Good day, ladies and gentlemen. Welcome to TransCanada Corporation 2013 First 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 2013 First 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, President of our 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 it 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 your 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 some 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. And 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; earnings before interest, taxes, depreciations 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, everyone, and thank you very much for joining us. Earlier this morning, you heard me talk about our ongoing commitment to developing North America's energy future with safe, reliable energy infrastructure that will generate superior returns for our shareholders. Over the next 3 years, we expect to complete $12 billion of projects that are currently in the advanced stages of development. They include the Gulf Coast Project, Keystone XL, Keystone Hardisty Terminal, the initial phase of the Grand Rapids Pipeline, the Tamazunchale extension, the acquisition of 9 solar projects and the ongoing expansion of the NGTL System. We've also secured an additional $13 billion of projects that are expected to be operational in 2016 and beyond. They include the Coastal GasLink and Prince Rupert Gas Transmission projects that would move natural gas to Canada's West Coast for liquefaction and shipment to Asian markets, the Topolobampo and Mazatlan gas pipeline projects in Mexico, completion of the Grand Rapids and Northern Courier oil pipeline project in Northern Alberta and the Napanee Generating Station in Eastern Ontario. All of these projects are secured by long-term contracts and, therefore, TransCanada expects them to generate predictable and sustained earnings and cash flow. In addition to our $25 billion capital program, we continue to advance other opportunities, including the Energy East Pipeline, which would transport crude oil from Western Canada to Eastern Canadian markets. Our 3 business segments performed well during the first quarter. TransCanada reported net income of $446 million or $0.63 per share. This included $84 million or $0.12 per share for the 2012 higher allowed rate of return for the Canadian Mainline. Comparable earnings for the quarter were $370 million or $0.52 a share. Comparable EBITDA was $1.2 billion and funds generated from operations, $916 million. The restarted…

Thanks, Russ, and good afternoon, everyone. Before discussing our first quarter results, I just like to highlight a few key messages. First, all 3 of our business segments generated solid results in the quarter. Second, we continue to progress our $25 billion portfolio of commercially secured projects with the advancement of the Gulf Coast Project, the Tamazunchale Pipeline Extension, ongoing expansions on our NGTL System and the closing of the public comment period on Keystone XL's Draft Supplemental Environmental Impact Statement, all of which will serve to further diversify the company's portfolio and contribute to sustainable earnings cash flow and dividend growth in the future. Third, as Russ has already discussed, we have achieved a significant number of other milestones to date in 2013. These include receiving the NEB decision on our Canadian restructuring proposal as it pertains to the Mainline, Bruce Power now operating as an 8-unit site, with the return to service of Unit 4 and the launch of the open season that is currently underway for our Energy East project. And finally, we remain well positioned to fund our current capital program, as well as pursue other growth initiatives. Now moving to our consolidated results. Net income attributable to common shares in the first quarter was $446 million or $0.63 per share. Our first quarter results include $84 million or $0.12 per share related to 2012 for the NEB decision that was received in the period on our Canadian restructuring proposal. Excluding this and certain other minor amounts, comparable earnings were $370 million or $0.52 per share compared to $363 million or $0.52 per share for the same period last year. Higher contributions from the Canadian Mainline, Bruce Power and U.S. Power were offset by lower contributions in U.S. Natural Gas Pipelines and Western Power. I will…

Thanks, Don. Just a reminder, before I turn it over to the conference coordinator, we will take questions from the financial community first. And once we've completed that, we'll then turn it over to the media. And with that, I'll turn it back to the conference coordinator for your questions.

[Operator Instructions] The first question is from Linda Ezergailis from TD Securities.

Just a question on Keystone XL. When in your view do you think would be the latest you could get a Presidential Permit to achieve an in-service date in the middle of 2015? And can you perhaps more broadly provide us with an updated timeline on your expectation of the approval process?

Sure, Linda. It's Alex. I think probably the best way to think about this is, especially for the Northern route of the present Keystone XL route, it is -- we need summer construction periods, and we need sort of one full construction period and the better part of another construction period. So in order to be in-service in the second half of 2015, we need -- we'll obviously need a good portion of construction season in 2013 and 2014. I've always said if we're looking at a permit, we think that we can be in a position to have a permit around this summer, and we think there's ample information in front of the State Department for them to make that decision. And obviously, if it slips significantly after the middle of the year, ultimately, we would put that earlier 2015 in jeopardy.

