Good day ladies and gentlemen. Welcome to the TransCanada Corporation 2007 Third Quarter Results Conference Call. I would now like to turn the meeting over to Mr. David Moneta, Vice President of Investor Relations and Communications. Please go ahead, Mr. Moneta.

Great. Thanks very much. Good morning everyone. I'd like to take this opportunity to welcome you today. We are pleased to provide the investment community, the media and other interested parties with an opportunity to discuss our 2007 third quarter financial results and other developments concerning TransCanada. With me today are Hal Kvisle, President and Chief Executive Officer; Greg Lohnes, Executive Vice President and Chief Financial Officer; Russ Girling, President of Pipelines; Alex Pourbaix, President of Energy and our Vice President and Controller, Glenn Menuz. Hal and Greg will begin today with some opening comments on our financial results and other developments 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. It can be found in the investor section under the heading Conference Calls & Presentations. Following Hal's and Greg's remarks, we will turn the call over to the conference coordinator for your questions. During the question and answer period, we'll take questions from the investment community first followed by the media. 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 for your detailed financial models, Myles and I would be pleased to discuss them with you following the call. Before Hal begins, I would like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission. Finally, I would also like to point out that during this presentation, we'll refer to measures such as comparable earnings, comparable earnings per share and funds generated from operations. These measures do not have any standardized meaning prescribed by Generally Accepted Accounting Principles and are therefore considered to be non-GAAP measures. As a result, these measures are unlikely to be comparable to similar measures presented by other entities. These measures have been used to provide interested parties with additional information on the company's operating performance, liquidity and its ability to generate funds to finance its operations. And with that, I will now turn the call over to Hal.

Thank you, David. Good morning everyone. Thank you all for joining us today. I will take a few minutes to talk about recent developments in our business and I'll then turn the call over to our Chief Financial Officer, Greg Lohnes, who will review our financial results in more detail. TransCanada's strong financial performance during the third quarter is a result of solid contributions for more long life legacy assets and growing cash flows and net income from newly acquired and developed assets such as the ANR pipeline system and the Bécancour power plant in Quebec. We continue to grow our Pipelines and Energy business in a disciplined way with an unwavering commitment to large scale, long life infrastructure of the highest physical and financial quality. Through development of assets such as Bruce nuclear and the Keystone Pipeline system, we expect to generate strong financial results for our share holders over the longer term. For the third quarter of 2007, TransCanada Corporation's net income from continuing operations was $324 million or $0.60 per share compared to $293 million or $0.60 per share in the third quarter of 2006. Comparable earnings were $309 million or $0.57 per share compared to $243 million or $0.50 per share for the same period in '06, an increase of approximately 14% on a per share basis. Funds generated from operations in third quarter 2007 were 6% higher at $702 million compared to $662 million for the same period in 2006. TransCanada's Board of Directors declared a quarterly dividend of $0.34 per share for the quarter ended December 31, 2007 on the outstanding common shares. Shareholders that reinvest their dividends in additional common shares for the company through our dividend reinvestment and share purchase plan will continue to receive common shares from treasury at a 2%…

Thanks Hal and good morning everyone. As Hal mentioned, earlier today we released our third quarter results. Net income from continuing operations or net earnings for the third quarter were $324 million or $0.60 per share compared to $293 million or $0.60 per share for the same period last year. The third quarter 2007 net earnings included positive income tax adjustments of $15 million. Third quarter 2006 net earnings included a $50 million favorable income tax adjustment as well. Excluding these items, comparable earnings were $309 million or $0.57 per share for the third quarter 2007 compared to $243 million or $0.50 per share for the same period last year, an increase of approximately 14%. The quarter-over-quarter increase was due to increased contributions from both the Pipelines and Energy businesses. I will briefly review the third quarter results for each of our segments, beginning with Pipelines. The Pipelines business generated comparable earnings of $163 million during the third quarter, an increase of $33 million over the same period in 2006. The increase was primarily due to the additional income earned from the acquisition of ANR, higher earnings from the Canadian Mainline and a higher earnings contribution from other pipelines. TransCanada completed the acquisition of ANR on February 22nd and included net earnings from that date. For the three and nine months ended September 30, 2007, ANR's net earning were $19 million and $69 million respectively, which is generally in line with our expectations. The Canadian Mainline's net earnings increased $10 million for the third quarter when compared to the same period last year. The increase was primarily related to the higher common equity ratio, certain performance-based incentive arrangements and operations, maintenance and administrative cost savings under the five year toll settlement effective January 1, 2007 to December 31, 2011. Partially…

Great. Thanks Greg. Just a reminder, before I turn the call 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. Again, I ask that you limit yourself to two questions. If you have further questions, please reenter the queue. With that, I'll turn the call back over to the conference coordinator. Question And Answer

Thank you. We'll now take questions from the financial analysts. [Operator Instructions]. The first question is from Matthew Akman from CIBC World Markets. Please go ahead.

