Good day, ladies and gentlemen, welcome to the TransCanada Corporation 2013 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, sir.

Thanks very much, and good afternoon, everyone. I’d like to welcome you to TransCanada’s 2013 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, Natural Gas Pipelines; and Glenn Menuz, our 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. 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 more 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. And finally, I’d also like to point out that during the presentation, we’ll refer to measures such as comparable earnings; comparable earnings per share; earnings before interest, taxes, depreciation and amortization or EBITDA; and funds generated from operations. These and certain other comparable measures do not have any standardized meaning under 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. With that, I’ll now turn the call over to Russ.

Thank you, David, and good afternoon, everyone, and thank you for joining us today. 2013 was a very successful year for TransCanada. We resolved many of the headwinds at Bruce, at Sundance, at Ravenswood and on our Canadian Mainline, headwinds that were constraining our financial performance. In addition, we secured an unprecedented $19 billion of new, high-quality infrastructure projects that will position the company for growth well into the next decade. And our portfolio of blue-chip assets continued to deliver stable and growing cash flow and earnings. All 3 of our core businesses, gas pipelines, oil pipelines and energy generated strong earnings and cash flow in 2013. Net income attributable to common shares was $1.7 billion or $2.42 a share. Comparable earnings increased 19% to $1.6 billion or $2.24 per share, and funds generated from operations were up 22% to $4 billion. The strong year-over-year growth in cash flow and earnings were primarily due to the return to an 8-unit operational nuclear site at Bruce Power, the first time all 8 reactors have run for a couple of decades. Higher western power volumes due to the return of service at Sundance A and increase in New York capacity prices, growth in our NGTL natural gas pipeline system rate base and a higher Canadian Mainline return on equity due to the NEB's restructuring decision made in March 2013, all contributed to the growth. After adding approximately $8 billion of new projects in 2012, we continued to build our portfolio of commercially secured projects by adding an additional $19 billion in 2013, including the Prince Rupert gas transmission project to transport natural gas to the B.C. Coast, further NGTL expansions and the largest company -- project in our company history, the Energy East pipeline, which is a combination of a newbuild and…

Thanks, Russ, and good afternoon, everyone. Before I review the fourth quarter results in detail, I'd just like to reiterate a few of Russ' key messages. Earlier today, we announced a 4% increase in the common share dividend. This marks the 14th consecutive year the board raised [ph] the dividend. Our fourth quarter and overall 2013 financial results were strong and reflect our diverse portfolio of high-quality energy infrastructure assets, including $3.5 billion of new assets that were placed into service over the past 15 months. The solid momentum is expected to continue heading into 2014 as approximately $4 billion of new assets are expected to be brought into service this year, including the Gulf Coast project, the Tamazunchale pipeline extension, the acquisition of the remaining 5 Ontario solar facilities and ongoing expansions of the NGTL System, all of which are expected to positively contribute to future results. We remain focused on advancing the remainder of our $38 billion portfolio of high-quality, long-life energy infrastructure growth opportunities. All of these projects are underpinned by long-term contracts or cost of service business models and are expected to contribute to significant growth in earnings, cash flow and dividends over the remainder of the decade. And finally, we remain well positioned to fund our current capital program. In 2013, we raised $4.8 billion on attractive terms, clear evidence of our ability to access varying sources of capital in order to finance our growth plans. Now moving to our consolidated results shown on the next slide. Comparable earnings in the fourth quarter of $410 million or $0.58 per share increased $92 million or $0.13 per share compared to the same period in 2012. This 29% increase in comparable EPS was primarily due to a higher allowed return on equity for the Canadian Mainline, a…

Thanks, Don. [Operator Instructions] I'll turn it back to the conference coordinator for your questions.

[Operator Instructions] The first question is from Juan Plessis with Canaccord Genuity.

With respect to Bruce Power, you have the option to participate in the purchase of Cameco's interest in Bruce B. How long is that option good for and when would you anticipate making a decision on this?

Juan, it's Alex. We're not right now talking about the term of that option. What I think I could tell you is that it is -- it has a long enough term that we're quite confident that we'll have all the time we need to make a decision on this. And we remain very committed to Bruce, we think there's a great opportunity for refurbishment. And by negotiating this option, it gives us a lot of flexibility as to how we go forward.

As a follow-up here, capacity prices in New York have had a pretty good start to the year, almost double from 2013 levels. Can you talk about your outlook for New York Capacity prices for 2014? And also, you've indicated in the MD&A that the demand curve reset could potentially negatively impact the capacity prices in 2015 and '16. I'm just wondering if you can elaborate on your 2015 and '16 capacity price outlook.

Sure. I think the FERC just settled the capacity -- the parameters for the capacity curve reset. I think, all in, we take a look -- we, by the way, disagreed with one of the changes they made, which was they made a change in the reference unit used to calculate capacity payment in the demand curve. From our perspective, as I said, we disagreed with that, notwithstanding all in all, it probably has a relatively modest dampening impact on the actual demand curve, maybe 6% or 7%. But that's obviously only 1 part of determining capacity prices. At the same time, we're seeing -- we had a few retirements. We've had demand expectations increase. So net-net, I'm probably looking at it as pretty close to a push, year-over-year, for summer 2014 and potentially, a very modest dampening impact on '15 and '16.