So just to clarify, if you get a permit by this summer, then early 2015 is still possible?

I think we've said the second half of 2015 and that would presume that we get a permit sometime during the summer a little later.

Okay, great. And just a follow-up question, what are the bookends of what's possible in terms of the cost range for the Keystone XL northern leg and can you confirm the sharing mechanism in place with shippers for that? And I guess another question related to that would be, are the delays alone putting pressure on cost or there's something else playing into that cost pressure?

Sure. The way the deal works with our shippers and any cost increases would be shared 25% by TransCanada, 75% by the shippers. At this time, we think it's probably premature to give too much granularity around the cost increase. Really, what we wanted to do with that disclosure on cost is it's probably been well over 1.5 years since we updated the Keystone XL costs. And obviously, with that passage of time, there's going to be some impact, and we wanted to directionally let our stakeholders know that, that was the case. So a significant amount of the exposure would be delayed, but there's a few other elements. There's obviously interest on the capital. We've already put in place -- we did a reroute in Nebraska, which had some costs, and we've experienced significantly higher regulatory cost. So all that kind of goes together. I think -- as a lot of these costs are related to timing and schedule, I think what we'll do is we'll wait and see when we get a decision on the permit. And at that point, we'll be able to give much clearer guidance on the cost increase.

The next question is from Juan Plessis from Canaccord Genuity.

You've mentioned that you'll seek regulatory and potentially legal review on certain aspects of the Mainline decision. Can you tell us what aspects of that decision you'd be challenging? And also, you're recording your earnings based on 11.5% ROE, so you obviously believe you can generate that return over the next 5 years. Can you talk about some of the things you're doing to enhance revenue on that system to get you to your returns?

It's Karl. Maybe I'll start with the first one on the aspects of our review and variance. At a very high level, we're still working on the details of this. But on a very high level, I can say that we are trying to work within the framework proposed to us by the board. We are going to deal with things that will make that framework more viable. One of them will be the timing of when these rates go into effect. The board has set up for July 1. We think there's a couple of issues with that. Number one is that, we have 1,500 delivery and receipt points in the system. That's not very long to get the pricing and all of our customer work done by that time. And the second is, during the summer, you don't have a much opportunity to sell discretionary services. So we're going to ask for that to be adjusted. The second is how the tolls are determined. We have presented before evidence with the board that our short-haul service on the pipeline, the Eastern Triangle of our pipeline is full. At the current rates, we are full in that pipeline, and we are going to ask the board to relook at how the tolls are determined. Right now, they're determined by setting the long-haul toll and then all the other tolls being factored off that long-haul toll, and we're going to ask them to take a look at that. And we have other issues we're going to bring up with the board, like some of our service packages, alterations of our service packages to make a likelihood of us earning revenue better and how to deal with other cost that come on the system. As for earnings, the reality is they've set the firm tariff at a level $1.42, which is below the full cost of service of the pipeline. We are expected to make up the deficit by selling discretionary service either at a higher price or more volumes. Our objective is that over an extended period of time, we're going to attract more volume on the pipeline and we're going to be able to charge the discretionary services more for their service. I think the board expected a bit of a deficit upfront, and the idea is any deficits upfront will be worked off later as the price of gas and our volumes improve. So we will be using that price discretion that we get, and we'll be marketing these services and pricing these services at the markets so that we can achieve as much revenue on it as we can.

It's Don here. With respect to the 11.5% on 40%, we continue to meet the criteria to employ rate regulated accounting. And part of the cost buildup by the NEB was factoring in 11.5% on 40% return in determining the rates here. So we consider that to be the appropriate amount to record and will continue to do so.

And Karl, just another question for you. ANR, GTN and Great Lakes pipelines, this system's earnings and throughput continued to decline. Can you tell us what actions or what options are being considered to improve those earnings and the outlook for that system?

