Russ Girling - President & Chief Executive Officer Don Marchand - Executive Vice President & Chief Financial Officer Alex Pourbaix - President of Energy & Oil Pipelines Business Glenn Menuz - Vice President & Comptroller Greg Lohnes - President, Natural Gas Pipelines

Carl Kirst – BMO Capital Ted Durbin – Goldman Sachs Linda Ezergailis – TD Newcrest Juan Plessis - Canaccord Matthew Akman – Macquarie Pierre Lacroix – Desjardin Securities Robert Kwan - RBC Capital Markets Andrew Kuske – Credit Suisse Petro Panarites – CIBC Faisel Khan – Citigroup Sam Kanes – Scotia Capital Brian Horey – Aurelian Management Juan Plessis – Canaccord Steven Paget – FirstEnergy Justin Amoah – Argus Media John Spears – Toronto Star

Good day ladies and gentlemen welcome to the TransCanada Corporation’s 2010 Third Quarter Results Conference Call. I would now like to turn the meeting over to Mr. David Moneta, Vice President of Investor Relations and Corporate Communications. Please go ahead Mr. Moneta

Thanks very much and good morning everyone. I'd like to welcome you to TransCanada's 2010 third 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 business; Glenn Menuz, our Vice President and Controller and Greg Lohnes also joins us, he is joining us from our Toronto office this morning. Russ and Don will begin today with some opening comments on our financial results and other general issues pertaining to TransCanada. Please note that a slide presentation will accompany their remarks. A copy of the presentation is available on our website at transcanada.com. And it can be found in the Investor Section under the heading Events & Presentations. Following their prepared remarks, we'll 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. And 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 more detailed questions relating to some of our smaller operations for your detailed financial models, Terry 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. Finally, I'd also like to point out that during this presentation, we will refer to measures such as comparable earnings, comparable earnings per share, earnings before interest, taxes, depreciation and amortization or EBITDA, comparable EBITDA and funds generated from operations. These measures do not have any standardized meanings 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 our operating performance, liquidity and our ability to generate funds to finance our operations. With that I’ll turn the call over to Russ.

Thanks David and good morning everyone and thank you very much for joining us today. I’m pleased to report that TransCanada posted solid third quarter results. If you look at our net income and earnings per share year-over-year we saw that figure climbed by approximately 80%. As I told you last quarter, we’ve accomplished this by continuing to do the things that have made us successful for a number of years. That is following a disciplined approach that focuses on growing TransCanada’s core businesses. We’re currently growing those core businesses by focusing on completing the reminder of our ambitious $21 billion capital program. In the future, we will continue to reinvest in additional growth opportunities where we have competitive advantage. We will grow earnings and cash flow and deliver long-term shareholder value. TransCanada’s core businesses of Pipe and Energy continue to perform well in a very challenging business environment. Net income applicable to common shares for the third quarter was $377 million or $0.54 per share comparable earnings were $374 million or $0.54 per share. Comparable EBITDA for the third quarter was $1 billion and funds generated from operations in the third quarter were $861 million. Also today, the Board of Directors declared a quarterly dividend of $0.40 per common share for the three months ending December 31, 2010. Well we did see year-over-year increases in third quarter earnings, the quarter was not without it’s challenges, power prices in our core Alberta and Northeast U.S. markets where we have exposure to market prices continue to be weak, which of course impacts our bottom line. And with natural gas prices hovering in the mid $3 range, conventional gas production is declined impacting throughputs on our Canadian pipeline systems. We are confident in the recovery of energy commodity prices however, the timing…

Thanks, Russ, and good morning, everyone. As you know, earlier today we released our third quarter results. Before I get into the details I’d like to highlight a few key elements for you. First, the diversity of TransCanada's assets contributed to higher earnings and cash flow quarter-over-quarter even though lower power and natural gas prices continue to impact a portion of our business. Second, we are successfully advancing our unprecedented $21 billion capital program for the long-term benefit of shareholders. We’ve now invested $13 billion in the program and over $8 million of these projects have either begun or about to commence operations. Keystone, the Halton Hills and Coolidge power generating stations, the second phase of the Kibby Wind project and the Bison Groundbirch and Guadalajara natural gas pipelines are expected to generate significant EBITDA next year as they enter full commercial service. And last, TransCanada's financial position remained strong. We’ve completed our financial requirements for 2010 and are well positioned to fund the remainder of our capital program in 2011 and 2012. I'd now like to take the next few minutes to elaborate on these themes and our third quarter 2010 results. Net income applicable to common shares in the third quarter was $377 million or $0.54 per share compared to $345 million or $0.50 per share for the same period in 2009 an increase of 8%. Comparable earnings in the period were $374 million or $0.54 per share compared to $335 million or $0.49 per share 2009. As we mentioned in our last conference call, we expected to receive National Energy Board approval of the three year Alberta System Settlement in the third quarter. That did happen and we reported $30 million of net income or $0.04 per share as a result of the higher allowed return under…

Thanks, Don. Just a reminder before I turn it over to the conference coordinator. We will take questions from the financial community first and once we’ve completed that, we’ll turn it over to the media. Now with that, I’ll turn it back to the conference coordinator.