The next question is from Paul Lechem with CIBC.

Just on Keystone XL, wondering what your thoughts are on the interaction between what's going on in Nebraska and the whole FEIS national interest determination process which is being run? Is there any concern that the change in Nebraska could derail the Presidential permit?

I wouldn't use the word derail. It's our view that there shouldn't be any impact on the Department of State process. The Department of State has completed its independent review of the environmental impacts of the pipeline, issued their final supplemental environmental impact statement. That said, there's always potential for delays in the process. We would hope that, that doesn't occur, but that's yet to unfold here over the coming days.

Okay and given where we're at in 2014, you commented that you need 2 full years to -- from when you get the permit to get this thing built. Is that 2 full years or 2 full construction seasons? I mean, is there a chance as you go through 2014, you could still salvage some of this year and you can still push for at least [ph] 2016 entry into service.

There's always certain things that we can do, depending on when you get the permit. But I think the most important thing, I think, is to have sort of 2 full summer construction seasons to complete the project. So there could be some things we get done in 2014, certainly that's what our objective is right now, is to understand what impact this might have on schedule and determine how we might rework our schedule to minimize the impacts it will have on the ultimate in-service date.

Just one more question, if I may, just switching gears. In the U.S. gas pipes. Any sign of things bottoming out for ANR and maybe Great Lakes? Are you seeing any sign of a turn there?

It's Karl speaking. As we reported last quarter, we did see some extra take-up on capacity coming out of Marcellus and Utica, into our Lebanon lateral. That has been paid for and we'll expect those volumes to come on over the next year or so. And right now, we're right in the middle of another open season for more Marcellus and Utica volumes and we're quite optimistic that we'll see some more volume. So certainly, I think, on throughput on that line, we've seen it bottom out and now we're quite optimistic on going through. The storage revenues that, that pipeline generally gets has not had the same recovery with the storage emptying out throughout North America here this winter. It will have some depressing impacts on long-term storage spreads. So we'll -- but again, that's cyclical as well and we expect that to come out. So I guess the bottom line is I'd say that certainly, on a flow perspective, we're quite optimistic right now with being [ph] our pipeline. Great Lakes, still about the same as it was last year. We're seeing some more spot volumes go through with the higher volumes coming through the Mainline, but nothing that I would say on Great Lakes that is structural.

And the next question is from Carl Kirst with BMO Capital Markets.

Russ, in understanding this is less than 24 hours post-Nebraska and I know you all are evaluating next steps. I guess my question is as we look at -- even if you kind of go back to putting this back under the purview of the PSC, it would seem like they have to make a decision within a 7-month time frame. Is the rebound side to just basically you're gearing up the process to actually file with the PSC just to get the clock ticking? And since we went through this process with the DEQ, does the filing -- I mean, is that something that takes 2 weeks to put together or is that something that takes 2 or 3 months to put together?

I don't have an answer to those questions, obviously. One of our options is to file with the PSC. I think as you correctly point out, a lot of work has been done already. We have provided all the information through the Nebraska Department of Environmental Quality process. I would hope that, that would obviously impact the schedule of which they could process that application if we went that direction. But it's too early to say just exactly what that looks like. We're in those discussions right now both with internal and external advisors and with the state, as well. As you're probably aware, the state Attorney General has appealed this ruling already. We have to wait and see what sort of the initial output of that is, as well as we calibrate what our strategy is. But I think what I would tell you is that my view is that the route that we picked is sound, it has been through the review process as I said at the Department of State. We will find the most expeditious route to getting that route ultimately approved and getting on with getting our Presidential permit, that's the current plan. But unfortunately, Carl I just can't give you any insight on details because we really haven't had a chance to put that together yet. But as soon as we do, I mean, we'll share that with the marketplace.

May be a question for Alex, if I could, just with respect to your view. I think Juan had asked about capacity prices, but power prices in New England have been going kind of crazy. I didn't know if you had any longer term view on that and whether or not you all were able to capture some of the benefit of that here in the first quarter.

Yes. It's a good question. I would say going into this first quarter, we were pretty well hedged. So probably net-net, some upside but not significant. And because that we do have a pretty significant load serving business in New England, we have a lot of assets, but they were pretty dedicated to serving those loads. So positive, but not knocking it out of the ballpark.

Okay. And then maybe last question, if I could, just really, more for Don in recognizing the drop-down opportunities that you mentioned for the MLP. Given that we've historically looked at that as in part, a funding tool in the toolkit, should we continue to look at that or should I continue to look at that as somewhat linked with the timing of XL and major funding expenditures, or do you see that sort of transpiring, excluding what happens with XL here?

