Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2014 Fourth Quarter Results Conference Call. I would like to turn the meeting over to Mr. David Moneta, Vice President of Investor Relations. Please go ahead, sir.

Thanks very much and good morning everyone. I’d like to welcome you to TransCanada’s 2014 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, Executive Vice President and President of Development; Karl Johannson, President of our Natural Gas Pipelines business; Paul Miller, President of Liquids Pipelines; Bill Taylor, President, Energy and Glenn Menuz, Vice President & 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 Web site at transcanada.com. It can be found in the Investors section under the heading Events & 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 will take questions from the investment community first, followed by the media. In order to provide everyone with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have additional questions, please reenter the queue. Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations or your detailed financial models, Lee and I would be pleased to discuss them with you following the call. Before Russ begins, I’d like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian Securities Regulators and with the U.S. Securities Exchange Commission. And finally, I would 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, depreciation and amortization or EBITDA, and comparable amortization as well as 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. They are measures are provided to give you some additional information on TransCanada’s operating performance, liquidity, and our ability to generate funds to finance our operations. With that, I’ll turn the call over to Russ.

Thank you, David and good afternoon everyone and thank you very much for joining us late on this Friday afternoon. 2014 was a year of many accomplishments for us here at TransCanada. We resolved a number of outstanding headwinds in our core businesses. We successfully advanced several new pipeline and power generation projects. We captured more high quality growth opportunities directly connected to our core assets. We continue to improve on both safety and integrity performance placing in the top quartile to top decile of our industry and we had strong financial performance from all three of our core businesses. Comparable earnings increased 8% and funds generated from operations climbed 7% during the year. Net income attributable to common shares was $1.7 billion or $2.46 a share. Comparable earnings were $1.7 billion or 2.42 a share and as I said funds generated from operations were up 7% to $4.3 billion. Our strong financial performance combined with solid new growth opportunities and an industry leading safety performance record is strong evidence that our strategy is working. Don will provide some more financial details on the quarter a bit later, but thought I would go through some of the highlights for 2014 with you at this time. Specifically during 2014 we continue to focus on maximizing the value of our $59 billion asset portfolio. This included successfully repositioning two key long-haul pipeline systems that have been under pressure from changing market dynamics in the recent years and specifically the Canadian Mainline and the ANR pipeline systems. In addition, $3.8 billion of new assets began operating in 2014. Those assets include the Southern Lake of the Keystone Pipeline or what we call the Gulf Coast Extension, $300 million in new facilities on our NGTL system, the $600 million Tamazunchale pipeline extension in Mexico,…

Thanks, Russ and good afternoon everyone. As highlighted in our news release this morning, net income in the fourth quarter was $458 million or $0.65 per share compared to $420 million or $0.59 per share for the same period in 2013. Excluding the $8 million after-tax gain from the sale of our South American pipeline assets and unrealized gains and losses from changes in various risk management activities; comparable earnings in the fourth quarter of $511 million or $0.72 per share increased $101 million or $0.14 per share compared to the same period last year. Driving this were new contributions from the Keystone Gulf Coast Extension and the Tamazunchale Extension in Mexico along with an increase in incentive earnings from the Canadian Mainline and higher realized prices at U.S. Power partially offset by higher interest expense. In terms of our business segment results at the EBITDA level, our Natural Gas Pipelines business generated comparable EBITDA of 884 million in the fourth quarter 2014 compared to 778 million for the same period last year. Canadian gas pipelines’ comparable EBITDA of $646 million increased 46 million compared to 2013 primarily due to higher incentive earnings on the Canadian Mainline partially offset by a higher OM&A cost on the NGTL System. Net income from the Canadian Mainline was $39 million higher compared to the same period last year. With the recent NEB approval of our 2015 to 2020 tolls application, $59 million of after-tax incentive earnings were recorded during the fourth quarter partially offset by carrying charges owed to shippers stemming from a positive toll stabilization account balance. NGTL’s net income decreased $13 million year-over-year to $59 million due to higher OM&A cost that were at risk under the terms of the 2013-2014 settlement partially offset by a higher investment base. In addition…

Thanks Don. Just a reminder before I turn it back over to the conference coordinator. We'll 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.