Thank you. (Operators Instructions). So the first part of the question-and-answer session will be for analysts. So the first question is from Carl Kirst from BMO Capital, please go ahead. Carl Kirst – BMO Capital: Thank you. Good morning everybody. The first question, I just want to make understanding on Bruce, I understand we’ve got the $400 million uplift here. With respect to timing and when we’re going to see revenues, presumably that’s going to be matched with when they come into commercial operation. And I’m not sure if that is a delay from prior or not, but the way we’re going to wrap it up was, earlier Russ, I think you were talking about new projects adding an incremental billion dollars of EBITDA into 2011. Are you still tracking to that or how should we be thinking about that now?

I think that number is still accurate. The major components of that, obviously the key major component is the Keystone Cushing extension, but then the other ones that I mentioned in my remarks, obviously Halton Hills, Bison, Guadalajara and are tying up at the Groundbirch projects, all sort of add you up to about that number. And they come on at various stages. So those would be sort of run rate numbers, not necessarily a billion dollars of EBITDA for the calendar year. But on a run rate basis, that’s the kind of number that they add up to.

Okay. I appreciate the clarification. And with respect to the Keystone XL, now that we might have approval, perhaps being delayed into the second quarter I understand that’s a bit of still uncertainty. But hypothetically under that perhaps June 30th approval, would that have an impact on as far as the in-service date of XL? Should we be moving that out to mid 2013?

Carl, it’s Alex. We even with that date we’re talking about mid next year for the Presidential permit, we’ve planned for and are still online for a Q1 2013 in service. Carl Kirst – BMO Capital: Great, thank you.

Thank you. The next question is from Ted Durbin from Goldman Sachs. Please go ahead. Ted Durbin – Goldman Sachs: Yes, if you could just talk a little bit more about your negotiations on the Mainline terrace, what are the key points of negotiation you’re looking at, we’re rapidly purchasing at the end of the year, you’re looking into 2011 at all, when you are in the negotiations, maybe just get a sense of the range of the outcome, we should expect on those?

Just said before, it’s we’ve, our desire is to, lower and stabilize tools, the primary root to getting there is through reduction and our collection of returned of capital if you will, which is depreciation. The way that we get there is, we do believe that there is an increased supply available for our pipeline over the longer-term, reserve estimates in Western Canada have gone from some 100 TCF of recoverable resource to about 300 TCF of recoverable resource based on that, we believe that the pipeline has a longer life and through sort of shifting cost around in the system to those portions that have longer life we are able to reduce our depreciation and then with some rates and services changes, we’d hope that those would reduce tools substantially between the East and the West. Those are sort of the major components in terms of timing what we’ve said on timing is that we would have agreements by the end of the year or we will be filing something similar to what I just outlined. Ted Durbin – Goldman Sachs: Okay, that’s helpful. Thanks. And then if I could just ask a little bit bigger picture question, we’ve got power prices are obviously quite depressed maybe just talk about where you feel like we’re in the cycle for that business, does it make you feel like there might be some acquisition opportunities out there given the fact that we maybe bottom into the cycle can you just talk a little bit about the power business?

You know what I’m able to speak couple of comments and then I’ll turn it over to Alex but it kind of feels like we’re at the bottom of the power market we’re experiencing prices that we happen to experienced for a long, long time, and I think there is a couple of reasons for that obviously the reception and has resulted in decreased demands sort of across the board with the exception of Alberta. Alberta is actually we’re seeing continued growth in demand as a result of industrial development. But as well gas prices being down have a significant impact on power prices as well we would think that over the longer-term as the economy recovers power prices will recover back to you, back to normal levels. No question that that presents acquisition opportunities, but what we said is we’re you know we are disciplined about the choices that we have made and that we’re focused on our $21 billion capital program and it’s if there is until we get that done, I would say that our focus isn’t done on looking for opportunities for acquisition in the power market. Now Alex, do you want to add to that?

I think that’s fine, I probably wouldn’t add anything further.

Okay, I appreciate it, thank you.

Thanks Ted.

Thank you. The next question is from Linda Ezergailis from TD Newcrest, please go ahead. Linda Ezergailis – TD Newcrest: :

Yes. I don’t have those right in front of me. I would say right now, Linda, we’re looking at an IRR with the present dates we have probably in the range of 9, maybe slightly higher but right around 9, and I don’t have the detail right in front of me on that delay, but yet I don’t imagine it would be too sensitive. We’re at the point now where we would expect, we are almost completely through the construction we will be through construction sort of towards the end of Q1. So where any delays that we would expect would probably be in the range of a month or two. Linda Ezergailis – TD Newcrest: Great, thank you. And just like shift and focus on your power business, can you perhaps describe your Oakville contract, whether or not there is any cleared language around cancellation and would it be similar to the agreement at by Concor or would it be more of a one-time payment or would it be perhaps an investment, an alternative investment opportunity somewhere else within Ontario or is it unclear based on how the contract is written?