Well, sure. Maybe I'll deal with the Great Lakes for the most part here because I think that's a system that has declined the most. We are in the process of filing an application with FERC. The issue with this system, we just lost billing determinants, long-haul billing determinants. It's turned into more of a storage and a short-haul system, filling up storage in winter peaking short-haul LBC [ph] system. So we have approached our customers, and we are preparing a filing to FERC to change the rate structures on that so we collect more of our revenue from the short-haul in the storage -- seasonal storage related services. So we expect to have any negotiated settlement done by the summer or if we do not -- if we're not successful in negotiating settlement, we'll be filing an application with the FERC, and that will come probably in the fall. My expectation with that system is that once we get our new rates in place from either the settlement or the filing, that system will improve. It may not get back to where it was a couple of years ago, but I think that we can still make that system pretty deep [ph] to look in a U.S. pipeline system. As for ANR, ANR right now is just suffering from low transportation spreads. The volumes are still good in the pipeline. This is a unique pipeline. It has lots of load on it. It's got lots of volumes. It's bidirectional. The volumes are still on the system. We just said we just see poor transportation spreads. So our efforts on this system are same as the efforts we've had the last couple of years, quite frankly. We're looking to tie more load onto it. We are actively involved in all expansions of industrials and into new local distribution areas, and we'll continue to add volume onto the system on both the load side and the supply side. And we expect that this will come back as the transportation spreads improve.

The next question is from Paul Lechem from CIBC.

On the Portland pipeline, you talk about the open season there for an expansion of that pipeline. Can you remind us again what that would entail, what kind of pricing cost that would be? And also, you mentioned that it would be subject to an assessment of the implications, the recent NEB decision on the Mainline restructuring proposal. What does that mean?

With the Portland system right now, maybe I'll give just a little bit of background on that. That pipeline goes into the Boston, the New England area, and supply has been altered in that area. The production is slowing on Sable [ph]. The Depinoc [ph] is not performed as well as people thought. And the LNG that's coming in on the East Coast is sporadic at best. So there have been some supply issues there. As well, I think we've tested some normal winter, maybe in a little bit colder normal winter this year, and the demand response was greater than people thought. So there seems to be good demand. There seems to be people interested in more capacity into that system. So we are entering an open season right now, and that open season will be going on for about another 1.5 months. And we are looking for firm commitments. We have some expansion capability there that we can do if we get the firm commitments at the prices that we're looking for. As for the expansion on the Mainline, anybody who gets -- who does bid on capacity on PNG TS will need to get Mainline capacity from either the Don area or Empress area to East River [ph], which is the inlet, to the Portland system. They will need to come with us, and we will at that time hold an open season to construct a new capacity for them at that time. We currently don't have spare capacity going into the inlet of the Portland system, so they will need to contract with us. And if we get a sufficient contract, we will expand the Mainline system to accommodate them.

So where is the bottleneck on the Mainline system? It seems that the Mainline has plenty of spare capacity right now. So where exactly is the shortfall? And also, what is comment in the write up about the implications of the NEB decision on this? How does that impact it?

Well, so I guess the first question is, where are the bottlenecks? The bottlenecks on the Mainline system are in the Eastern Triangle. We'll need to construct more there. We do have spare capacity coming out of Empress, and we have spare capacity going out to Northern Ontario. But in the Eastern Triangle, we're quite full right now. So that's where we'd be looking to build. So you'll need to build that regardless of where the origination point is. And the implications of the NEB decision? Well, the implications of the NEB decision now, because of the fixed rate tolling that they have, people will have to -- when people come to us wanting transportation to the Portland -- to the inlet of the Portland system, they'll have to sign probably an incremental contract with us that will cover the full cost of that expansion.

Okay. And then if I could sneak a second one in, Northern Courier, who's at risk if that project ultimately does get canceled in terms of the sunk cost that you put into this project already? And how much have you actually spent on that project to date?

I don't have the amount right in front of me that we spent. It's not a very significant amount right now. But I think importantly, if the project doesn't go ahead, we would be reimbursed by our counterparties. And I think the important thing to remember is, even in the event that the upgrader doesn't go ahead, the Fort Hills Mine is going ahead, and our counterparties are still going to need a pipeline coming out of that mine. So we think under any scenario, there's still a pretty good opportunity for TransCanada there.

The next question is from Carl Kirst from BMO.

I was wondering if I could start -- Don, Karl, as far as the Mainline, I think there was recognition that the NEB sort of expects to start in a deficit period. Can you help us out with what the baseline of that deficit is? Maybe asked another way, what's the cash under collection at this point at March 31 relative to, say for instance, the earnings we've booked here at 11.5%? Just to kind of put us on the same page.

