. So we'll have an answer here by the time we get to making a filing. But it will be premature to say exactly what roadmap we're going to use at this point in time. There's a lot of other people that have to provide us with input before we make those decisions. Andrew M. Kuske - Crédit Suisse AG, Research Division: That's helpful. And then, Alex, just on the U.S. Power, how much outperformance do you think you had relative to your plan on U.S. Power? And how much of that was really related to the storm and the impact of Sandy when some facilities went out, both transmission and generation? Because the quarter looked very good for the U.S. Power versus what we've seen in the past.

Yes. I think you know it's funny. My take on it was, obviously you don't want to profit from something as problematic as Sandy. But I would say that the -- that we were obviously a very big part of keeping the lights on in New York City and sort of other features. But a lot of units during and around that storm were kind of running on a must-run basis. But the market price actually wasn't representing what it otherwise would've been. In other words, I'm saying prices were quite low given the magnitude of impact on power supply. I think when you look at the quarter, you're seeing a few things. You're seeing the impact of some improvement on capacity markets. We did get some benefit from the extreme weather conditions. But I don't think there was any real overperformance involved there. Andrew M. Kuske - Crédit Suisse AG, Research Division: Really just the volume itself is on a per megawatt basis, just on some simple calcs, your per meg numbers were actually down versus a year ago, but your volume is up dramatically. So is it really just the volume and being one of the sole generators that was still operating during that period?

Yes. There's no doubt that all of our assets were running pretty much full-out during that period. Andrew M. Kuske - Crédit Suisse AG, Research Division: Okay. And then just if I can, one final question on the Bruce. What kind of tilt do you think you're going to have on your operating levels? I know the MD&A talked about 90% on the As through the year. Is that your 90% at the end of Q1 for the rest of the year? Or do you have a little bit of a tilt going through the first quarter?

Yes. I think you can think about that kind of tilting upward, like hitting an overall average of 90% and getting there by, in the second half of the year, having availabilities higher than 90%.

The next question is from Steven Paget with FirstEnergy Capital.

Just first question. What's the average price for the Western megawatts you've contracted in 2013 and 2014?

I always get a little uncomfortable with this, Steven. I'm stepping back a little bit about giving sort of guidance on what we've actually sold for. But what I would say is that forwards in 2013 are kind of in sort of higher 50s. 2014 right now we're probably still pretty low, around 50%. And our hedging activities would be significantly north of both of those prices for those years, or some degree north of that.

North of both of those prices. Second question, if the Mainline was converted, some shippers could see a benefit from lower gas tolls, while other shippers aren't really so worried about those same tolls. Is there any discussions between the 2 groups of shippers and the allocation of economic benefits?

It's a little premature to be having that discussion. Right now, we're really still in the process of getting commercial confirmation of our project. When we do get -- if we do move to the next step, I'm quite certain the discussion will be around how much rate base goes out, which facilities go out. I don't anticipate, at least initially, a discussion on giving up the pie so to speak, I'm expecting we will talk asset-specific.

Yes, Steven, historically that hasn't been the nature of the process for our regulated assets. The criteria is public interest, the overall public interest. And they make their determination based on what is the greatest good for the greatest number, and they look at the overall number, and they opine based on that. As opposed to sort of sorting out the winners and losers in a process. It's the overall public interest which is the guiding factor. And that's what I suspect, again, why we're encouraged that obviously from a Canadian interest perspective, there's tremendous benefits from the repurposing. I think folks have seen the impact of the curtailment of -- or the lack of capacity leaving the Western Sedimentary Basin, the impact on netbacks for producers, which impact royalties, which impact taxes and impact the Canadian economy to a great degree. So those are, I think, the overriding factors driving folks to say that this is something that Canada -- is in Canada's interest and we should take a pretty hard look at it. As you just point out, there'll be individuals within that process or within that context that win or lose to a greater degree. But I think the board, the National Energy Board's primary decision criteria is in the overall public interest.

The next question is from Chad Friess with UBS.

Hopefully my Mainline question is the last. I was wondering, what do you view as the primary threat to your Mainline conversion project? I mean, I know there's a lot of railing going into Eastern markets, which is cost flexible and fairly expensive. But it seems like there's also the potential to cheaply move oil from the U.S. Gulf to Eastern markets through tankers. I know there's regulatory hurdles there, but I wonder if you could speak to how your potential project compares on tolls for those sorts of solutions as well as unit train railing?