No, the contract is very clear. There is no right for the OPA to cancel the contract. So that puts us in a situation where the government makes a decision to do that. They have to sit down with TransCanada and work out appropriate compensation. I think, you’ve kind of hit the nail on the head, Linda. There is sort of a number of ways that we could see that compensation coming, obviously we have been a big player in the Ontario market for many years and we’ve had a good relationship with both the government and the OPA. So we have embarked on a process that we’re in the middle of trying to figure out how we will get that recovery. Linda Ezergailis – TD Newcrest: Great, thank you.

Okay.

Thank you. The next question is from Juan Plessis from Canaccord, please go ahead.

Thank you. With regard to Keystone, can you comment on why there was a delay in the EBIDA recognition and when do you expect the maximal operating pressure restriction to be lifted and to begin according to EBIDA?

Hi Juan. It’s Alex. As I think you might have heard, we have been operating base Keystone under a pressure reduction on the original line one in Canada by the NEB. And I would just state they wanted us to do some further investigation and work on the integrity of that line, all of that work has been done. We’ve run the inline tools, we have done all of the analysis, that information is now with the NEB and we would expect to have that delay lifted some time as we get towards the end of this year, and that is really we have delayed the recognition of income from and revenue from this project just based on when we get to the full design capacity and so as I said we expect to do that towards the end of this year. Juan Plessis – Canaccord: Thank you. And shifting gears a bit, Russ you commented that your business environment will be challenged in the short-term by depressed power pricing and natural gas pricing. Can you elaborate a little bit on that?

Well, I think that’s and I’m trying to elaborate on it a bit, in those places where we have exposure to market prices in the power side, those revenues will continue to be depressed until we see a turnaround in the market price. It’s not our intent to sort of forward lock-in these prices at the current time. We think that we are at the bottom of the cycle. And then secondly on lower gas prices, we have seen that impact, Western Canadian drilling on the conventional side, and we have a timeframe between when that gas is declined and when your new shale gas comes online. So, in terms of turnaround on that front, we would expect a change in throughputs prior irrespective of a change in gas pricing environment, but if gas prices do sort of more normalize, then I think that we will see an increase in conventional drilling activity as well in Western Canada, which would augment those new volumes that I talked about in Northeast British Columbia. Juan Plessis – Canaccord: Okay, thanks. So, this wasn’t a shift in your outlook then?

No, it’s just recognizing that this has been a prolonged recession and it could last a bit longer. Juan Plessis – Canaccord: Okay, thank you.

Thank you. The next question is from Matthew Akman from Macquarie. Please go ahead. Matthew Akman – Macquarie: Thanks guys. Maybe this is for Alex, but follows on what Russ was just saying on hedging and particularly your strategy for Alberta, I’m just wondering whether you’d continue to put any hedges on, I guess at these forward prices or whether you just kind of leave that open now and try the ups and downs?

Yeah, that’s kind of exactly what our view is, I mean, we are hedging forward, sort of a month or two or a quarter if we see what we would consider good short-term value, but right now I mean there is almost no, I’d expect there is almost no downside left in Alberta power prices and the skew to the upside is pretty significant so you are dead on with our strategy right now.

I think our strategy Matthew is always been to maintain about that portion of our portfolio that’s exposed to market prices at a fairly minimal level and that could just strength the bottom of the cycles to not have to hedge I mean we’ve got a very stable base business and so we can, we’re not forced into selling at prices that we think are not as good as we will, otherwise be able to achieve by waiting for a period of time here.

Yes, that’s a good comment. I mean, if you look at our overall portfolio because of the heavy waiting of power purchase agreements, I mean even going into 2011, I think, if you value those we’re about 75% to 80% forward sold. Matthew Akman – Macquarie: Okay, thanks and maybe if I could just follow-up with one question on the pipeline side of the business. We’ve got Bison coming in soon, which it looks like you got the project, also other takeaway capacity out of that basin in the form of Ruby. Have you got any preliminary views on how that can affect your other pipelines in particular I guess GTN and maybe the Mainline?

I think at, on the GTN, maybe I will pass it over to Greg. He is on the other end of the line here.

Yes, with respect to those projects that we will see Bison coming on at, 400 million a day, we would expect to see some production from Western Canada on moving to the Mainline that’s been moving this year on northern border. And I think that’s in our modeling in the range of about 250 million a day and then GTN, I guess, Ruby coming on kind of midyear we would except to have some impact as well probably in that same range or maybe higher…

The key I think, Matthew, on GTN is that we have most of our revenues on GTN are derived from long-term contracts and they run through to 2023. And even if the volume movement on GTN is decreased as a result of Ruby coming online, our revenues won’t be impacted to any material degree. And then sort of as we, sort of think longer-term having two sources of supply moving in our GTN pipeline is probably a positive going forward. Many pipelines have multiple sources supplying multiple markets provides greater optionality and greater opportunity to prosper in the future. Matthew Akman – Macquarie: Okay. Great. Thanks, guys. Those are my questions.