Well, the cash deficit right now is actually 0. The way the board has set it up is they've asked that we do a deferral that is planned, which is the long-term deferral, and that will come in every year. So we haven't actually done that yet under this program. And they've asked that we do a short-term deferral, which is actually the difference between our revenue and cost every year, and that is a TSA and that is not -- that's at 0 right now. We do have some deferrals coming out of last year that we have put into long-term deferral, but those are deferrals that were only existing and aren't incremental to this decision. So as of right now, the TSA, the total stabilization account is 0.

Another question with respect to the Gulf Coast Project part of XL and maybe the longer perhaps that the Gulf Coast Project will be standing on its own. Can you help us out with what you think the annualized EBITDA earnings power of Gulf Coast would be, say for instance, in 2014? Is this something where you would go after market-based rates? I don't believe you have market-based rates now, but correct me if I'm wrong. So just trying to get a better feel for that, the longer this project kind of is on its own.

Sure, Carl. I think we've given a little bit of guidance over the past year or so on this. And I think they're sort of 2 pieces we've given, which is number one, you can look at the capital from this project and compare it to the capital, the base Keystone system, and contribution would be roughly equivalent. I think we've also given a range of kind of $200 million a year EBITDA moving up to $300 million. What I would say is we've been pretty active on the marketing side. And so, I think we're feeling pretty positive about the contribution that this project is going to make going forward in advance of Keystone XL. We have not yet filed for market-based rates. That's something we're looking at, and we're going to see what success some of our competitors in that region have. But that is an opportunity ahead of us also.

Great. And then last question, if I could, and this really speaks to ANR and understanding that the volumes are high. Granted this is a hypothetical, but if energy transfer really does convert a piece of trunk line and take some of the excess capacity out of that market, are you expecting that to tighten up that capacity or is it by the nature of which you're flowing and more seasonal, et cetera, that may be that wouldn't tighten up?

I think directionally that's positive. I don't know how much extra volumes we would attract from that. But I think directionally, that will make the transportation values better in that area. So I think that would be positive for ANR, yes.

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

If I can just first ask Alex. Just on your comments at the end on Northern Courier, I'm just wondering -- and Northern Courier we get them out of the Fort Hills Mine. I'm just wondering what's been contemplated with your discussions is the possibility of a direct connection into Grand Rapids or an extension to Grand Rapids, something that you're pursuing or do you think that they'll want to go in a different direction?

I think they have a number of options. I think we would think that Grand Rapids would potentially be a pretty good fit for their needs also. So that's something we're definitely going to look at with them if they're interested.

Okay. But there's nothing in the Northern Courier agreement that would contemplate a direct Grand Rapids connection?

Not at this time, no.

Okay. Just the other question I've got is you're certainly not capital constrained. But if Keystone XL is pushed back into second half of '15 and if some of the other spending starts to kick up, as you evaluate new projects, do you think about if there are spending or the acquisitions are into 2014, '15, '16 even time frame. Have you been thinking about trying to increase hurdle rates or rationing capital kind of in that 2- to 3-year period?

I'm not sure if I truly understood your -- Robert, it's Russ, and maybe Don might want to jump in here as well. But I think your question is, how are we going to finance essentially if we're so fortunate as to have all of these projects approved? What does that mean for our ability to fund them? I think the way we're looking at it right now is we'll use, as I said, all the traditional sources of capital that we have in the past, starting with the cheapest one, which is our cash flow and then our debt capacity in preferred securities. I think that you can expect us to be using our MLP a lot more actively than we have in the past. We've always said that, that's a financing vehicle that's available to us to the extent that we do get capital constrained. And then obviously, we'd look to the balance of our portfolio. Are there other certain assets in our portfolio that are fully valued and may be more valuable to others than they are to us. It's kind of a stack up of the way we look at it. But also look at with some of these projects there, they're open to strategic partnerships. And in the case of our LNG projects, for example, those counterparties still have the option to take up some equity in those projects. So we're trying to be as flexible as we can in going after those projects. I wouldn't say that we've moved our hurdle rates yet in terms of a method of rationing capital, but we were [ph] able to, I think, ration our capital in a way that we have allocated it all to this fully contracted -- long-term fully contracted kind of structure and away from sort of commodity exposure or other kind of market exposures that's unique tied in the industry to be able to capture these opportunities. And I think our thinking would be is as long as they're soundly contracted, and if you think of those projects like the LNG projects, for example, which are sort of a cost to service like kind of approach, we're not taking construction risks, we're paying back our money if they don't go forward. Those are conducive to other forms of financing, like strategic partnerships or other things down the road. So I think that's where we probably turn our heads to. As long as we can keep the contractual structures tight and valuable, then I think financing isn't going to be an issue at the kind of hurdle rates that we have in place right now. I don't know, Don, if you want to add to that.