Thanks very much. Questions on the Keystone announcement from today, Hal. I'm just wondering if you can help us understand or clarify the significant cost increase in the project and how and whether TransCanada will earn a full return on that increase in the full expenditure.

Yes, Matthew, we will earn a full return. All of these issues have been agreed contract with our shippers. The capital cost increase is partly due to an expanded system, moving more volume, more equipment and that sort of thing. It's also the result of capital cost increases in pipe and construction contractor rates. We have moved actively to nail down those costs, securing long-term supplies of steel for the pipe itself and entering into contracts with contractors for specific construction of the different sections of that pipeline. But under the terms of our arrangement with the shippers, we have the opportunity to come back and firm up the costs estimates and of course to expand the project to move more crude oil. And we have done all of those things over the last six or eight months, and the announcement today is really what we think the project will cost when it comes in and the volumes that we think will move under the current phase. We continue to wok on subsequent phases of the project and we look to increase volumes further. The demand is there and of course everybody is considering carefully the impact of the current royalty changes, but early indications that we have had are that volumes will need to move to market. There is a number of very big projects that are under way today. And regardless of a final analysis of the royalty changes, there will not be an issue about volumes adequate to fill the current contracted capacity and we believe further expansion capacity on Keystone.

Okay. Just as a quick follow up then, when can we expect more details on TransCanada's share of this expenditure and return parameters and so forth as we go forward?

Well, we continue to finalize the ownership arrangements with certain other parties that have the right to take a piece of it. We'll get to a final resolution on that, I would think, some time in the next three to six months, and I think that the rate of return issues and what not will become clearer over that time as well.

Okay, thank you.

Thanks Mathew.

Thank you. The next question is from Linda Ezergailis from TD Newcrest. Please go ahead.

Thank you. Perhaps just to follow up on Mathew's Keystone question, the cost increase, can you allocate that between the core system and then the expansion on the Keystone?

It's approximately about -- someone will correct me -- about 1.5 billion for the Cushing and then the balance would be, I guess, about 3.7 for the Patoka Wood River leg.

Great, thanks. And in terms of the Bruce Power system of units, the depreciation and amortization has jumped up $7 million to $43 million versus the prior run rate. Is that somehow related to this Unit 4 deal? Can you explain and what's going on there?

Linda, it's Glenn Menuz here. No, the Unit 4 will only be depreciated once it gets in there. I think what you're seeing in there are just the timing of some items coming into service as well as some other minor adjustments in there. But again, just to note that those are 100% numbers and obviously our share would be smaller than that range.

Okay, but that's the new run rate that we should use?

I'm not exactly sure about the details, but it's going to be in the ballpark.

Okay. And while we are on the subject of Bruce Power, perhaps you can let us know what the next major milestone would be the Bruce restart and is it still on time and on budget?

Linda, it's Alex. We have now -- as Hal mentioned in his prepared remarks, I mean we have now installed all the steam generators in Unit 2 and we have now moved our heavy lift crane to Unit 1. So from my perspective anyway, I think there is really a couple of issues. It's going to be removing and replacing the steam drums and the steam generators in Unit 1. And we are now well into the process of removing the end fittings of the pressure tubes on the Unit 2 reactor; AECL is doing that. And those are, really from my perspective, the big events that are going on.

And so -- and that's on time and on budget versus your original estimate?

Yes, we -- as I think I've said at the last conference call, I mean we are continuing with our view that this project is going to come in well within the ranges of return that we had talked about then, and we are very happy with the progress of the restart to date.

Okay. Thank you.

Okay.

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

Great, thank you. Just on the Western Power side, the implied hedge price was in -- it looks like it was in the mid $80 per megawatt hour range. And that looks like it's a pick up from prior quarters. Is there something we can expect going forward just in terms of having seen the forward curve move out?