I wouldn't link it to any specific project. We've got $38 billion coming, which gives us a comfort level that the CapEx spend and the capital requirements are going to be substantial over the next several years here. I'd look at it to be more methodical over time. There are capacity limits as to how much we can put into the LP on any given transaction. So watch for this to be paced more methodically than in any big bang transaction, where we take back paper. Ultimately, we're looking to realize cash on the transaction. So it will be over several years but with a program of this size, moving this $3.5 billion suite of assets into the LP, makes sense.

And the next question is from Andrew Kuske with Crédit Suisse. Andrew M. Kuske - Crédit Suisse AG, Research Division: I guess the question is for Karl and it's just on relation to the Canadian Mainline. And if we look at the asset in the old regime, you had a high-8s ROE and now, you're doing about 11.5%. Could you just give a sense on how are you achieving that just on the mix of volume, the tariff structure and cost reductions?

Okay. Well, for 2013, for example, we -- on our gross revenue requirement on the Mainline, which was just a little over $1.6 billion, we essentially covered it, we're a little short but as we're talking about $50 million, $60 million, so it wasn't that, that significantly short. So we are actually collecting the revenue now for the revenue requirement. We do expect in 2014 that again, we're going to collect our revenue requirement. We're only 2 months into it but we've had a couple good months on discretionary here and we're still signing up lots -- a good volume of firm contracts. So we're quite optimistic that we will cover our revenue requirement in 2014 as well. When I look forward, I see probably, 85-plus, maybe even closer to 90% of our revenue coming from firm transmission. So we're not relying on discretionary for that great of our revenue requirement right now. So I think it's in pretty good shape. I'm not sure if that answered your question, but I think we're quite optimistic in 2014 as well and we have some sales already on for 2015. Andrew M. Kuske - Crédit Suisse AG, Research Division: So I guess it's just fair to say that you feel pretty comfortable on how you've de-risked the asset with just the increase in the FT.

Yes, of course. Our objective -- I think any pipeline or capacity provider's objective is sell firm contracts on their assets and right now, we're running probably right now, about 3.2 Bcf of FT contracts on our assets, that falls off of a little bit next year because of the renewals came up but we're starting to already add that, so I'm quite comfortable that we have a pretty good balance and a good percentage of FT covering that revenue requirement. Andrew M. Kuske - Crédit Suisse AG, Research Division: And then related but jumping ahead a few years, when we look at the conversion project and really taking some of that plant out to service and putting it into Energy East, what's your confidence in the Mainline achieving and 11.5% ROE?

Well, let's -- don't forget, we have an application in front of the board right now with our settlement with our shippers. And that settlement with the shipper is essentially is with our Eastern LDC shippers. Essentially, segments are pipelined and what it does is our Eastern LDC shippers have come to us and said that they'll give a transition or bridging mechanism for our cost of capital or for cost in our entire system, if we were to build more Eastern Triangle capacity for them so that they can access more [ph] Marcellus. And so part of that is the system's going to be more heavily utilized in FT if we get that settlement approved. We'll see more volumes migrate over the short-haul from long-haul and the LDCs, of course, will give us a bridging mechanism to pay for that. As part of that settlement, our ROE will decline. We have agreed to if they were to essentially, for a long period of time, commit to covering our system cost, we agreed to a lower ROE. That ROE that we've got in that settlement is 10.1% on 40% equity. We do have a contribution that we make every year but we also have an incentive program. So we can make between 8.7% and 11.5% ROE on the pipeline. So if that settlement is approved, you will see, actually, our ROE fall a little bit vis–à–vis, what we're getting today. But then, we'll have a much longer -- a much better profile of secured cash flows.

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

I guess coming back to the Mainline here, you mentioned -- well, Mainline and NGTL. You mentioned in the MD&A that you booked incentives for both of those systems and I'm just wondering if you can quantify what the incentives were. And then for the Mainline, do you have a rough sense of how much of those incentives are from activities or tools that you would retain under the LDC settlement?

Yes, well, let's start with the Mainline, the LDC settlement has a very similar incentive program that we're under right now. It basically gives us a tiered percentage of the revenue that we get over our net revenue requirement. So yes, I think we -- to go in the settlement with the LDCs. We will have the same opportunity that we're seeing right now during [ph] incentives. Right now, as of, 2013, we earned about $14 million on the Mainline under the incentive program. And again, that incentive program was anything above our natural [ph] revenue requirement we shared and on NGTL, there was a more modest incentive. I think it was about $3 million to -- it was $3 million?

Yes, it was about somewhere in that, about $0.005, it wasn't much.

And that the incentive mechanism there really, is we have a fixed O&M charge to the customers and if we can come in underneath that, then we get to keep that savings.

Okay and that was all booked in the fourth quarter?

Yes that was all booked in the fourth quarter.

Just I guess, turning to Energy East, you've got some refined timing here. Is that just related to some delays in the regulatory application with respect to you just being a little bit more thoughtful or taking a little bit more time with the First Nations, Aboriginal and community stakeholder consultation process?