Yes, I'll just concur. Our hurdle rates aren't that dynamic over time. They're fairly sticky. And we're not devoid of opportunity, Keystone XL aside here over the next few years. Just to give you a sense as to what the capital program looks like, let's say, through 2015 over this 3-year period right now, we've got about $4 billion of oil projects, Gulf Coast and the Alberta regional opportunities, about $4 billion in the gas side with NGTL Mexico and some pre-spend on our LNG projects getting to final investment determination, which amounts are recoverable if they don't go forward, and then $3 billion of other stuff, including solar, that could -- the ramp-up of spend on Napanee and the like and maintenance capital. So that gets you to about $11 billion between now and the end of 2015. There's probably another $1 billion to $1.5 billion on NGTL that we haven't filed for yet in terms of connecting gas for Prince Rupert. So you're getting into that $12 billion to $13 billion range without Keystone XL. So the plate is not empty but, in our view, certainly manageable.

And in that $4 billion, Don, so that's without Keystone XL. Does that include, at least in the back end to that, anything for Energy East?

No. We've got a couple hundred million to development work upfront but nothing beyond that. So you're kind of in that $12 billion range now through 2015 without XL and without any material post filing spend on Energy East.

The next question is from Andrew Kuske from Credit Suisse. Andrew M. Kuske - Crédit Suisse AG, Research Division: I guess just a point of clarification on the Mainline accounting for the quarter. You did book the 11.5% ROE. I guess the question really is, what portion of that was cash? Was it all cash in the sense that you received it or what portion would wind up with accruals or deferrals?

So it's Glenn here. Under the direction of the Mainline decision, obviously we had an increase from our 8.08% return that we were recording last year up to 11.5% retroactive to January 1. We are not allowed to go back and re-invoice shippers from 2012. And as directed in the decision, that increase forms part of a long-term deferral that Karl was referring to earlier that was already in existence. So that income, if you would, will be recovered over time with also a regulated return on top of it. Andrew M. Kuske - Crédit Suisse AG, Research Division: So is it fair to say just really in the quarter if you looked at it on a true cash basis, you're probably, given the decision timing was about March 27, you were really 8.08% through the quarter and then the differential is really on this long-term deferral?

I think the other thing to factor in there is that we're also under interim tolls right now. And as a result in the winter season, we are collecting that, and that will be addressed and dealt with in the future. Karl, anything more to add on that?

Yes -- no, I don't think I have anything to add more on that. Our collections in the first quarter under these interim tolls were probably greater than our cost.

They were.

The way it works is we've kind of collect more of our cost service in the winter and in the peak months and then less in the shoulders months. So I don't know the exact number, but I don't think it's a fair statement to say we didn't collect it.

The amount that we've, as Carl would say, over collected or, what I would say, the excess of our collection under interim tolls versus our underlying revenue requirement was a little over $100 million or $140 million in the first quarter. Andrew M. Kuske - Crédit Suisse AG, Research Division: Okay, that's very helpful. And then I guess just a bigger broader question but still on the pipeline space, and it's probably to Russ. Could you give us any color and comments and just general thoughts on Representative Terry's proposal, the legislative proposal to really avoid the need for Presidential Permit for Keystone XL?

Can you say that one more time? Andrew M. Kuske - Crédit Suisse AG, Research Division: So the Energy subcommittee have gone through the process of Representative Lee Terry with his proposal to introduce legislation eventually that eliminates the need to have a Presidential Permit.