Well, I think, I certainly think, given the experience we've had on Keystone XL and my observations, that I think getting -- the U.S. getting its head around exporting crude oil when they are so focused on energy independence is -- that's probably a long shot of Marine transits coming out of the Gulf into the Canadian markets. With respect to rail, we obviously are seeing some increased rail movements. I think, fundamentally, looking at kind of the toll that we think we can do out towards East Coast, rail is at least twice as expensive as the pipeline option. And I would argue that if there is a concern about the environment, every barrel you move by rail emits 3x the GHG that a barrel moved by pipe does. And it's in order of magnitude at least more likely to have a spill. So I just think on sort of all of the bases, ultimately, if we're going to be moving the kind of volumes of oil that we're talking about here, and our customers are talking about, then I really think ultimately, everyone wants to get to a pipeline solution.

Chad, I guess just add to Alex comments. What we'll do is we'll let the market decide. There are many alternatives, as you point out, to move the crude. The drivers here are growing production in both Canada and the United States needing to get to markets. The primary markets that they need to get to are those places where we import oil into North America, primarily that's the Gulf Coast, the East Coast of the United States and the Eastern coast of Canada. So right now, there are other alternatives being employed to get that crude to market. Ultimately, the market will decide which alternatives they're going to choose, and we've always been a market-driven company, and I think what I said earlier is our conversations with both producers and refiners to date would indicate that the Eastern Mainline conversion places very high in terms of how they would view that relative to their other alternatives. And based on that encouragement, that's what we're moving forward with here is that they're saying they've look at those other alternative means and for the safety and economic reasons that Alex has mentioned, we believe that we're going to get a very favorable response to our proposal.

The next question is from Ted Durbin with Goldman Sachs.

If you can just give us an update on how you're thinking about potentially other conversions of your gas pipeline assets, whether it's regional oil sands or maybe even some of the U.S. pipes that are seeing lower volumes? Is there anything that you're thinking about there? I'm even thinking about GTN and Northern California, maybe just talk about any strategy there?

I guess what I would say, Ted, is we are constantly looking at our suite of assets to make sure that they're in their highest and most valuable use. And I -- obviously we have a lot of time and effort tied up in this Eastern conversion project that we've been talking about. But I wouldn't have anyone think that while we're looking at that, we aren't considering other options. And to the extent that we see spare capacity that isn't otherwise being utilized, we're going to take a really hard look at it. But right now, the most advanced of those ideas is the Eastern conversion project.

Got it. And then another quick one for me is we've bumped the dividend here again, we're at $1.84. We just had $1.89 of EPS. Obviously pretty high payout ratio on a trailing basis. I guess I'm just wondering how you're thinking about the payout ratio going forward and how we should think about dividend growth going forward?

Dividend growth will follow earnings growth. We've talked about some of the anomalies of 2012. We do have a lot of projects coming onstream. We also still have a lot of capital that's tied up in projects that aren't generating any revenue yet. So if you look at things like Gulf Coast, Keystone XL, even Bruce, where we did bring $2.4 billion into service in the fourth quarter, but we won't see a normalized run rate for -- certainly in the first quarter of this year. As these things come onstream, there are very predictable earnings streams, and we're quite comfortable that we'll grow our way back into more of a normalized payout ratio, which historically we've been in that 70% to 80% earnings payout range. We expect to gravitate back there over time. That equates to about 1/3 of cash flow. So that's kind of where -- I'd point you in that direction.

The next question is from Dennis Coleman with Bank of America Merrill Lynch.

I have a question with regard to the elections coming up in BC, I guess there's been some rhetoric there that would seem to complicate the regulatory process even further. I wonder if you might just comment on the outlook there and potential outcomes and how that impacts some of your projects going west?

Guess what I would say is that our projects going west are 2 natural gas pipeline projects to move primarily natural gas out of Northeast British Columbia. From what we've seen to date, both at a provincial level but also at a local community level from a political perspective, those developments, the value chain of those developments are significant economic generators, significant job generators, and therefore, appear to have the support of local communities as well as the provincial government. And all of the parties that I'm aware of at the provincial level have all endorsed the movement of British Columbia produced natural gas to West Coast LNG export terminals.

So the key there is then its oil versus gas, is that...

I'd say that we're not building oil projects into British Columbia, but our -- so I can only speak to our experience on the gas projects. And so far, so good. We engaged immediately with communities along the right of way. And so far, we have had a positive reception in all of those communities.

Questions will now be taken from the media. [Operator Instructions] First question is from Rebecca Penty with Bloomberg News.

I have a couple of questions actually. I'll ask the first one now. I'm wondering if someone can elaborate on I think there was a point about splitting up the Grand Rapids pipeline and splitting up construction or the time line for in-service. Maybe if someone can elaborate if that's the case on what's going on there and why?