I think it's relatively simple. We're still on track to making our regulatory filing to the National Energy Board this summer, so no delay there. I think the biggest impact on our thoughts on timing is now that we've chosen Cacouna as the site for the Marine Terminal in Québec, that is significantly further east than we had originally been anticipating. And as a result, we're going to have to build more kilometers of pipe inside Québec before we get to the Marine Terminal. So just by -- with adding those, not necessarily significantly increasing the total kilometers, but increasing the amount of kilometers inside the province, we're going to have to build. We've just modestly amended the in-service date just to take account of that.

And the next question is from Linda Ezergailis with TD Securities.

I don't know if this is too much of a detailed question for the call, but I noticed that your operating working capital changed a lot in 2013 and I'd assume that it's not entirely related to growth in the business. Is it timing of something or can you walk me through what's going on there?

Sorry, Linda. Are you just looking on the balance sheet then?

I'm looking on your statement of cash flow. So last year, your operating capital in 2012 decreased by $287 million and this year in 2013, it increased by $326 million.

Yes. And quite frankly, most of that is timing, there's a little bit of a -- current regulatory deferrals in that. But there's no underlying driver to it. It's really just timing of collections and payments.

The next question is from Steven Paget with First Energy Capital.

You've got a $35 billion order book. Once you take the Gulf Coast Project off for the remainder of the decade, what's the un-risked dollar value of the potential additional projects that you are looking at adding, if any?

I'm not sure if I have a good number for you, Steven. It's obviously the -- that we're looking at numerous things. Think of the Alaska project, for example, if we have a 20% interest in a $40 billion or $50 billion project, that's $10 billion by itself. So you add on sort of bolt-ons and add-ons, things that we're looking at, I think you could easily get another number that looks like $30 billion.

And that might include Bruce B refurbishment?

That will be included in that. Obviously, that one's an over time thing. But alone, Bruce B refurbishment I think, folks are talking between $10 billion to $15 million by itself. So it's an -- it's a great question. It's not one that we've actually added up. But I think easily, you could come to a number that's equivalent approximately, to what we've actually secured under long-term contracts.

And what's the driver on your dividend growth rate? Is it a steady increase per quarter -- or per year or as a percent of earnings or cash flow?

It's more the latter, is our object -- and I'll let Don, maybe, jump in here as well. Our focus for the dividend is to move it up in conjunction with sustainable and visible increases in cash flow and earnings on a go forward basis. And so there's no sort of set percentage in mind. Obviously, we want to sort of stay in a range of a payout relative to earnings in about the range that we have been lately or less. It's probably where we'd want to be. So as we start to see visibility of earnings growth going forward, it would be our intent to move dividends in conjunction with those.

Yes. Sustainability is the key. Historically, we've been in the 70% to 80% of earnings payout range, which equates to about 1/3 of cash flow. That seems like the right place to be, which gives a good balance of cash return to the shareholder and still retain capital to invest for growth. So that -- we don't see a clear reason to move off that.

Sorry, Don, you said 70% to 80% of EPS?

Of EPS, which is about 1/3 of cash flow.

[Operator Instructions] The next question is from Matthew Akman with Scotiabank.

My questions are on Bruce and I guess, exercising or not, the option on some of the considerations that go into that. And obviously, Bruce has been in some sense, a good investment but also controversial and challenging at times. And maybe, for Alex I'm just wondering how you think about it now in terms of its desirability? And in particular, whether there are sufficient, I guess, learnings in the organization through the last process on the As, where you feel more comfortable that if you were to take this on, that it would be closer to on time and budget?

Well, I think from our perspective, you take a look at that investment, we -- when we invested in it, it was 4 units and those 4 units coming to the end of their life in about this time period, we now have all 8 units up and running and all of those units now with a time horizon out to kind of 2020 and beyond, even for the units we're contemplating refurbishments. So we certainly think, I would agree with you, it's certainly been an investment that we've had to be quite involved in. But I think overall, we've been pretty pleased with where we've got to. With respect to the issue of the refurbishment of units 3 through 8, I think those are excellent opportunities. I think you saw with the recent publication of the province's long-term energy plan, that they clearly have a view that Bruce -- an 8-unit Bruce site is a key part of the mix going forward in Ontario. I think that the focus for us is to make sure that we do learn lessons from 1 and 2. What I would tell you is that there has been -- over the past year, 1.5 years, there's been a very exhaustive review of -- sort of on the lessons learned basis. TransCanada has been very involved in that, all the way down to sort of an operational and technical perspective. And we are quite confident that Bruce and the partners have really learned a lot, but that is going to be the big issue for us, as we make a decision to participate in 3 through 8 where we're going to want to be absolutely comfortable that we've learned all the lessons from 1 and 2 and that we're not going to repeat that experience.

And just in terms of the timeframe, you talked about the OPA report and I read that. It just looks like the refurbishment timeframe from their perspective was more in the sort of 2020 or so on the Bs. But I've also heard earlier dates and I'm wondering what your perspective us on the potential timing or necessity of that?