Well, I guess -- what I guess I would say is -- I mean, obviously, we appreciate the sentiments of that kind of proposal, anything that accelerates the decision-making. I mean, we have been at this review for 67 months, and there's not much left to say so let's get on with the decision-making. That said, our focus isn't on legislation. Our focus is on answering any additional questions that arises from the regulatory process, and that's what we're focused on right now. And that we just got through the comment period on the draft environmental impact statement. Our next focus will be on answering any questions that arise during [ph] the national interest determination. Andrew M. Kuske - Crédit Suisse AG, Research Division: And then realistically the timeline, just excluding the legislative kind of option, you're thinking late summer for a actual Presidential Permit to be granted?

Well, I guess what I'd say is, it appears that we're through the comment period now. The last time that they received comments on a draft environmental impact statement, it took them something greater than 60 days to get to a final environmental impact statement. The Department of State said that it will get to a final -- it will issue a final environmental impact statement. They had a lot of comments. So 60-plus-ish days is what we were kind of thinking around that process. Then the National Interest Determination last time, they specified a time frame of 90 days. We would argue that the time frame could be shorter than that, given that 79 days had passed through that period last time. That said, I mean, they have to specify that time, and they haven't specified that time frame yet. And that's what kind of leads you to those kind of time frames that Alex mentioned. But that's the amount of certainty or clarity that we have in the process today, and we continue to work our way to make sure that we're ready to start construction at that -- when it comes to a conclusion. It's just difficult to put a pin in when that's actually going to occur. So we would hope, as I said, in that sort of summer to fall time frame that we would see a decision. But as I've said, we've been at this for 67 months now, and the process, I think, will take however long the process takes. And our objective is to work with everyone in a cooperative way to assure that they have full information to make a decision.

The next question is from Ted Durbin from Goldman Sachs.

Just want to talk about the Mainline conversion or, I guess, Energy East. You've talked about marketing the 850,000 a day. I guess, how many -- how much in terms of volumes would you actually need to go forward? I'm assuming that's somewhere less, south of 850,000. And then can you give us a sense at all of what kind of tariff you'll be marketing to get to different points on the Energy East Pipeline?

So I would say that the project is sort of at the upper end would be about 850,000 barrels. We would be able to go forward commercially with significantly less than the 850,000 barrels, and I'll probably be a little coy on that for the time being. And we're talking about a toll to get to kind of Québec and out -- potentially out to Eastern Canada. You're talking about the range -- it's sort of in the $5 to $7 range depending on -- once again, depending on size of the project and how far we go.

Okay. And presumably that would vary somewhat sort of light versus heavy?

Yes.

Got it. Okay. And then can you talk about -- just shifting over to the Mainline and, I guess, the ROE there, the 11.5%. Is there any read-through we should have on that into, say, the NGTL System or maybe even some of the LNG projects? Might you be looking for a little bit better return than what you've historically got on the Canadian pipes on an ROE basis?

I think it's a fair comment to say that the regulatory framework has changed with the decision on the Mainline, and that this will be -- this should, in our opinion, apply to the NGTL System as well. So we're in the middle of settlement discussions right now. I don't think I'll talk about specifics of our discussions, but it's not lost on us on that there has been some change in the regulatory framework and that we would be looking for changes for all of our NEB-regulated pipelines, yes.

Okay. And is that true for the LNG projects as well?

I'd say that the LNG projects are already contractually set in terms of the return on equity. But what I would tell you about that return on equity, it's more in the range of this recent decision than past decisions. And certainly, we've always thought that the return on equity on the Canadian Mainline and other Canadian-regulated businesses are too low, and that obviously influenced our negotiating position in securing those new projects. So they're already in that neighborhood.

That's very helpful. And if I could just do one more, just on Keystone XL and the delay here in the in-service date. I'm just -- can you talk about how the contracts look as the time frame continues to go out and if we do bleed past the summer for the permit and potentially into 2016 for the startup, how does that impact sort of the contracts you have in place?

I think the most important thing is that we, at this point, still enjoy the very strong support of our shippers for this project. I think they see Keystone XL continuing to be a very attractive route to get their oil to market. So I think that's the first point. And under the second point, under any of the scenarios that we're looking at, we think we are -- we're quite confident that we'll be able to get the pipeline in service without putting at risk significant shipper commitment.

The next question is from Juan Plessis from Canaccord Genuity.