Thank you. We will now take questions from analysts. [Operator Instructions] Our first question is from Carl Kirst from BMO Capital Markets. Please go ahead.

And just to get may be for further clarification to the extent that if this goes forward we have another straw into another basin. Can you remind me as far as the full Energy East 1.1 million barrels a day? Is that considered fully pressured up or will in some point in the future that has expansion capability?

Hi Carl it's Paul Miller here. The 1.1 million barrels per day on Energy East is the fully powered up capacity. We'll continue to look for opportunities to increase that once we are in operation but as of today the 1.1 is maxed out.

And second question if I could and I guess sort of sticking with Energy East but maybe going over to the Eastern Triangle. And I just wanted to get the updated thoughts on the Northern leg and some of the back and forth we've heard. And I guess this is clearly in front of the NEB and maybe perhaps my question can be summed up is do you see any risk for project delay with respect to some of the consternation we've seen about the Northern leg?

I'll take a first cut at it and then maybe Karl has a view as well. But both the -- I think you're speaking with respect to the issue as to whether or not there'll be sufficient gas capacity available to meet the Eastern Canadian concerns. Both the Ontario government and the Quebec governments have engaged their respective regulators to basically inform them as to how they should respond to the National Energy Board process. One of the issues that obviously they well review is, is the gas transportation issue. The Resi’s completed its report and has submitted it to the government. I understand the OEB is still in the process, I think that what we're seeing is that the incremental gas supply needs or that the -- at least the Quebec regulator has indicated that the conversion of the capacity on energy to from gas service to oil service will provide a benefit to gas consumers. They've indicated that it would be beneficial if we solicited for additional gas needs and to understand gas needs better, we have recently completed that process, we're in a process of analyzing those open season requirements. But at the end of the day that’s all about we will be complete well in advance of the Energy’s filing and I wouldn't suspect that that would be a critical path item for us and will determine what the gas supply needs are and we will make sure that the capacity is in place for that and Karl if you have anything to add to that.

Not I don’t have much to add, we will take this to the NEB as Russ said the topic of capacity will be looked out by the NEB and we're quite comfortable we have enough capacity for existing in future needs on the system.

And so just to be perfectly clear, the peak day load for Eastern Canada off our system over the last four years has been just slightly greater than 1.7 billion cubic feet a day the Triangle currently has the capacity of 3.2 billion cubic feet a day with the adjustments that we're planning on making to it, it will bring that capacity down to 2.6 billion cubic feet a day. So there is ample capacity available to meet that 1.8 billion cubic feet a day of need under almost any scenario. So, we don’t see there being an issue with gas supply in Canada.

Thank you. The next question is from Paul Lechem from CIBC. Please go ahead.

Just a first quick question to Don maybe in the earnings outlook slide that you have with the arrows going up and down and flat for Keystone. Is that in Canadian dollar, U.S. dollars, what are we looking at there?

They are in Canadian dollars.

So you’re expecting Keystone to be flat in Canadian dollars even with the exchange rates moving -- Canadian dollar moving low late in 2014, so I mean potentially does that suggest it goes lower in U.S. dollars for Keystone in 2015?

We’re just checking up Paul. So Paul it’s flat to slightly up on a Canadian dollar basis.

And then just maybe a question on the given where commodity prices are have you seen any shippers pulling out of any of these pipelines I think the proposed pipelines the Energy East, Keystone XL and any of the, ones you have underway in Alberta, Northern Korea, Grand Rapids has there been any impact from the move down in oil prices in any of these projects?