Thanks Matt.

Thanks Matthew.

Thank you. The next question is from Pierre Lacroix from Desjardin Securities. Please go ahead. Pierre Lacroix – Desjardin Securities: Thank you, good morning. Just coming back on the Western Power, you mentioned that you have a substantial portion of your portfolio that’s hedged going forward. But if you look at 2010 versus what it will be in 2011, given the average price that you’re getting on those hedges, do you see that 2010 year to be the bottom for the Western Power side?

Yes, I think 2010 will be more challenging year than, sorry. 2010 is tough, 2011 is going to be tough. And we would expect to see some recovery in 2012. Pierre Lacroix – Desjardin Securities: Okay, good. Thank you for that. And looking at the U.S. power side, $77 million of capacity revenue, could you give some kind of a breakdown between Ravenswood and your operations that you had on the specific line?

Sorry, I missed the last part of that question. Pierre Lacroix – Desjardin Securities: Would you give the breakdown of Ravenswood in that capacity revenue versus other operations?

Sort of New England, I’m trying to think of it off the top of my head, but I would say probably at least 75% of that capacity split would be Ravenswood. And I think one of the things that I think it’s important to keep in mind is that the capacity calculations in New York are based, one of the key components of the capacity calculation is unit claim capacity and our capacity at Ravenswood has been depressed for ’09 and ’10 as a result of that extended unit 30 outage we had shortly after we acquired the plant. In 2011, we no longer have the rolling impact of that. So we’ll see a significant increase in capacity payments coming out of Ravenswood in 2011. Pierre Lacroix – Desjardin Securities: And talking about capacity there, in terms of the pricing situation, are you heading toward the $10 to $15 level that you were previously guiding on?

Yes, I think we are right, the one thing we are in the middle of another big, there is several factors that factor into the value of capacity. We are right now on the middle of a regulatory process to settle on a one of the features of the capacity value, which is called the cost of new entrant or cone that is a regulatory process. We are in the middle of and we expect to be done probably in Q1 of 2011, but we are probably looking in the winter season, we’re probably looking at capacity values in that sort of $12 to $15 kilowatt month, maybe a little bit towards the lower end of that range, just because of the modest demand drop we have seen. But we are in that range that we talked about earlier. Pierre Lacroix – Desjardin Securities: That’s great. Thank you very much Alex.

Okay.

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

Good morning, just coming back to the Mainline toll negotiations based on kind of where you are right now in the negotiations, do you think that what either you are going to come to an agreement on that it’s going to be something smaller with the tweaks, Russ you mentioned something on depreciation or should we be expecting something more radical coming out of those negotiations with respect to tolling methodology.

Maybe I like to, let Greg take that one as well.

We are currently in discussions with all the stakeholders and I would say, I think we are making some reasonable progress here. We would hope to be in a position where we could file a settlement towards the end of the year, which would deal with 2011 tolls and look a little bit longer-term. One way or another we will be filling as Russ said by the end of 2011. And with regard to the, your question there are a whole number of things that we’re considering and we are working with our stakeholders on a confidential basis on and I can’t really disclose the nature of those discussions. Robert Kwan – RBC Capital Markets: It’s some thing kind of much larger, it may be even a departure from the regulatory frame work that we have seen is it still on the table, was that fair?

No, that’s not fair, we are under the same regulatory contract, we’ve been under all along and we would expect that we will continue to work within that frame work.

Yes, I just to make a point on that Robert, is one of the corner stones of it is to ensure that the regulatory framework that we have operated under for several decades, stays in tact and that is the one of the cost recovery, I think that best serves the industry in terms of maintaining the lowest possible cost-to-capital, in the lowest possible cost of service. And departing from that model I guess it isn’t a good idea for TransCanada and isn’t a good idea for the industries, so that has been a cornerstone for our project.

Okay. Just my other question relates to Keystone and the returns on the project. I believe when you first said the toll you had mentioned that you took some exposure on what your debt financing rate was going to be, which was looking, a little issues of time, but based on what you’ve done recently where bond rates are looks like it’s been a bit of a win. Can you just kind of refresh what the expected returns in the line are in light of where you’ve been financing?

I believe if I remember correctly 100 basis point change in our financing cost, which I think was paid at about 6.5% made a 0.3% difference in IRR. And so I think sensitivity that we gave you on our meetings I think it works both up and down. Robert Kwan – RBC Capital Markets: Okay, and is there anything else changed within the project that we can just use the old numbers and make some adjustment?

No, I think at the time we announced the projects, we have given an IRR range of around 7% to 9%. And I think 7% at the bottom end is a good number for just sort of base Keystone with the contracts if we get our expected spot volumes growing over the years that number probably looks like 8% and then if we are able to go to the total design up the volumes of the total design capacity of $1.5 million with incremental pumping. We are probably looking at 9% and then any of these other assorted projects like Bakken, the Cushing marketlink, those would be on top of that. Robert Kwan – RBC Capital Markets: That’s great, thank you very much.