I think Bruce will have to -- and is spending a lot of time with the government and the OPA and with OPG, I imagine, in looking at refurbishment schedules. As I've said, it is a fact that we now have usable life in these reactors out into the sort of post-2020 period. But at the same time, that tends to be around the time that you see all the Darlington units coming to their end of life and you can't be refurbishing 12 units at once. So that there has to be a discussion about what units go first, what units follow and those discussions are going on right now. And from our perspective, I think we have a relatively open-mind, to the extent that someone wanted us to move quicker on those refurbishments. Well, first we need to be very comfortable with the deal and we'd also want to be comfortable that if we're bringing the units off early, that we're getting appropriately compensated for forgone generation that we could have got out of the units.

Okay and my last question on this topic is around Cameco as a partner and I guess, the necessity. I mean, you had them as a partner in some of the units but not in the others. I'm just wondering if you feel that they are necessary as a partner or whether they brought any significant value that you'd have to make up elsewhere, especially obviously, in the fuel availability and cost.

We and Bruce maintain an excellent relationship with Cameco. I think from Russ and my perspective, they were a fantastic partner. We were disappointed to see them leave, but we understand where their strategy was going. But I think that Cameco has been a fuel provider to Bruce for decades and I think that relationship is very strong and highly valued both by Bruce and by Cameco. So I don't see that their leaving would require us to bring in any more skill set in that regard. I think we have ample skill set within Bruce to deal with any fuel issues that come forward.

And the next question is from David McColl with Morningstar.

Just jumping back to earlier questions, I guess, around Keystone XL. I maybe want to revisit comments. I think it was Russ, that you made regarding the possible idea of using rail to almost help fill any issues that you could have with the Gulf Coast connector, in terms of adequate volume or also, really as a way to offset the delayed revenue from Keystone XL. So with the Nebraska decision, dithering in Washington, I'm really wondering, is this becoming a more serious option at this point in time or is something that you really don't want to get into unless you're pulling the trigger on it?

I think that as I've said before, that option will be driven by our customers and production continues to grow. And that production needs to move to market. We know that a number of our customers have ordered railcars and they are in sort of delivery process. We know that a number of the refineries, both in Canada and the United States, are building rail offloading facilities. And we're being asked the question as to whether or not we can potentially provide bridge facilities to load tank cars both out of Canada to those locations, and if our customers want us to do that, we will do that. And so we're, obviously, seriously looking at what services we can provide for them. I'd say that the longer these delays continue, the more traffic we're going to see on the rails. And obviously, what we want to do is help our customers. I hope my comments weren't sort of meant to -- my comments weren't meant to give people the impression that our strategy with respect to rail would be a major revenue generator or that it would offset the revenues that we would otherwise achieve on the pipeline side. I mean, in and of themselves, we would expect a decent return on capital. But the capital requirements in that side of the business aren't that large. So the primary function of it would be to service our customers and to build a bridge, essentially to the time in which we get these regulatory approvals to get our pipelines built.

Okay. I don't think anyone interpreted it as a revenue offset, definitely just as a bridge. And I assume from your statement there, there's no real drop-dead that you guys are thinking for that. If it happens, it happens. If it doesn't, it doesn't?

Yes, I think there's no drop-dead in it. But what I would say is that it's going to be a necessary part of this business until such time as we get approvals. I think the industry has already indicated that they're up for that. But as I've always said, it's not a long term replacement for our pipeline. I would say, as soon as we have a pipeline in place, that will be the preferred alternative for the long term shipment of large volumes over large distances. And our customers have clearly told us that and have indicated that their foray into shipping under that scenario, really doesn't replace the long term solution of building a pipeline.

And the next question is a follow-up question from Carl Kirst with BMO Capital Markets.

Just a couple of quick follow-ups and understanding here the NEB filing with utility settlement was done in December. Is there sort of a rough expectation when you think you might get a ruling from them?

Well, the -- they did provide a comment period, where all comments now are in. I think the last -- the comment period for those in support of the settlement was 1.5 weeks ago. So all comments are in. So we're waiting for further instructions from the NEB, and we would expect them as soon as next week. But it shouldn't be too long for further instructions and at this time we don't know what those instructions will be, obviously, there were -- some people have asked for an oral hearing and we've asked for written hearing. So we'll find that out shortly here.

Understood, thank you. And then last question, if I could. Just, Russ, on Energy East, I think there was perhaps some optimism or hope, maybe that even the 900,000 barrels a day of committed volumes could even be increased. And I didn't know if there was any additional color or status you could add on those negotiations?

I think we remain optimistic that, that number will grow. There's been a lot of inbound interest in the project. But at this point in time, I'm not prepared to announce anything new, but what I could tell you is that interest is strong and my expectation is we would see a larger number in the future.

[Operator Instructions] The next question is a follow-up question from Steven Paget with First Energy Capital.

Just looking at Bruce B, could there be a sort of West Shift program to push the reactor refurbishments out to past 2025?