Hi Paul it’s Paul Miller here. We haven’t had any impact from the decline in the commodity price the shippers who have signed up for these pipes are still fully behind us we anticipate we’ll see some slowing in some of the growth here in Western Canada, but today all the shippers remain fully committed to all of the projects.

And is there any, contractually any ability for them to delay or move out their commitments under current scenarios?

No, there isn’t.

Thank you. The next question is from Andrew Kuske from Credit Suisse. Please go ahead.

I guess the question really relates to the financials and just your outlook for financing and I know you mentioned a little bit of your financing expectations and really the spreads you can issue on. Is now the opportunity to just to try to go and term out some debt on a longer term basis and if you were to do so and in particular on unregulated assets what kind of spreads or levels do you think you can hit?

Yes these are pretty compelling levels we would agree on that. And we do have a need on the regulated side of the business for some debt funding this year and particularly with the growth on NGTL. 30 year mining in Canada is probably in the four area pre-tax so that’s a kind of levels we’d be looking at and in that on NGTL I would be pass through the tolls. In terms of a broader financing program spent around 6 billion this year internally generated cash of around 3 which leaves us with the funding need of probably in the 5 billion area including maturities we’ll be across the term spectrum on that you saw us do some three year notes earlier so we’ll be across the term spectrum in both currencies there. But again across the entire yield curve and across all products we view these levels as compelling.

And maybe just for a bit more clarity where do you think you could issue 10 year paper on say unregulated assets or even regulated assets for that matter?

On regulated assets 10 year paper in Canada would be probably in the three area.

Okay, and that’s…

And in the U.S. probably around a 360 plus minus area today…

And then just how do you think this plays into the overall valuation of your stock and just the return expectations because obviously under the old regulated formulae that still exists under certain assets we’re really disconnected from the formulae at this point in time? And just how do you think about your stock valuation also whether just rates are so low?

Well obviously there is a very high correlation to our yield to where bond yields are at so it’s certainly a tailwind to the share price here. If your choice is investing in a stock that’s paying a mid 3s after-tax dividend or putting your money into government bonds taxable at a rate lower than that it’s from an investment proposition standpoint it’s a good new story we think we have to sell to investors there. And if we continue to grow that dividend as we’ve indicated at Investor Day and since over the next several years you are driven by the small-to-medium sized projects first and foremost. And then if we get some of these big projects over the finish line it’s another factor here that I think is on investors’ minds.

Thank you. The next question is from Robert Kwan from RBC Capital Markets. Please go ahead.

Just looking at the Mainline as you head into 2015 with the settlements I know look we’re only six weeks into the year. But just wondering do you have any comments as to how you performed so far with the discretionary and directionally when you just look at the settlement versus how you made the money in 2014, how are these tools impacted by the settlement agreement thinking about things like summer storage service, just as we think about year-over-year your ability to churn the incentives over to 10.1?

Hi, Robert, it’s Karl, and maybe I will start with just talking about the revenue generation incentives that we get. We do actually have a 8 filing still to do, a compliance filing at the end of March to update all of your numbers. So that will be coming at the end of first quarter but just generally speaking the winter this year has not been as cold as last year, so I wouldn’t expect as much incentive earnings as we earned last year. I think we earned last year about $0.08 incentive earnings kind of five net of kind of the carrying cost of the surplus cash we generated last year. So we’re certainly not going to make that the winter just hasn’t materialized the same, but we are on-track with good FT contracts this year and then we do expect to make our revenue requirement with the FT contracts, which will make up above 90% of our revenue requirement, so I think it’s a good start to the year, but it’s certainly nothing compared to last year with a very-very cold winter we had. Does that answer your question? I think the second part of your question was -- and maybe you can remind me what the second part of your question was.

Just if any structural differences with the settlement that may make it just directionally more difficult for you to earn incentives?