Okay.

Thank you. The next question is from Andrew Kuske from Credit Suisse. Please go ahead. Andrew Kuske – Credit Suisse: Thank you. Good morning. Do you have a perspective just post the election in the U.S. on what that really means from an infrastructure standpoint to your business as far as the future development of it goes?

I think, Andrew, that’ll be very hard to give you any sort of insight of that as to what, that the election yesterday, will have on development of infrastructure, obviously that the marketplace determines that the need for infrastructure and right now that marketplace is depressed and so the need for infrastructure isn’t as great as it has been say over the last five to 10 years, but as the economy recovers we’d expect that to, that to pickup but I’m not sure that the politics at the end of the day actually drive the need for infrastructure, it’s really the marketplace that drives the need for infrastructure. Andrew Kuske – Credit Suisse: But would you anticipate some of the changes that happened yesterday from the mix in the housing of Senate. Making things maybe a little bit easier for your approval process I mean in particular if we look at things like, say Keystone.

Again, I think Keystone stands on it’s merits it’s a good project, the market as I said, market will drive that project, the market needs the crude oil, they need that 10 million barrels a day of imported crude oil and we believe that the safest most reliable place to get it is Canada. So it’s a fundamental need even with a depressed economy, they’re still needing 10 million barrels a day of imported oil and Canada is a great source of supply. So that along with the economic stimulus that comes with the project, $7 billion project in some 15,000 direct jobs are very much needed in this economy. So I think again the marketplace will drive those decisions at the end of the day. Andrew Kuske – Credit Suisse: And then somewhat related I know this builds up on the previous question on the call, as it related to Oakville, what effect do you believe this will have the Oakville decision from the government on other power plant developers within the province, because if we look over the last 10, 15 years of Ontario politics and power plant development has been a challenging at times we can go back to market opening and then market closing among other things. So I’m just interested in your perspective either Russ or Alex on, what impact does this have not just on Canada, I think which you’ve been very clear about, but on broadly power plant developers within the province.

It’s a good question, I think there are a number of implications that we and other developers would want to think about I think the first question that goes to the sanctity of the contract I mean if the Ontario government with Oakville had sent a message that they working on are in force and our executed contracts, then I think that could have a real chilling effect on anybody’s interest to develop power plants in Ontario, I think the good news on that is, our experience with the Ontario government on the Oakville issue is that they have been very reasonable and they very much appreciate that concern in that risk, so I think so far so good on that issue. I think the biggest issue that everybody needs to think about is the NIMBY issue and the perceived threat by developers at future RFPs of obtaining environmental permits and I think it will be important for the government to send a message that Oakville is a one-off situation and doesn’t represent a change in the view of the government towards necessary energy infrastructure in the province. Andrew Kuske – Credit Suisse: That’s helpful, thank you.

Thanks Andrew.

Thank you. The next question is from Petro Panarites from CIBC. Please go ahead. Petro Panarites – CIBC: Thank you and good morning. Just back to Ravenswood for a second, are you able to quantify the incremental EBITDA from Ravenswood this quarter year-over-year and also on the capacity you will be able to offer into that market next year. Again, could you quantify the proportional increase in capacity?

We don’t typically break out that information on an asset-by-asset basis, but I’m trying to think of the exact number, but that sort of range that I gave you kind of winter capacity prices kind of towards the low end of that $12 to $15 range, I think we are looking at sorry summer capacity in $12 to $15, the lower end. Winter capacity in the sort of probably around $4 to $5 per kilowatt month and we are now getting credit under that capacity calculation in 2011 for the full output of the plant and I think when you run that through, the capacity calculator, that the regulator has, that looks like somewhere in the range of 2200, 2250 megawatts. Petro Panarites – CIBC: :

The demand, you know, it was interesting. Last summer, demand came within a whisker of the all-time peak demand in Zone J. I think the general view of the ISO is that the demand is moderated modestly in the range of kind of maybe, I would say probably about 2% to 3%. I think I’ve read a lot of commentary on it and the perception seems to be that really isn’t related to any of the demand, the demand side management programs, but it really had more than anything to do with the fact, that we’re, the New York economy was in a tough time and even though it was hot, people were just making the decision not to turn their air conditioners on. They really viewed it as a bit of a temporary phenomenal on. So I, but that’s kind of the range that we looked at it, as I said it was interesting to me that although average demand might be some what muted, peak demand, which is one of the very important aspects of capacity calculation, was looking fairly robust in those hot weather months. Petro Panarites – CIBC: And on the supply side?

There is one project coming on, I believe it’s the story of plant, but there is one combined cycle project coming on that we had always had in our calculation, I think that’s coming in sometime in later in 2011, I think it’s around a 500 megawatt project, but that’s been in our calculation. We tend to be fairly skeptically about these various cable projects and either feasibility and even if they’re feasible, we tend to be a little skeptically about the challenges of permitting those types of projects. Petro Panarites – CIBC: That’s great. Thank you.