I think -- I don't know that I'd describe it as a West Shift program. I think there are certain things that potentially we could do to continue to add life to the units, but they are -- there are some technical differences in the B units than the A units. And so right now, we're kind of still at that -- those dates you've heard us talk about earlier. But we always are considering.

And your work so far says rebuilding the Bs makes more sense than building C and tearing down B?

Yes. No, it's -- just if -- if kind of the numbers we're looking at, even if we were to achieve an outcome that looked a lot like the Bruce, the A unit, the 1 and 2 restart, escalated to future dollars, it's still is very, very competitive power compared to the options in Ontario. So I think rebuilding looks way better than looking at any new build.

Could you please update us on the progress on Grand Rapids? I remember you were looking at beginning construction in summer of 2014.

Well, so we are -- on Grand Rapids, we are going to be in service. Recall that it is a -- we have a 36-inch bitumen line and a 20-inch diluent line. Our plan is to bring that 20-inch line into service -- early in service in 2015. And that will be moving oil via the 20-inch line with the bit of the bitumen blend line in service in 2017, and that we are still sort of in the same time frame.

Thank you. There are no further questions registered from the financial community. We'll now take questions from the media. [Operator Instructions] The first question is from Kelly Cryderman with the Globe and Mail.

I just wanted to know what gives you the confidence that the 90-day process that the State Department is currently undergoing with Keystone will not be impacted by the Nebraska ruling. Have your lawyers advised you that -- or internal advisors said that it won't impact it? Because there's a lot of people out there who are saying it could slow the process down.

I guess, the way I would answer it is that we don't know what the impact on the process will be. It's still too early to tell. Our view would be is that there's no reason that we can think of as to why the process would have to slow down as a result of the events in Nebraska.

And have you been given legal advice in that regard?

Our advisors have given us their views and that's what I'm sharing with you, is our view is, is a collection of both internal and external advisors that have told us that there's no reason why the Department of State process needs to be impacted by this issue in Nebraska. We're past the final environmental impact review and we're now in national interest determination. The process in Nebraska will have to sort itself out at the end of the day, but that's not related to what is going on at the Department of State at the current time.

The next question is from Rob Gibson with Sun Media.

It's Rob Gibson here. I'm curious to know if you've been following some of the comments that John Kerry made about climate. He was in Indonesia and he brought up the impact of the climate. And then yesterday when the President, Obama, talked about Keystone, in particular, he brought up climate change again. Does that signal anything to you, to TransCanada, about this 90-day process and the chances of it winning approval in a timely fashion?

I think there's a clearly -- the U.S. administration and other Canadian and global officials have talked about the importance of addressing carbon emissions. But I think clearly what the final environmental -- final supplemental environmental impact statement from the Department of State indicated was that the Keystone Pipeline wouldn't have an impact on either the rate of production from the oil sands or the rate at which oil is refined and consumed in the United States and, hence, the Keystone Pipeline would not have any material impact on GHG emissions. So I think that after 5 years and what is the new 11 volume set of review has come to the conclusion that the pipeline doesn't have an impact on GHG emissions. So I think that those concerns continue with respect to policy that needs to put in place to curb GHG emissions. But my view would be is that the actual facts and science coming out of the Department of State would indicate that it's not an issue that's relevant to the Keystone XL pipeline.

So I had the opportunity to speak with Hunter Harrison of CPR, and I broached the idea of, perhaps, the rail line to whether it's CP or CN, or others working with pipeline companies like yourselves, try to coordinate either a hub at the border or some such thing. He indicated there was no real development in that area, but he was interested in the idea, he brought it up. Obviously, there is some merit to it. Have you thought at all about the logistics of what that would look like?

I would say a hub at the border isn't been something that's been primary on our radar screen. I think more logical, you would see something built at a terminal or some place on the other side of the border, which is actually what's occurring today, is production companies are railing both out of Canada and the U.S. Bakken to delivery points to the United States, both to Cushing, so that they can load on to things like our Gulf Coast Project or directly to the Gulf Coast. And going forward, I think they're looking at additional terminaling facilities. If you think of along our Keystone XL route, places like Baker, Montana which would be an on-ramp for both local production, as well as potentially other production that could be railed to a place like that. I'm not saying that's a location that we've chosen or anything, but I think that those would be more logical places for us to build rail facilities, is where there is interconnection with oil pipelines to be able to move it from that point on to refinery locations. So we're looking -- those solutions would be both east, west and south, in terms of rail solutions. And those are -- those conversations are going on amongst producers and refiners and terminals as we speak.

He kind of indicated that oil by rail was only a very small portion of his business. I know that's just one railroad and just one Canadian Railroad. But is that -- does that resonate with you? Does that sound like that's right, 5% of their business? And a low margin one at that?