Sorry, I missed -- could you repeat that question? I missed a bit of it at the end.

Sure. It just looks like the -- like you are selling in terms of the hedge prices moved up in Q3 to somewhere in the mid $80 per megawatt hour range. Is that something we can expect going forward just based on what we've seen in terms of the forward curve move up as well?

Sorry, I understand the question. I think that's probably a little higher than we would expect particularly in Q4. Q3 always tends to be one of our highest price quarters. So that's probably a little slightly optimistic from my perspective.

Okay. And if you just look at say the year-over-year results, if I can remember correctly, you weren't able to capture a lot of the upside last year from the spike in power prices. Can you just -- how would you characterize say Q3 '06 versus Q3 '07 in terms of pricing and volumes and how you captured the opportunity?

Sorry, I don't know if I would agree with that characterization. I thought we did a pretty good job of capturing the spike in the power prices. We obviously have a strategy of selling forward a relatively significant percentage of our output. But we've been quite pleased with our contracting practice, and I look at our contracted portfolio right now and I think it looks quite attractive.

Maybe, Alex, if I put it a different way, your earnings are up very significantly in the quarter.

Yes.

Volumes are down. And how would you kind of characterize what was driving the big change then year-over-year given spot power prices were very similar? Was it just all the contracting strategy?

I think so. I mean the Alberta market, particularly in July, was characterized by some very high prices, and I think it would be fair to say that we were well prepared to benefit from that volatility.

Okay. Great. Thank you.

In part, Robert, it's Hal here, I'll just add to that. We see a pretty tight market in Alberta. And we are concerned firstly that the market structure is not allowing or inducing people to build more capacity, but at the same time we foresee these periods of tightness coming, and I think our power can do us a good job of getting a good rate of return out of that.

But Hal actually, to the extent that you're seeing or you're view being incremental tightness, is that going to change even just a little bit on the margin, your contracting strategy as you go forward?

Yes, I mean we are certainly flexible with our contracting strategy. I mean we are very focused on maintaining TransCanada's credit rating and just the security instability of earnings. But at the same time, we are flexible when we see opportunities where we see a lot of opportunity for higher prices rather than lower prices. I think you will see that sort of 75, 50, 25 kind of contracting strategy vary accordingly.

Great. Thanks Alex.

Thank you.

Thank you. The next question is from Sam Kanes from Scotia Capital. Please go ahead.

Good morning, Al. I am curious about the strategy with respect to your preliminary look at the Saskatchewan pet coke polygeneration unit. Watched for years as power study, study, study, then kill [ph], a project that sounds quite similar. I am wondering if you could elaborate on whether this is a, the only project you are looking at this kind. And Alberta obviously needs something like this as well and all over the U.S. there is a variety of different projects. Is it the same project? How much has it changed and what is the degree of interest from a TransCanada strategic point of view?

Well I think Sam the big picture would be that we see firstly declining gas production out of Western Canada and we have seen increasing demand for natural gas at places like Fort McMurray. We look at the carbon dioxide agenda that's playing out and we recognize there has to be other forms of electricity generation that emit less CO2. We look at IGCC, integrated gasification combined cycle, as a very interesting way. But we also recognize that the technology is in the early stages and most of these projects have been characterized by dramatic cost overruns. We visited gasification facilities in Dakota, IGCC plants in Florida, we have done a lot of work with General Electric and Bechtel on the Saskatchewan project. We continue to look at two or three different opportunities here in Alberta both related to coal-fired power, perhaps using a gasification process but also looking at petroleum coke in the Fort McMurray and Fort Saskatchewan area. So we are looking at all these things. We think longer term, we have got a very significant supply of pet coke and coal obviously here in the West, and there will be demand for natural gas, whether it's produced natural or synthetic natural gas. On the Saskatchewan project in particular, we have tried to be very astute about the way we go forward. We have put several million dollars into the project so far and we have said to the Government of Saskatchewan, given their involvement and the CO2 agenda, we are not prepared to continue putting money into this thing without some complementary contribution from them. And so that's basically the structure that we have landed on. And we continue to work with some very sophisticated parties in GE and others on how you move the technology forward and exactly what's it going to take. And I hear you on plans getting announced, a lot of hoopla and then these projects getting canceled as people figure out it's just too difficult and they are at too early a stage in the technology cycle. So we are going to proceed cautiously. We are not aggressively trying to get this plant built in a hurry. We want to continue to move forward, but we are going to make sure that we spend the necessary money upfront on technology and engineering and avoid the kind of multi-billion dollar mistakes that we have seen on some others.