Thank you. The next question is from Faisel Khan from Citigroup. Please go ahead. Faisel Khan – Citigroup: Hi, good morning, it’s Faisel from Citi. Could you, I think you may have answered this in a previous question, but I may have missed this, but can you elaborate a little bit on the – when you expect the extension from Cushing to Port Arthur and Houston to be in service, given the time, that it’s taken to get the state department approval for the expansion of the pipeline?

Hey, Faisel, it’s Alex. We, as I said earlier, we are still on a Q1 2013, timeline for in service for all aspects of Keystone XL, like, I think there might be some opportunity to advance that phase of the XL project, but I think right now sort of an early 2013 is probably good time for everything.

On that one, Faisel, as we have said before, if we’re intend to try to build that one first as Alex said depending on the start date we have to figure out our construction, but what we hope is to build that first and you can – look at a map and it’s about the same distance as there are Cushing extension and we would hope that, if we could do that one first we might be able to finish that in sort of the 12 to 15 month kind of timeframe. So we got started mid 2011, we might be able to finish sort of mid 2012 that way certainly our intent would be to, the customers are asking us to bring that capacity on as quickly as possible, but depending on start date and construction windows we will have to asses that when we get there, but that’s our intent is to build that piece first. Faisel Khan – Citigroup: Okay. Is there any change in the regulatory process and we need to do that or is that pretty straight forward?

No, once we get our approvals then we can determine sort of the most appropriate construction schedule if you will for the whole project and as I said is being further South that does pose less challenges then any constrains then in the more Northern parts of the project so we are confident that we can probably still, start that piece of the project first. Faisel Khan – Citigroup: Okay. Fair enough and then just on the Mainlined volumes kind of looking at the volumes year-over-year how much of the volumes declined year-over-year has been a function more of declines versus customers looking at other systems to bring their gas on?

Greg you might want to take that?

Yes, I think it’s mixed the producer just looks at a netback and determines where they are going to sell whether it’s neither move downstream. We certainly saw with REX moving further east opportunities for improved netbacks on border both at Chicago and at Ventura and so we saw increased volumes moving down border which we would have otherwise I think in the past have seen moving on the Mainline, but the conventional production is down and so that is also having an impact. : Faisel Khan – Citigroup: Okay, is it fair to say that the volume up-tick on GTN was a function of this shift in volumes from the Mainline to other systems?

Yes, I think its fair to say that some of that was that shift there is also a demand pull that unusually low hydro volume so there was a demand pull into that market as well as you know we are always impacted by weather constraints and weather challenges that tend to move volumes for short periods of time in different directions. Faisel Khan – Citigroup: Okay, great thanks for the time I appreciate it.

Thank you.

Thank you and the next question is from Sam Kanes from Scotia Capital. Please go ahead. Sam Kanes – Scotia Capital: Yes, just to do with big projects longer-term now that you are well entrenched in your $21 billion and if we just go through that maybe for the quick sound bites, obviously Athabascan [ph] has now passed I presume that was friction with native groups or with your partner or was there some specific reason?

No Sam, that was – we had a great relationship with ATCO on that and we would always characterize that as a very early stage development and we always said that we weren’t interested in pursuing it at all if we weren’t able to get the support of the native group. So, when they made the decision, that they really wanted to disengage. We really took the view that we weren’t going to be interested in pushing water uphill. So we’ll put that on the backburner and see if they change their mind sometime in the future. Sam Kanes – Scotia Capital: So, that was native group generated?

Yes.

Okay. Big transmission in Western U.S., I know you got one project part way through the regulatory process. Is that anything further at all or the other one going to California from U.S. Midwest?

Yes. Well, the I think the one, the Zephyr Project, which is the HVDC project from Wyoming down to the Las Vegas market, we did have a successful open season. The project was fully subscribed. But we’ve taken the view that the main market for this power was the California market and the main driver for that are the RPS standards that have been enacted and that are continuing to be enacted. But there is still a lot of uncertainty as to how that power is going to be contracted and particularly whether renewable sources outside of the state are going to be eligible and I think certainly everyone has a view that that is likely where it will end up, but at this point, there is still some uncertainty about that. So, what we’ve done is, we with the agreement of our partners, we’ve all agreed to take a go-slow approach on that and work with utilities and stakeholders in California to see if this very attractive wind resource in Wyoming is going to be attractive and suitable for consumers, utilities in the state. Sam Kanes – Scotia Capital: Thank you, and lastly the pipeline, Frontier pipelines. I’m positively surprised with your response so far, yet we have depressed economy and depressed gas prices, if you could just speak to that a bit more in terms of your view of timing, if it has changed any and/or Mackenzie here in NEB I guess is going to rule on the project here in a month as well.