I can't actually speak to you, what percentage of his business, what we've seen is that rail traffic out of Canada has increased from a few thousand barrels a day to close to 200,000 barrels a day. And I think in the U.S., we're somewhere around 1 million barrels a day or more, and both of those numbers being considerably greater than they were in the previous years, and the expectation is that those numbers will continue to rise at those kind of rates until we get pipeline capacity in place. So I'm not sure how much market share there is they're picking [ph] up or what would -- what I would say is that we're looking at the number of tank cars that we're seeing rolling and the numbers are growing quite considerably.

And the next question is from Scott Haggett with Reuters.

I'm just curious, is there a limit to TransCanada's patience with the U.S. process? If this continues to be punted ahead, when does it become too much?

I think as I said before, I mean, the market demand for this pipeline hasn't gone away, in fact, it's increasing, as I just mentioned, we're seeing increasing production both in Canada and the United States. And in this case, the U.S. Gulf Coast refiners who want this oil. So the demand stays there. And as I've said before, as long as the demand stays there and our customers want this pipeline built, TransCanada will be 100% committed to getting it done. And that continues to be our position, Scott. That's not to say that I'm not frustrated and disappointed by the continued delays. But at some point in time, the pipeline has got to get built, and we've got a lot invested and this is the right thing to do. And therefore, TransCanada will stay in this thing until it gets completed.

[Operator Instructions] The next question is from Elsie Ross with the Daily Oil Bulletin.

This relates to the Canadian Mainline. And I was wondering if you would expect even more renewals, and to what extent you do and to what extent those are due to the NEB decision?

Well, we just went through -- the end of January was the last renewal period. And we just saw our renewals for the next 2 years be enacted at the end of January. And we got about 70% -- just a little less than 70% of our FT contracts were renewed. So it was a very positive event for us. And is it, in fact [ph], the result of the NEB decision? Well, yes. I would say 2 things have impacted that. number one is, the NEB decision gave us pricing discretion, which really has driven people who need firm service onto firm contract. And the second part of that, I think is that, it's been a pretty cold winter for a lot of our customers. And I think people are starting to realize the value of firm service on the pipeline. So I think the renewal period came at a good time where people actually understood the value of firm service. So the next renewals will happen as the year progresses, depending upon the expiry date of the contracts, but our last renewal provision was very successful.

Were those mostly long-haul or combination?

They were combination but -- for example, I think the short-haul eastern contracts, virtually 100% renewed. And long-haul was around in the 70% or 69%, I think was the exact number. 69% of the contracts were renewed.

And the next question is from Jeff Lewis with Financial Post.

On Energy East and the possibility of more customers signing up for firm commitments, what's driving that interest? What are you hearing from shippers? Is that a function of delays to XL?

I would say it's a combination of delays and other alternatives. But as well, production just continues to grow over time, as people achieve approval for their -- expansion of their facilities. They're in a position then to commit to longer term contracts. And so, as you see new projects get announced in Western Canada for new production, both conventional and unconventional, I think that we'll see increased interest in transportation alternatives leaving the province. And given that we have advanced Energy East as far as we have, obviously, it's a very attractive option for folks as they look at the landscape.

And does that include -- I mean, are you talking about just an increase in the firm commitments and would you then have to upsize the size of the pipeline itself? I mean, from 1.1 million to something else, just so you have that spot capacity is still available?

We will have to maintain a certain amount of spot capacity under any deregulation. We're required to do that. We're just in the process of understanding what that amount is going to be that we're going to apply for. At the current time, we don't have any plans to increase the capacity beyond 1.1 million barrels a day. But obviously, we're continuing to look at other alternatives once oil supply grows above the current available capacity that's being offered in the marketplace. Producers will begin to look at the other alternatives. And obviously, we would have our slate of other alternatives to move growing production to market.

And do you expect to make an announcement before you file -- I guess, it was mid-2014 for the project on additional commitments?

Those additional commitments aren't a necessary component of a filing. So those would be announced if and when they come about. The 2 things aren't related. Our plan is to file our application, as I said, by mid-year. And what we would hope is that as time progresses, we would continue to sign additional long term firm contracts with shippers. And that may continue even on beyond the application date.

The next question is from Rebecca Penty with the Bloomberg News.

I'm just hoping that you can get into the level of support that you have from landowners in Nebraska for Keystone, where the contracts are at with those landowners and whether the recent ruling by the Nebraska judge affects how you guys negotiate with landowners and eminent domain and that whole situation?

I'll do my best. We originally had in sort of the 90% kind of range in terms of negotiated land easement agreements with landowners in Nebraska. We're close to 100% in South Dakota, as you know, and in Montana. With the reroute, we had to start from square one with landowners along that reroute section. Along that reroute section, we're about 75-ish percent, which is actually faster than we have been able to negotiate easement agreements in other parts of the system, so we're pleased with that. So those negotiations continue. With respect to your question on eminent domain, we need an approval from some authority, whether that's the one that we thought that we had or under the PSC or some other alternative that may arise in order to exercise those rights. But as we said before, that's not our natural inclination. What we would hope is to negotiate with the landowner. And in most cases, we get ourselves to a place that's in the high 90-ish percent of voluntary easement negotiations and only a small minority, actually end up in that eminent domain process. But again the eminent domain process is really just one of setting price, it's not one of expropriation of land or anything like that. It's an easement which is the right to cross a piece of property, the pipe will be buried 4 feet to 5 feet under the property and the landowner continues to have the right of use over that property, and we pay for that right of access. And what the eminent domain process is, is one that's determining what the market value or fair market value of that right would be.