Well I think the incentives that we structured I must say that we are capped now we have a collar basically so we can’t go lower, so if under collect we can’t go lower than 8.7% return on equity, and if we over collect we can’t go higher than 11.5%, so it’s structurally a little different. I think last year we were much over 11.5% because of the incentives that we gathered. But strictly speaking we still have the same tools we still got the pricing discretion tools that we have. We still have the products that we can use both the firm products and the interruptible products. So I don’t see a lot of difference in the tools that we can use to earn incentives. This year it is a bit seasonally depended and it will change a little bit as we move into the future and people start converting from long haul to short haul, so that’s probably the main impact on it because once you get short haul you just have a several lower tolling probably some lesser amount earn incentives on a base toll that is lower, but with all the tools that we have I don’t see any difference this year over last year.

Just my other question is for Ocean State with the capacity auction for 2018-2019 in New England and Ocean State being in that Rhode Island pocket just wondering have you looked at expansion opportunities either on the site or near the site that you might be able to take advantage of into the future?

Yes, Robert it’s Bill Taylor here. Obviously we’re quite pleased with that result. We actually did anticipate improvement in the Rhode Island zone and that was proven out in the results of the auction that you mentioned so we’re continuingly looking at opportunities there and we do have some initiatives to look at what opportunity there may be on the site, it’s a limited -- there is not a lot of geography that isn’t used up at the site so we have limited ability to do something there, but it may also be a repowering opportunity as well.

The next question is from Matthew Akman from Scotiabank. Please go ahead.

On Western Power, is there anything you can say about your hedging over the next couple of years?

It’s Bill again. We don’t provide any forward indication for competitive reasons on kind of what our hedging approach is, as you could see from the results in the quarter, we were positioned fairly well and given the low price environment that occurred over the last quarter through that period and we will continue going forward to try to opportunistically take advantage of opportunities in the market to improve our results.

Staying with Power Bécancour, can you make any comments on the -- kind of the contract structure, there is obviously a bump up that’s occurred, is that sort of permanent till the end of contract now?

Well, the contract at Bécancour has not been revised. We did make some adjustments to the transportation contracts that were originally in place. The natural gas transportation contracts that were originally in place for Bécancour and so part of the impact you’re seeing is the result of those adjustments that we were made in respect of that gas transportation and that you can expect it we would see that continued effect to occur in 2015.

And anything you can say beyond 2015, do you expect that to be ongoing?

It may depend on the expiry of those transportation agreements and what we intend to with that going forward so it's kind of speculative at this point.

Last question the just sticking with Power on Ravenswood there was an unplanned outage in 4Q is that going to be a material thing to capacity over the next couple of years or was it pretty short?

The station is still unit 30 I should say is still being repaired at Ravenswood work on that is going well there will be some impact that will come in primarily in 2016 and a little bit into 17 that will result from have that average occur.

Thank you. Our next question is from Linda Ezergailis from TD Securities. Please go ahead.

In your MD&A you mentioned that there is a possibility to implement some operational efficiency at Keystone to improve capacity inflows. And it sounds like there is a possibility to do that even with Energy East down the road. Can you talk about what that might be and how much capacity you might unlock is that drag using agent or something else patching or?

Hi Linda it’s Paul Miller here. That’s exactly what it is on Keystone we've increased our flows probably by about 20,000 barrels per day so far by the use of drag reducing agents as well as other efficiencies that we've found in the pipeline. So we'll continue explore those on Keystone and once in operational all our pipes will explore these opportunities. So Energy East included bit with Energy East today we believe the capacity is around 1.1 million barrels per day. But we've always looking for ways to improve the reliability and the efficiency of our operations.

And just a follow-up question with respect to the landowner loss for Nebraska, can you walk us through how long that will take to resolve and what the book ends of the outcome will be I'm not a legal expert but I'm wondering what also the basis is and in terms of constitution no consideration?