Just, I didn’t hear the first part you were asking about Alaska. Sam Kanes – Scotia Capital: Yes. You seem positively surprised and I’m surprised as well in your response to-date. Of course, of course the putting when you have long-term from contracts and long-term from demand but you got depressed gas prices much higher, I guess. Gas, probably potential for the continent and a depressed U.S. economy and so that kind of surprised me to even hear that in terms of probable timing of last preceding Russ it used to one thought processed toward 18, 19 or?

I would say, 18, 19, 20 is probably the timeframe to deal and sort of, by the end of the decade. That the driver Sam, is really I think, all of these, large companies that are in Alaska are sort of looked to answer the current power place environment, they look to North American marketplace that is about 80 Bcf a day today, the market place, that could be 90 or greater, 10 years out. And on the supply side, a decline rating conventional supply, anyway, of somewhere in the neighborhood of 15% to 20% on an annual basis, so replacement is about 15 billion cubic feet a day, just to stay even, so we have seen a proliferation of new shale gas come on whereas you can see sort of in places like the Barnet for example, where you have ramped on very quickly to 5 Bcf a day, but it appears to have leveled out, because the decline rates for that shale gas production is actually pretty steep in the first couple of years. So once you reach sort of a production level, a run rate production in those basins and those level up as well. So our long-term view and I think that will be shared by those producers and I can’t speak for them but, given the bids into our project would suggest they are thinking the same that sort of as you get out towards the end of that gate you are going to need, shale gas, you’re going to need conventional gas and you are going to need Northern Frontier gas. And I think another sort of you know primary driver out of Alaska would be that the gases being produced today. And I think they are producing some sort of 78 billion cubic…

Thanks Sam.

Thank you. (Operator instructions) The next question is from Brian Horey from Aurelian Management. Please go ahead. Brian Horey – Aurelian Management: Thanks for taking my question. Based on pipeline flow data, it appears that the Mainline is really lost, most of its export amounted to the Northeast U.S. and it seems unlikely that’s going to come back even the growth of the Marcellus [Inaudible] basis in the East Coast markets that we’ve seen. So I’ m just curious if you can elaborate how do you see overcoming that with respect to the Mainline by shifting some of the cost around as you put it?

Greg, do you like to take that?

Sure, well obviously we do have new volumes that are coming into the marketplace and allow Eastern users to have some options as to where they get their gas at the Canaport LNG and Marcellus coming on and you heard Russ mentioned earlier that with regard to Marcellus we’re certainly negotiating Preston agreements and we’re looking at our system as to how we can move some of those volumes anytime you have existing depreciated infrastructure, you can be very competitive in moving volumes to wherever they need to be moved and so we are fortunate in that. We have a large Eastern system, which can take some of the new supply as well as supply from Western Canada and we are working hard with the producers and with the end used market to make sure the Western Canada stays competitive and that’s where Russ’s discussions about depreciation and moving to areas where we do have higher flows and therefore can observe those cost in a more effective way and keep our tolls competitive. So that’s what we’re working with our all of our stakeholders is to make sure that Western Canada stays a significant supply for the East. I think you correctly have seen some volume drop off Niagara Chippewa and Iroquois. The Niagara Chippewa area will likely be a good source for these Marcellus volumes and we would hope that we can continue to be competitive into the more distant markets through our settlement with our various stakeholders. Brian Horey – Aurelian Management: Okay, thank you.

Thank you.

Thank you. The next question is from Juan Plessis from Canaccord. Please go ahead. Juan Plessis – Canaccord: Okay, thank you. In regard to the U.S. power side, we saw a significant increase in the purchases and resale of power. Is that a sign of the power markets in the U.S. maybe picking up?

I think it probably would be more fair to say, that particularly in Q3, I mean we had some really hot weather in New York and New England and that created a lot of incremental opportunities. I mean, we were running our units more and we’re also seeing opportunities to procure power in the market and fill other sales we had. So I think as I said, I think generally we saw a little tiny tick back in demand overall in New York. I think, we’re seeing, actually I think, New England probably went up 1.5% or so. So I would expect we’ll move back to a growth mode over the next couple of years. Juan Plessis – Canaccord: Okay, thank you. And my last question. On the Alaska pipeline project, I noticed that the sale of Alaska started making some payments for reimbursement of costs as of July 31. Was there any impact on the Q3 earnings from that?

No, I think that there’s, the county is sort of based up expense and then reimbursements from the state actually follow on a like basis. So I think if we actually look at the disclosure Alaska, it will be different in our disclosure because there their payments are different timings than we’re recognizing the cost from an expense perspective.

Yes, and we understand through the contract which costs are reimbursable. And so similarly as we need to accrue our expenses, we can also accrue our recoveries on that. So it’s not necessarily on that, when the cash comes in regular basis. Juan Plessis – Canaccord: And again, Glenn, in terms of our expense expectation for next year.

I think, now that we’re into the 90% threshold, it’s relatively modest next year. Juan Plessis – Canaccord: Okay, great. Thank you.