Okay I'm just hoping you can speak to the bigger picture about how important Nebraska is in this whole process because earlier you guys were talking about how this ruling wouldn't affect the State Department, National Interest Determination, but that's not the final be all end all, obviously, Obama's decision is. So I'm wondering can you speak to this latest setback in Nebraska. And do you think that Obama could just wait until that's resolved before deciding, which is what everyone is speculating?

Yes, I can't speak to what the Department of State or the administration, how they will react to this process because we said we have our views and we don't believe that there should be any connection between the two. We believe that we should be working in parallel to resolve our issues in Nebraska, which again is just ensuring that the proper authority has -- approves our pipeline route. And if it's not, the governor of Nebraska under what we thought was the current law or what was the current law, then our question is, what is our process for determining or getting approval of that route, and we will comply with all of those rules and regulations, as we have with the State Department process, and they just run on two different tracks and we would hope that they can run those two tracks can run in parallel and that there's no reason for them to run in series.

Sorry, just last question. I'm just wondering, you were speaking earlier about alternative options that you were looking at and for your next steps like what do you do, where you go from here, can you speak about any of those alternative options? One of which would be filing with the PSC, obviously.

Yes, those were the 2 options I think that people have talked about to date. Our -- the appeal which has already, my understanding has already been launched by the Attorney General in Nebraska. The other is to file with Public Service Commission. There could be other alternatives as well. And at this point, Rebecca, we just haven't had a chance to thoroughly review what our options are, what the pros and cons are and pick a path. And over the next few days we will obviously be engaged in several conversations with officials in the state and our advisors to determine what the best path is to seeking approval for the route that we now have. As I said, the existing route approval wasn't done in a vacuum, it wasn't done independently by the governor of Nebraska. It was actually conducted by the Department of Environmental Quality. All of that work has been done and sound. Any new process that is initiated would incorporate -- I would hope, would incorporate all of that work that's already been done by Nebraska authorities. In any decision that needs to be done, we just need to be pointed in the right direction as to what is the right process and we'll comply and we'll follow with those rules. My view is at the end of the day, we will receive approval of that route and underway [ph] whichever route we go in terms of next steps. And as I said, I don't think that should impact the national interest determination, which really isn't asking the question at this time, what is the route in Nebraska. It's really asking is this pipeline in the national interest of the United States. And they have full information on which to make that decision at this point in time.

The next question is from Chester Dawson with the Wall Street Journal.

Two questions. First of all, in regard to the court ruling, was this something that kind of came out of the blue or had you been monitoring it and expecting a decision.

It would've been something that we would have been monitoring. But I think as we said, our view was -- our view is that the decision -- incorrect -- and that the laws that we had made our application and had our approval under was sound, and we continue to believe that. So not out of the blue, it's something we were monitoring, but certainly, we hadn't expected that the decision would go this direction.

Okay, thanks. And secondly you mentioned customer interest in rail bridges. Can you provide a little more information about exactly where that interest lies, is it along the proposed Keystone route? Is it elsewhere, where is there interest in that type of a bridge solution?

Well, the way bridge solutions would work is you're going to -- basically you're going to load oil into tank cars at terminal facilities in the proximity of production locations. And it will move on existing rail corridors through both Canada and the United States to receiving terminals at either storage facilities in Canada and the United States or refineries in Canada and the United States. So there wouldn't be any sort of along the -- anything done along a pipeline corridor like the Keystone Pipeline corridor, for example, maybe tank cars moving on existing railways from either existing or new loading facilities to either new or existing unloading facilities at a place where you're actually going to refine or use the crude oil.

But I guess what I meant was is it as a way around Keystone or are there other projects as well where you could see that demand...

It's actually being done as we speak. As production grows, you need to move it to market and a number of projects have been delayed, not just the Keystone project. And as a result of that, rail traffic has moved up exponentially, and so I expect that to continue and the railways have the ability to accommodate more railcars, that the constraint has been in that marketplace, the availability of railcars. And what I can tell you is that railcar manufacturing facilities are chockablock full right now, delivering as many railcars as they can to the industry. So the industry is buying them or leasing them. And when I say the industry -- mostly producers and refiners are buying those railcars as quickly as possible, getting them on the tracks and what they may need is additional loading and unloading facilities, and that's probably the role that we would play in terms of adding a bridge and the likely place to put them would be at places where we already have plans for storage terminaling at the current time.

Thank you. This concludes the question and answer portion of the program. I would now like to turn the meeting back over to Mr. Moneta.

Thanks very much. And thanks to all of you for your interest in TransCanada today. We look forward to speaking with you again soon. Have a good day. Bye for now.

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