Sure, Rebecca. It's Alex Pourbaix. I'm happy to talk about that. When we announced Grand Rapids, we were anticipating we're building a 36-inch line to deliver from the Grand Rapids region down to the terminus of the pipeline. But we're also planning on putting in place a 20-inch diluent line bringing diluent up north, the opposite direction. The original plan was that we would have that combined project in place in 2017. And we saw the opportunity to actually get that 20-inch pipeline, the diluent line, in-service earlier, but moving blended bitumen south. So what we're going to do, we can have that 20-inch line in-service in 2015, and that probably about 100,000 barrels a day, and then that will be mid-2015. And then by early 2017, we'll be able to bring the 36-inch larger line in-service and be able to move the full 900,000 barrels a day of blend from Fort McMurray down into Edmonton. And at that time, we'll reverse the diluent line to be bringing about 300,000, 330,000 barrels of diluent north, total.

Rebecca, essentially what it does is it allows the production to start ramping on early and grow into its ultimate production. But we can start moving that crude via pipeline earlier by putting the 20-inch line in-service and allowing for that ramp-up to occur.

Okay, great. I just have one follow-up question and this is from a colleague who's writing about TransCanada's debt. Wondering if the Keystone XL decision, if TransCanada gets an approval from the U.S., do you expect to see any reaction in the bond market on your debt on that approval?

No, we wouldn't -- our credit spreads are -- have been pretty consistent here. We wouldn't expect any rating reaction. It would be a credit positive for the company to move that capital that we've expended into revenue, and it's a great diversifier for the portfolio and a great contractual structure. But in and of itself, no, we wouldn't expect a major reaction in the bond market.

The next question is from Jeff Jones with Reuters.

I have a couple of questions. First of all, with regard to the Mainline conversion project, does it make any sense at all to take the line when it gets from the end of the current Mainline to say St. John by going through the United States? Or does that sort of defeat its purpose from a regulatory standpoint, because the route is shorter that way?

Yes. But I think, number one, if you were to do that, there would be a regulatory process in the U.S. that would be incremental to the Canadian process that we're already committed to go through. So I think the idea of streamlining the regulatory process by just dealing with Canadian regulators, obviously, has some attractiveness. The other comment I would say is that a good -- TransCanada has significant existing assets and right-of-way in Eastern Canada. And by going on the Canadian route, we would be able to maximize the distance that the project would go on, on existing right-of-way or via existing pipe.

Okay. And then secondly, maybe on a slightly larger note, although Mainline conversion is a good name, do you have a more permanent name for this project?

We've got our thinking caps on. We have a few ideas that a -- we'll wait and see when we are able to announce that we have shipper and stakeholder support, and I'm sure we can come out with something a little more interesting for everybody.

The next question is from Nathan VanderKlippe with The Globe and Mail.

Just -- I wanted to actually re-ask a question that was asked before, I don't think there was an answer given. But can you give us any sense of the breakdown between shippers and refiners as far as the interest in holding capacity on this Mainline conversion?

I did, and it wasn't on purpose. I just neglected to answer that. Nathan, we're seeing interest on both sides. But until we get the final commitments in, it's hard to know where it's going to fall out. But definitely, we are seeing interest at this point from both sides.

I think, Nathan, similar to the Keystone XL experience, what we found was that producers and refiners talk to each other on a continuous basis. There'll likely be some contracting between producers and refiners, and then between them, they'll decide which party takes the transportation capacity, and some of that conversation is going on. So it's sort of early to tell, but I think what -- based on -- similar to what Alex said to you is that there'll be interest from both sides. Who actually is the title holder of the transportation will be the subject of some of their supply and market agreements.

And I wanted to ask too, as far as getting into New Brunswick,, if that is the option that you choose, would that have to be new-build sort of beyond Montréal? Or are there existing gas pipes or other sorts of pipes you could actually use to get there?

Beyond Montréal, there are really no existing pipes that I think would be suitable. There is existing right-of-way that could potentially be utilized to Québec. And if the project were to go north of Québec, then that would be a greenfield construction for that element of it.

And just one last question, and perhaps more of a general question, but Russ, how closely do you look to something like the state of the union address tonight for indications on Keystone XL?

As I think I've said before is that the regulatory process is what I look to. As Alex said, the next major step to occur is the issuance of the SEIS, and that's where we'll take our cue from, as to what the next steps in the process are and how long they'll take.

The next question is from Elsie Ross with the Daily Royal Bulletin

Just a fast question here. Are you talking about heavy oil or light oil or a combination on the Mainline conversion?

I think our view is that, especially initially, we would think that much of the oil moving on this project would be light oil. And that would either be from sort of the Saskatchewan or synthetic crude from Alberta. Most of the refineries in Ontario, Québec, Eastern Canada, are more configured to run light oils right now. And I think initially, that would be most of what would be transported.