Thank you.

And Alex would to that.

Yes, Sam, I might just make one comment on that. I think from our perspective, our polygen facility in Saskatchewan is actually quite a bit different from the oxy fuel facility that SaskPower was looking at. From our perspective, the polygen facility, I think power is just one of the off takes and it significantly benefits in its economics by the proximity to several other off takes in the region whereas the oxy fuel project that SaskPower was doing was really purely a powergen facility. And from our perspective, that technology was very, very in the experimental phase whereas the IGCC technology proposed to be used as a polygen facility is something that has been around for decades and is quite well understood.

Thank you for that. A quick follow up maybe to you, Alex. Now that Alberta has opened up the wind cap, if you may, and you've good success experience in Quebec, does that not make logical sense to extend out that way in the Alberta market?

We have always followed wind and Alberta very closely. And obviously the cap that had been imposed really made it difficult to consider anything. Now that hard cap is gone, but I think practically the issue that remained is still the issue of transmission access to these wind opportunities in Alberta. So we continue to look at them, but I think Alberta continues to be challenged with a lack of transmission infrastructure and the costs associated with building transmission infrastructure to some of these isolated sites.

Okay. Thank you, Alex.

Thank you. The next question is from Bob Hastings from Canaccord Adams. Please go ahead.

Hi, just a clarification from Alex on the transmission side. One of the things that you have been looking at I gather is Northern Lights, and does that impact to you at all and what are your plans on that these days?

We have said for years that probably the most significant problem plaguing the Alberta power market is its relative lack of interconnectedness with surrounding jurisdictions, particularly the Pac Northwest. We think that right now there is a unique opportunity with Northern Lights to really do a couple of things. I mean number one, better connectivity between Northern Alberta and Southern Alberta, which is obviously a problem with the cancellation of the recent alternating [ph] project. But I think more fundamentally as we move to a CO2 constrained world, we see a lot of opportunity to connect wind in Southern Alberta, hydro in Northern Alberta, cogen in Northern Alberta to markets in the South.

Okay. So with the cancellation or the delay in the alternating [ph] project, would you be able to -- are you looking at ways to propose other projects around that?

Yes, we are not working at specifically competing with any project, with any AC project that might be contemplated sort of a north-south interconnect -- or strengthening project. I am just suggesting that in the longer term Alberta will continue -- whether or not a north-south line -- AC line is built, Alberta is going to continue to need more transmission connectivity between the North and the South. And we think that our HVDC Northern Lights line could very much play a role in that longer term.

Okay, thank you. And can I get a clarification on the Keystone project? You capitalized costs in there, and I wondered if you could tell us sort of what those were and whether there is any catch up in previous costs with maybe expense in other quarters?

Greg, on --

No, there is no catch up. As we've disclosed in the past, we have capitalized -- we have disclosed our capitalized costs each quarter. I think what are you seeing this quarter with the jump in capital costs is really around pipe order and locking in some of these other contracts.

Okay. Thank you very much.

Thank you.

Thank you. The next question is from Karen Taylor from BMO Capital Markets. Please go ahead.

Thanks. I just have a couple of questions really quickly. Maybe David, if you've got the tax rates for Bruce and in the Gas Storage segment is my first question.

Yes, I haven't got them here handy. Karen, my recollection was we have used approximately 32, 33% on those two businesses, and I don't expect they would have changed.

Okay. And just a couple of other orco miracle [ph], how much was the adjustment to the TC PipeLine, LP contribution arising from the higher ownership? I am not sure I understood what that comment meant in the release.

Well I think there were two things there. One, obliviously, we are up from last year just -- the LP owning a share of Great Lakes here, a significant share of Great Lakes, we also own a more significant share of the piped LP. And in the laundry list of items, there was a small adjustment in there.

So are you talking less than $1 million or like non-material?

Not material. A couple or $3 million. I think it was about $3 million give -- or so Karen.

Okay. And we talk about foreign exchange rates in the commentary I guess, and maybe this is for Greg. Given all of the hedging ad natural offset with the debt position, what is the exposure of $0.01 change in the exchange rate?