At Bruce Power, Alex, how much forced outage expectations of Units 1 and 2 is baked into the expectation of a mid-80s percent availability at Bruce A?

I don't have that right in front of me. Glenn, do you have a...

Yes, as far as the units being a little -- or ramping up and filings their ramp-up, that's supposed to end quite soon.

Okay. So the forced outage expectation is baked into that mid-80s percent?

Oh, yes. The forced outage is already bared [ph] into there and it would -- as they ramp up would be consistent with other units.

I think the number that I saw most recently was somewhere in the neighborhood of 3%, which would be above. So that's what's baked in, and that is above what we would normally see as a forced outage rate. It would be closer to like 1-ish or so.

Yes, I think -- and sorry, I didn't quite get the question. That was my recollection. I think it's somewhere around 3% and is particularly seen those as new units. We would expect to see that go down relatively significantly after the first year.

Okay, great. And Don, how much of the $40 million of business interruption insurance recovery at Bruce related to 2012 and how much was related to 2013?

Juan, it's Alex. I'll just give a quick explanation and then that might be helpful. When we were bringing Unit 2 back from the refurbishment, you'll probably recall, we had a generator failure on the unit, which slowed down and obviously slowed down bringing Unit 2 into service. But in order to sort of maximize the value of the site, what we did is we took some generator parts out of the Unit 4 generator and -- which worked because we were putting the Unit 4 generator on one of these life extension outages. And as a result of that, we had attributed some portion of that insurance recovery to 2012 and to 2013 because it had a knock on impact on bringing Unit 4 back later than would have normally occurred.

It's Glenn here. After you take into account insurance waiting periods under business interruption and then factor in the full time period, it does span from 2012 into 2013. And without getting into the specifics, a little over half of it would be due to 2013.

We will now take questions from the media. [Operator Instructions] The first question is from Chester Dawson from Wall Street Journal.

I'm sorry to make you repeat something you've explained quite a bit today. But you could you go in a little bit deeper on the decision of the catalyst for your new timing on when you think Keystone XL could be up and going, provided you get the permit? And how likely is it that it would go even beyond that into 2016, 2017? Are you absolutely confident that we would be late 2015 now? Or is there an increasing likelihood it would go beyond that? Secondly, with all of the debate over that and the Northern Gateway, are you looking into other potential opportunities, for example, going up north through the northwest territories for an Arctic means of transmission? Or what are your thoughts on that as a viable reality for a pipeline?

I'll take a shot at it, this is Russ. I think the first question on in-service timing, I mean, in-service timing is directly related to when we get a permit. And at the current time, as we said, that process continues to be delayed. We're in a position now where the comment period has closed. The Department of State has to sort out those comments. That's a 60-day process and then potentially a 90-day process on top of that for a National Interest Determination, which gets you through the summer. But hopefully, we'd see a decision in that kind of time frame. But if that time frame continues to get delayed, then our project continues to get delayed. And that's just sort of the reality, and I can't really sort of nail down what impact a specific period of time would have at this point in time on the back end of that. We're still expecting a late 20 -- a latter half of 2015 as an in-service date. With respect to other alternatives, I think that we spent some time today and over the last few months explaining what we think is one [indiscernible] viable alternative -- not really an alternative, but something that's going to be necessary anyway is the conversion of some of our Mainline gas capacity to move oil from Western Canada through to Eastern Canada delivery points. And to date, we have had considerable positive interest in that. And I'm very confident that at the end of our open season, we'll have sufficient shipper underpinning to move forward with that project. It can move about 850,000 barrels a day from west to east. With respect to going north, I mean, the marketplace is innovative, and it continues to look at all kinds of alternatives. What we know is that what drives the production of oil and of any commodity for that matter is economics, and there is considerable economics in producing the Western Canadian reserves, the oil sands reserves, and the third-largest reserve in the world. And the folks that are investing in it are folks from all around the globe. And they will figure out a way to get their product to market. And Keystone XL is one route to get product to market. But we know the world needs oil, and there's oil available there and the marketplace will figure out how to get it from A to B. And I'm 100% confident that, that is what is occurring, and that's what will continue to occur.

[Operator Instructions] There are no further questions registered at this time.

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 talking to you again soon. Bye for now.

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