We'll find out, Elsie, obviously what the market tells us in terms of what it wants to ship and to where it wants to ship it to.

Okay. And the other question is, on the LNG side, what sort of expansions are you looking at in Alberta to connect up into BC?

Right now, our 2 projects both originate from the Montney area, in Northeast BC. And one is what I would call North Montney and the other is right at the Groundbirch pipeline. We are talking to not only the company that we've contracted with, Progress. But we're talking with the other companies in the North Montney area to expand our NOVA system north up in the North Montney. So we are really staying in, and we're right now in the footprint of, the Montney area and just expanding the existing infrastructure there.

Elsie, the NGTL system will be connected as a delivery point to both of our proposed projects that move to the West Coast. But as well, all of that production, if you will, in Northeast British Columbia will be connected to the NGTL system, and it will have access to all the markets that NGTL can access. So that's one of the flexibility benefits that the TransCanada brings to the table in its NGTL system, is the ability to bring on that production over the next 3, 4, 5 years. We don't see moving the gas to the West Coast until towards the end of the decade. So in between that period of time, that new production is going to look for a home and obviously being connected to Alberta and its downstream markets will be very beneficial to those producers.

The next question is from John Spears with the Toronto Star.

I have a question about the figure of $250 million that you say is the compensation that you've received from the Ontario government because of the cancellation of the Oakville power plant and moving it to Napanee. They say that, that $250 million is offset by lower payments that you will receive during the course of the contract. And they put a value of about $210 million on those lower payments that you'll receive, because it's a lower net revenue requirement. Do you agree with that figure, that the $250 million will be offset by the $210 million over the course of the contract?

Yes. In essence, there is a reduction in the net revenue requirement, which was largely created by us transferring that equipment from TransCanada to the OPA.

The equipment still will be used in the Napanee facility.

Yes, it's used in the Napanee facility.

Right, okay. But the $250 million payment that you're receiving is offset over the course by that $210 million?

Yes.

Of the lower net revenue requirement.

Yes, there is definitely a lower net revenue requirement that would be largely driven by the transfer of that equipment.

The next question is from Tonya Zelinsky with Upstream.

I'm going to change direction here. I'm wondering, has there been any updates or changes with regards to the Alaska Pipeline Project?

The latest in Alaska that we updated folks on was that we had suspended the work on the auction to come to the lower 48 with a pipeline. And have redirected our work if you will to a feasibility study with respect to LNG off the West Coast. That's ongoing. And it's a study that's being done jointly by ourselves -- by the 3 major producers in the region, ConocoPhillips, BP and then Exxon and the State of Alaska as our partner under the AGIA license. And I would say that we would expect -- I think the governor of Alaska has said that he expects that, that project will come to conclusion by the middle of February. And based on that, we'll determine our next step forward. My view would be is that West Coast LNG off the coast of Alaska is likely economic. And therefore, from that point, I would expect a conversation to ensue as to delivery points again, where and how. And then the issue that always arises in any discussions about the development of gas in Alaska, is what will the fiscal regime look like going forward for those producers. And by fiscal regime, I'm talking about the royalty rate that will apply to that production, both in terms of quantum and over what time frame that royalty rate is applied. And if they can come to a conclusion on that between the producers and the state, there's opportunity to advance an LNG project in Alaska.

Are you optimistic given that there are proposed changes to the current tax structure and royalties?

I think what you were referring to likely would be the tax and royalty structure around crude oil production, which I think has some ancillary benefits to the discussion on gas royalties. But I think the gas royalty discussion is somewhat separate from that.

The next question is from Geoff Bird with allnovascotia.com.

Sorry if I missed this earlier. I was just looking for a capital cost for the Mainline conversion project?

We haven't put out an actual capital cost number yet. And it will be dependent upon the volume, which will then drive both the line that we need to take out of service, and then what are the receipt points, what are the delivery points. And so we haven't announced a capital number yet. But I think that our view would be is it -- you can think of it as being a number that's comparable to some of the numbers that the people have used for getting a pipeline to the West Coast. Given that its existing pipe in the ground, existing right of way, we think that we can get to Eastern markets for a comparable toll, if you will, to what you can move oil to the West Coast for.

There are no further questions registered at this time. I'd now like to turn the meeting back over to Mr. Moneta.

Thanks very much, and thanks to all of you for participating today. We very much appreciate your interest in TransCanada, and we look forward to speaking to you again soon. Bye for now.

Thank you. The conference call has now ended. Please disconnect your lines at this time. Thank you for your participation.