So Linda it’s Alex. So we have that decision come out of the Nebraska’s Supreme Court a little while ago and basically what happened was three of the four judges found that the plaintiffs did not have standing. So given that you require a super majority to find that a law is unconstitutional the existing Nebraska legislation and the process we went through to determine the route in Nebraska was therefore valid. One of the outcomes of that though was because the decision was made basically on this lack of standing it let the opportunity open for landowners withstanding to make a claim. So that process has occurred and we have a couple of lawsuits that are seeking to determine the constitutionality of the route. I think you're going to see the same -- it should be the same process there will be trial because the only issue at stake is this issue of constitutionality it should be able to be concluded very quickly and if it is found to be constitutional by that same super majority that is the end of the case and our route is constitutional if it is on the other hand found by the trial that it is unconstitutional then there would obviously be an appeal to the Nebraska’s Supreme Court in the same manner as the previous round of cases. Once again I think the good news about this is there is only issue at stake it's the constitutionality and I think we can probably get through the two cases sometime give or take in about a year or so. The other point that I would say is in Nebraska right now we already have 90% of those easements have been signed voluntarily and in the other states along the route we have 100% of the easement signed voluntarily. So we really are talking about a very-very small number of landowners that we haven’t resolved things amicably with.

Thank you. The next question is from Rob Hope from Macquarie. Please go ahead.

Maybe just shifting a little bit North to South Dakota just wondering about the formal hearing regard the re-certification of the permit how long do you think that could potentially take?

I'm trying to remember the exact time.

I believe that our thoughts is that we would be through that process sometime and I think the hearing is in June and that we would see decision sometime around December if I recall.

Yes I believe it's set for May

So, just a bit little bit earlier than what Russ highlighted.

Well I am sorry and when would you expect that resolution?

Yes I think Q3 sometime.

Some time in Q3, we don’t have an exact date but that would be our speculation.

Maybe just one follow-up question broadly speaking with the commodity price environment and your access to capital are you taking a harder look at acquisitions either for individual assets or potentially larger packages?

No question, we've been through these cycles before as a company and there is several assets out there in the marketplace that we covered but obviously in certain market cycles they're not available to us and so we'll remain attentive to that, I think if you look back in our history when we have seen market downturns like this we have acted, so we bought a GTN in that kind of a environment we bought the Northeast Hydro asserts in that kind of environment. And so several assets that we've acted on, and I do believe that that is a possibility if we see a sustained downturn in commodity prices there could be really good assets that are freed up and we have the financial capacity to actually act on that currently. So that is one of the reasons why we try to maintain a strong balance sheet and financial flexibility to do those things. And if we see some of our capital programs being pushed out like Keystone XL and that sort of thing again it gives us more capacity to be able to do those kinds of things in the short run.

Thank you. The next question is from Steven Paget from FirstEnergy. Please go ahead.

When you consider your U.S. gas pipelines and contracts are all these pipelines now ready for at least potential dropdown in the TC pipes?

Ys Steven it’s Karl. Yes I think that we said years ago, I think on ANR we want to do a little bit of work selling and we have actually sold a route now. So I think all the assets are what I would call dropdown ready. I'll defer this further comment on this to Don but we're in a process right now kind of dropping down one at a time. And we've made a commitment to keep that process up. So I would say there is nothing inhabiting us from moving these assets into the LP at the proper timing.

And I will just echo comments made at Investor Day where we're on the conveyer belt approach here the intent is to put out cash from these assets but well maintain the control of them and being cognizant of the capacity limitations at the LP to absorb these assets. So we think the LP has capacity of a $1 billion dollar plus per annum, we've got buyers in our GTN is set to close here in this quarter and then we'll continue to move forward with the rest of them. So there has been no change to the strategy we outlined back in November.

This question I guess would be for Bill or Alex. Can I ask what the internal timeline might be for securing the future of Bruce Power units 3 for 8 as far as the media reports at the unit for refurbishment process will begin in the summer of 2016?