I guess -- I mean you say without hedges. So we have our income offset by the interest on the debt. I'd say without hedges, there is about 100 to $130 million of exposure there, which would be about $1.3 million per cent [ph] change in the exchange rate, 1.3 net income. That's virtually all hedged with hedges that are rolling on a 12 month basis on a fourth quarter going forward basis. And therefore for right now, we have pretty much totally covered that exposure. As we go out looking forward of course, we are rolling these hedges forward and we are really deferring the impact of the change in exchange rate. Now that impact all shows up in corporate. The operating units are taking their hit as we go along when you look at the numbers from the operating units and then the hedge benefit shows up on the corporate side.

Right. So I just want to understand, because you can't really beat the trend with the series of rolling hedges, so if you put the hedges aside then, it's basically, a $0.01 move in exchange rate is $1.3 million in net income?

Yes.

Okay. And just very lastly, we talked about capitalization of costs and potential delays on Cacouna. Can you tell me how much cash, or rather costs have been capitalized for Cacouna? And then can you please give us an update on the proposed in-service date of Broadwater?

Okay, I will tackle the first question. We haven't capitalized any costs for Cocuna.

Okay.

And then Broadwater --

All right. Karen, we are still waiting for FERC environmental impact assessment, which we expect towards -- right now, we are expecting towards the end of the year and I don't think we have communicated any different date for the in-service.

So given the timeline for this particular approval, you wouldn't expect one or you just haven't announced one?

Karen, it's Hal. It's interesting that we have got two challenges on almost all of these LNG projects, we and everybody else in the industry. First is getting regulatory approval to build the facility and the second is securing the supply of LNG.

Right.

Our two projects are quite different in that regard. At Cacouna, we are working to bring down capital costs and to finalize LNG supply. And in the current supply demand environment, that's a major task, and we are working hard on that. At Broadwater, our partner of course is Shell, and Shell has more options for LNG supply, I believe, than any other company. So the issue at Broadwater, clearly, there is a great market, there is great market demand for that LNG coming in and we've aligned ourselves with what I consider to be the best possible supplier. So the issue at Broadwater is really one of getting environmental approvals and other approvals from the State of New York. The major approval is the environmental impact statement from FERC, and that we hope to get within the next few months and then we go on to secure whatever approvals we need from the state.

Has the state given you clearances under the Costal Zone Management Act?

Sorry, has the state given us clearance on --

Under the Coastal Zone Management Act, which is really their environmental trump card, have they given you approval for the project on that basis?

No, that's -- they don't address that question until they get the finding from FERC.

Okay. Thank you.

Thanks Karen.

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

Thank you. Good morning. Hal, in the previous comments you mentioned about the tightness in the Alberta power market and how you look at that in the future. I am just curious as to what your strategy is as far as your PPA exposure goes in Alberta. Because if we look at over time and we look at the tightness there, the market does look tight, but your PPAs roll off in 2017 and 2020. And if we look at the build time that's needed for a coal plant, it is considerable. So I am just wondering what are your thoughts at this stage on Alberta and how you approach your power strategy in Alberta.

Well I will provide a quick comment and let Alex add to it. First of all, our PPAs do run off in that 2017, 2020 timeframe and we acknowledge that. And we also acknowledge your point about the long lead times, and not a week goes by that Alex or I don't speak to the Alberta government about the need to work now on plans to replace this generation when it reaches end of life. Not only do our PPAs run out in that timeframe, but it is not too long after that that quite a number of the coal units in Alberta start to reach the end of their useful life. And in fact some of them will be coming offline before 2017; not our units, but some of the others in the overall Alberta coal fleet. So we look at we look at a number of different opportunities here in Alberta. Certainly, coal gasification is one of them. We'd be quite nervous as a company about proceeding with a simple coal-fired generation facility, and we think you have to look at other technologies that enable the capture of CO2 if you are going to be using coal as the generation. We also looking at -- we have obviously taken steps to develop our own gas-fired fleet, and that's a great way to generate electricity in Alberta other than we are not sure how expensive gas is going to be. And that's obviously something we worry about. We have looked at a number of large scale hydro projects. I'd underscore a comment Alex made earlier that really for people to invest significant money in merchant generation in Alberta, we need better connectiveness with major U.S. markets. You can't bring on 2 or 3000 megawatts in a new project and have that output stranded in Alberta. During the early years of a new plant you have got to have a safety valve to release that output into the larger Western North American market. So that's where we think transmissions a big part of it. We are aware that other people have looked at nuclear opportunities in Alberta. And with our partners of Bruce, we also look at those things. But obviously that's a complex step, there is a lot of technical issues. The building of a nuclear plant is not a simple thing, and we are doing our homework on that before we decide whether or not we would want to engage in that kind of generation build here in Alberta. So there is many opportunities, but you are right, the planning horizon is long and we need to deal with this early on if we are going to keep the lights on in this province 10 years from now.