Thank you. The next question is from Steven Paget from FirstEnergy. Please go ahead. Steven Paget – FirstEnergy: Good morning. I think we’ve gone through to Q4, in the time we have taken, but just quickly on Bruce, are you going to be exposed to spot power prices in 2012 until the – both units are up and running so that makes about three quarters of exposure to Ontario spot power prices?

That is what the contract says Steven, I think we’re able to do a number of things to reduce that. I think most notably you’ve heard us talk about the life extension activities that we’ve done and continue to do to extend the life of Units 3 and 4. So we’re now looking at life cycles for Units 3 and 4, probably getting out to around 20, 21. But as I said, there is this maintenance that is required we call it West shift, but without going into great and gory detail, it’s just an extended outage that we have to do on the Unit 3 reactor. What we’ve done, we were going to do that West shift in 2011 and it worked out well that we could shift it into 2012. So that is, I think it’s around 170 day outage, so an outage that we needed to take, we’ve been able to move into 2012, which significantly ameliorates that challenge so we do have much lower exposure to that. And also I think that the discussions are on going with the OPA and we’ll see if we can’t do something in that regard. Steven Paget – FirstEnergy: Okay, thank you. Alex, my next question is on the Alberta system, there is some talks of the Alberta system might be expanded eastward to take in part of the Canadian Mainline, I guess its right at the settlement you reached on September means that that’s unlikely to happen?

They are independent events but maybe Greg, you want to talk about that?

Yes, when we put a proposal together Steven in the spring that was one of the matters that we were considering and as we’ve worked our way through the process, it’s still there long-term there are a lot of different things that we would be thinking about and working with our various stakeholders on, in order to make sure we keep the competitiveness of the Mainline viable going forward. But we’re in discussions, the Alberta settlement did not eliminate, that as a potential solution, but I’d say that the reaction from the upstream was quite negative with regard to that particular proposal, so the settlement did allow if something were to happen that way that we would continue to look at the upstream side, but that’s just was one potential option and we are now looking at a number of options, with all stakeholders including the upstream cap group. Steven Paget – FirstEnergy: Thank you and then those are my questions.

Thanks Steven.

Thanks Steven.

Thank you. We’ll now take question from the media. (Operator Instructions). The first question is from Justin Amoah from Argus Media. Please go ahead. Justin Amoah – Argus Media: Hi, thank you for taking my call. What were Keystone throughputs what’s the day average in the third quarter and after and how quickly can you increase throughputs on that system after the MOP restriction is lifted?

It’s Alex Pourbaix, I think on Keystone we have been averaging about 120,000, 130,000 barrels a day, and that will ramp up when we remove this flow restriction on the Canadian portion, then we’ll move up to those numbers that you heard Russ discuss in Q1. Justin Amoah – Argus Media: Okay, so the incremental volumes that you are talking about is, are those coming through contracted capacity or is that or do you expect high amount of spot shipments on the system?

It is over-whelmingly contracted capacity in 2011, the total capacity of 591,000 barrels a day, 90% of that would be contracted. Justin Amoah – Argus Media: Okay, and I just have one more if I could, [Inaudible] just talked about connection from Keystone XL to the needling terminal. Is that going to be the only terminal that XL connects to at the Gulf Coast or are you working on other connections as well.

We are right now, I mean we see an opportunity to advantage Keystone by increasing the connectivity at that end of the market, so we are continuing to look at connecting to other terminals and that’s something will probably progress our thinking over the next year or so. Justin Amoah – Argus Media: Thank you.

Thank you. The next question is from John Spears from Toronto Star. Please go ahead. John Spears – Toronto Star: Hello, I am just wondering if I understand the most of the expenses been made now on the Bruce one and two refit, but what do you anticipate to be the total expense when it’s finally done on the capital side. And I am just want given the delays in the cost over, how attractive is it an asset for you to keep in the long run.

Well, at the time we committed to go into the project, I mean we had said that we would probably be looking at an internal rate or return of somewhere between, I think it was around 9% to 13% and we said that and where we ended up on that would depend on the challenges of doing a lot of this first of a kind construction, it would be fair to say we have experienced a number of those challenges, but at the end of day we are still in that range, that we are talking about that represents an attractive return to TransCanada’s shareholders and I think equally importantly it also represents very competitively priced power for Ontario consumers. Even with the modest cost sharing that has taken place with the government through the OPA, this power still looks cheaper than any alternative sources such as gas fire power. John Spears – Toronto Star: Alright, thanks very much. And the total cost for the units one and two?

We have indicated 4.8 total cost, our share 2.4. John Spears – Toronto Star: Great, thanks very much.

Thank you.

Thank you. This concludes today’s question-and-answer session. I would like to turn the meeting back over to Mr. Moneta.

Thanks very much and thanks to all of you for participating today, we very much appreciate your interest in TransCanada and hopefully for many of you will look forward to seeing you at our upcoming investor meetings in both Toronto and New York on November 17 and 18. Thanks again for your interest and we look forward to talking to you soon. Bye for now. Thanks.

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