Sure, I can try and give you a brief update on that. The discussions are being led by Bruce Power and there is still actively in those discussions with the ISO and representatives from the government of Ontario. So there is not really any detail I can provide on that at the moment other than to say that the discussions are still ongoing. As for the timing I would say it's really premature to try to focus on any single timeframe at the moment given the status of those discussions.

Thank you. The next question is from Carl Kirst from BMO Capital Markets. Please go ahead.

I was just curious Russ on XL, you guys obviously responded to the EPA letter. I haven't seen anything in the public record with respect to the state department but have any of the other agencies waved in Homeland Security on Energy Security et cetera that you guys are aware of?

I believe that the state department said that all of the agencies have commented, we don't know what's in those comments but my understanding is they have commented and at least to this point in time the state department has said that those are internal documents and they're not making them public.

And then two micro questions if I could just one Don, can you actually say how much right now of 2016 net currency exposure is floating versus a hedged, near 80% hedged or something less than that?

Sure let me just give you some color on the currency. I guess my earlier question I should have clarified that the when I talked about Keystone being flat to slightly up on a Canadian dollar basis. I had a more modest exchange rates factored into that than the current spot levels we’re seeing today. So for 2015 we're largely hedged, there might be a couple of pennies pick up in there but it's not material. Looking out into 2016 and onwards our run rate is about 600 million after-tax U.S. dollar income that is exposed that is after natural hedges in the form of U.S. dollar debt so that’s before financial terms but after U.S. dollar debt. So for every $0.10 move you get year-over-year you’re looking at something in the order of $60 million of after-tax income that would fall to the bottom-line.

Don sorry that would be on an unhedged basis then so you’re indicating that we don’t have any hedges laid on for 2016?

Not beyond U.S. dollar debt and interest associated with it, so that would be it’s about 150 million a quarter run rate going forward 2016 onward of exposed currency from the P&L’s perspective.

Understood, I very much appreciate that. And then last question if I could just a very small one Bruce Power and you guys may have already said this so I apologize. But Bruce Power this quarter I think it was Bruce A there was an out of period generation adjustment can I get the size of that?

That would have period generation adjustment?

There was a quote deem generation adjustment of a prior period. I’ll follow it offline.

Yes, we’ll give it a quick look Carl but we’d be happy to follow-up offline if it’s -- when they have it.

Yes Carl it was just an adjustment for there was a substation outage that was the classified or qualified deem generation in the third quarter and it was trued up in the fourth quarter our share of that was forward pay through…

Thank you. Our next question is from Andy Gupta from HITE Hedge. Please go ahead. Mr. Gupta your line is open please proceed.

Just a quick follow-up on your comment about there being capacity at GCP, it seems with the share price that’s come off since last November do you still think GCP has got the capacity to absorb $300 million of dropdowns?

Yes, we do. The share price is still fairly robust I think it’s high 60s.

Yes.

Yes and as well at current debt levels that forms part of the equation of GCP as well in sustaining these assets to that levels that funding levels are more attractive they were back then.

And from what I understand from the Investor Day as well is that these drops which was certainly about $5 billion of proceeds to TRP it is really to fund your near-term projects like Energy East, the Keystone XL that’s not being funded by this, this is more the near-term $12 billion to $13 billion of projects?

Yes, we’re not quoting any specific drop to any specific CapEx project but collectively the $12 million of high visibility small-to-medium sized projects we feel quite comfortable that there is a logical home for 5 billionish dollars of proceeds from these dropdowns for that portfolio.

Thank you. We will now take questions from the media. [Operator Instructions] We have a question from Julian Arsenault from The Press Canadian. Please go ahead.

Regarding Energy East that it seems less and less likely that there will be marine terminal in Cacouna. Why wait until the end of the quarter to confirm the news?

It’s Alex Pourbaix, as Russ said in his comments we expect to announce that in Q1 it doesn’t mean that we’re going to wait to the end of Q1 but there really is a lot that goes into the discussion and the analysis of this. But we expect to make a decision fairly quickly on that.

Is it possible to realize Energy East without the marine terminal in the province of Quebec because I mean there is a lot of positioning and some other town that has been mentioned to be a potential site this seems open to get one?

Sure I mean I think the number one priority for the project is that we ensure that we are connected to the refineries in Quebec and I think under any option we’d be looking at that that would obviously continue assuming that that was the case there are any number of configurations or options that could be anywhere from locating another terminal in Quebec to having one terminal in New Brunswick. So that’s actually the process we’re going through right now to find out what are the best of the options.

But you’re confident that you will have a marine terminal in Quebec?

What I am saying is I am absolutely confident that we’re going to be connected to the Quebec refineries and we’re doing that analysis of where or if we have a terminal in Quebec and that work isn’t completed at this point.

And it’s a triangulation of commercial interest and environmental interest and job creation in those kinds of interest and within there we’ll try to optimize the answer to maximize the benefits of that to minimize an environmental pack and do it in a way that’s economic for our shippers that’s the makings of a good project and a win-win-win for everybody. That’s a complex analysis with lots of stakeholders involved and that’s why it’s taking us the time to get through this process.

And maybe just clarify, there is a lot of news reports here saying that you have already quit on the Cacouna project maybe just finish on your spend on this?

I think what we said at the time that we put all the work on the hold remains true and that was we take the concern over the beluga whale in the St. Lawrence very-very seriously that is why when that recommendation came from that Federal Commission then we immediately put all work on hold and whatever resolution we come to we’re going to make sure that it’s a resolution in our minds will absolutely protect that population of whales and beyond that we’re just once again doing that analysis to see sort of what options look the best.

Thank you. Our next question is from Ben Dummett from the Wall Street Journal. Please go ahead.

Could you just elaborate on the reasons behind doing the Upland pipeline, I mean, you really should reference the fact that there is all this Bakken oil that’s been moved by rail, but is it just a matter of trying to win share of that business?

Hi, Ben, it’s Paul Miller here. I think start off with our business model is -- we’re business responsive and where we’re acting two desires in part for market access and then desire by the producers to get some of their product off the rail, and so in response to that desire and to off of that market access, we went to an open season to gauge what sort of interest was there, we were able to secure enough contracted volume to move forward with the project and provide that access for those Williston Basin producers. We will -- as Russ indicted in his prepared remarks we have contracted 70,000 barrels a day that will move on the plant and connect to Energy East and we will also provide transportation services within the Williston Basin from various gathering systems from various feeder pipelines to connect with other pipelines beyond Energy East to take barrels out of the Williston Basin. And we will continue to provide the transportation for the Bakken producer once we move forward with Keystone XL we’ve set aside 100,000 barrels a day for the North Dakota producer and Montana producer on Energy East as well on Keystone XL as well. So it’s a combination of market demand and where those barrels want to go to and it’s an opportunity that we looked at and responded.

And just at the macro-level there is no question that the production is up in North America across the border, Kenya production is up since we made our application on Keystone by about a 1 million barrels a day and U.S. production is up by about 2 million barrels a day. All of that production is moving on rail today and it wants to get off rail as quickly as possible and so those producers are talking to TransCanada and other service operators, pipeline service operators, to look for alternatives and to move it off the rails onto a less extensive more efficient safer system, and so I think you will see more of this down the road where people will try to find innovative solutions to move that at volume off the rail and this is a actually a visible volume that has been moving for several months from the Bakken by rail though Canada right to refineries in Quebec and in New Brunswick and this is a safe solution to optimizing that movement.

And then how long is the stay Upland pipeline? How many miles, how long would it be like…?

The Upland pipeline itself I believe it is about 300 kilometers or about just under 200 miles, I can validate that for you if you like.

That would be good if you could just did that analysis and just one last thing you’re going to need a State Department approval for this, I mean given this difficulties that you have had with Keystone, I mean, there is a little irony here, I mean do you expect the same kind of difficulties?

I really can’t tell you that this has been an extraordinarily process, and our historic experience is of gaining approvals across the border has taken 24 months, other pipelines that have exactly the same characteristics have taken 24 months. This particular one has taken 6.5 years. I hope that’s an anomaly in Canada U.S. trade of energy and that isn’t the situation going forward, but obviously the market isn’t waiting for regulators to catch up with their decisions they are moving the oil now, so my view is eventually that oil has to move and eventually we will obtain the permits while that will be a Keystone XL permit or the permit for a pipeline like Upland’s and these are necessary pieces of infrastructure that are required to efficiently move volumes that are being produced today between production locations and market it is used, it is a necessity that has to be done and has to be done safely but these things have to get completed.

That’s Russ that spoke there right?

Right.

And Ben it's Paul Miller again I misspoke earlier. Upland pipeline it is 460 kilometers or 285 miles.

Thank you. Our next question is from Jennifer Dlouhy from Houston Chronicle. Please go ahead.

Thanks for taking my question. Most of which has been asked. But with regards to Upland could you talk about the potential border crossing where that would be located if that’s been determined at this point?

Hi Jennifer it’s Paul miller here it hasn’t been determined definitively but it will be between Saskatchewan and North Dakota if you look at a place called Moosomin Saskatchewan go straight Southeast it’s a point just East of the Manitoba, Saskatchewan border so beyond the probably Central North Dakota and Eastern Saskatchewan is the best I can provide. But straight South Moosomin, Saskatchewan is a best guess right now.

Thank you. The next question is from Iris Kuo from Argus Media. Please go ahead.

In the past you've talked about building a rail bridge in lieu of or in addition to Keystone XL. Just wondering where you are with that project right now?

Hi Iris it’s Paul miller here, we continue to explore rail as a transportation solution for the producer shipping a product from Keystone XL not necessarily a Keystone XL bridge. But a reflection of the producers having to get to the market until pipeline is developed. And as we said previously we do believe rail will be a permanent part of the producers’ transportation solution, impart to access niche markets and impart to manage around kind of the lumpiness if you wish of pipeline implementation. So we continue to work with a number of perspective shippers in this regard it's something that they want to move forward with it's something that we’re working together with to bring to fruition here it just takes times because these are major decisions for a lot of these producers and it's a type of transportation that they haven’t used traditionally. So it's just a bit of a learning curve as well so it has taken some time a little longer than we thought and had hoped but it's something we are still pursuing.

Do you have a timeline for when you might make a decision or is it just ongoing?

It's pretty much ongoing once we typically disclose a project once we have it locked down with all the commercial support. So we'll continue to pursue the commercial support and make the appropriate announcement at the time.

And have the current low oil prices impacted at all the shipper interest in the rail project?

Not really the ultimately the net backs are going to determine rail usage and we have seen some softening of rail transportation rates not as much as I would have anticipated. But I think it becomes almost self fulfilling as we see increased production you see bigger differentials and lower net backs so if you can't access efficient transportation. So it drives people to pursuing well and the producers are taking a long-term respective there, there is nothing worse than having traffic reductions. So they're making long-term commitments on resource typically out of Canada here that has 100 year life and so they want to ensure that they have the access to the market that they need to realize on the investment in this upstream. So we haven’t really seen any softening in the motivation.

And finally could you give us some sense of what flows are right now on the Gulf Coast Pipeline?

Yes the Gulf Coast flows about above 400,000 barrels per day, and probably just under 400,000 barrels per day.

Thank you. We have no further questions at this time. I would like to return the meeting back to Mr. Moneta.

Thanks very much and thanks to all of you for participating this afternoon. We very much appreciate your interest late on a Friday afternoon before a long weekend for many. So thanks again and we look forward to speaking to you soon. Bye for now.

Thank you. The conference has now ended. Please disconnect your lines at this time. And we thank all who participated.