Well I guess my overarching concern, and then that's all great color and commentary, but my overarching concern is when we get out to that period of time, there is a bit of an earnings cliff that you face if you didn't recontract the PPAs or have your own generation facilities assuming that the PPA of [ph] plant owners, those facilities just go away, which might or might not be a valid assumption.

Andrew, it's Alex. I think that's a very valid point. I guess I would have a couple of responses to it. From our perspective in the short term, I mean we have to be worried about things like market our concentration. We are already at about 20% of this market. But long term, we absolutely consider one of our core competencies and competitive advantages our knowledge of and our position in the Alberta power market. So I think you can take it as a given that we are very active right now on assessing development opportunities in those range, as Hal said, from things as small as 100 megawatt wind farms up to 1500 megawatt major hydro projects in Northern Alberta. So I don't foresee a situation over the next 10 or 15 years where we don't continue to maintain a very significant power generation position in Alberta.

And then if I may, I guess what's your view on the PPA plant owners' ability to life expand and then just extend contracts with them?

I guess there is potentially that opportunity. At the time these PPAs were entered into, the terms were calculated, for all intents and purposes, to coincide with the end of life of the plants. Now I think realistically, our experience with coal plants tend to be that those -- they never go away, they just keep getting refurbished in one way or another. So I do expect there is life in those plants longer than the PPA life. But the issue, I think the big issue in Alberta and the big issue in Canada is going to be the CO2 costs associated with continuing to run those plants. And as Hal mentioned right now, it really is -- there is a great deal of uncertainty under the federal act, the plan as to what those costs of CO2 compliance are going to be. I think our view is very much that right now there is no viable technology to capture CO2 off the back end of those existing and relatively late in life coal plants. So I think there is going to be challenges in life extending them if we continue under the present federal plan that we have right now. I think if there is some opportunity to do that, I mean we are obliviously going to engage with the asset owners to see if there is an opportunity for us to continue with some form of entitlement under those plants.

That's great. Thank you very much.

Thanks Andrew.

Thank you. The next question is from Daniel Shteyn from Desjardins Securities. Please go ahead.

Yes, good morning everyone. A couple of questions here. First, on the Alberta system negotiated settlement that is currently underway, I guess one of the things that you'll be looking at, and I believe you've already commented on, is the increase in the deemed equity ratio, up from 35%. I am just wondering if you can comment whether you are shooting for 40%, like you have gone on the Canadian Mainline and also if you believe that the likely outcome of the process will result in a fixed return for a couple of years or maintaining enough floating ROE.

On your second question, it's too early to speculate where we might land with that negotiation. That discussion has just started. Our target at the end of the day is likely a number that looks like 40% with an appropriate corresponding return on equity that would get us what we would call a fair return. And that fair return will probably be in the neighborhood of 7% on a all in sort of return on capital basis. So you can sort of back [ph] calculate where we think the ROE needs to be. And so that's the nature of discussions consistent with the asks [ph] that we have made in the regulatory forums and the asks [ph] that we've made on Mainline. Now obviously, we didn't achieve all of that on the Mainline in the settlement, and the settlement includes other factors like performance incentives, cost incentives and those kinds of things. That's sort of what we'd be targeted for heading into a settlement.

Okay, thank you. And for my follow-up question, I would like to just briefly touch on Bruce. I guess on page 9 of our press release here, there is an operating income number for 100% of Bruce for the three months at $204 million versus last year at 181 million. But TransCanada's proportionate share stays at 69 despite the increase in operating income, which could be attributed either to a decrease in your ownership percentage, which I do not believe to be the case or potentially a half a sentence comment that was made later on in page 10 saying lower positive purchase price amortization related to the expiring of power sales agreements. I wanted to see if you can shed a little light on the matter.

Yes, Daniel, it's Glenn Menuz here. Just taking it sort of line by line, you are right that the 100% operating income is up this year, but our proportionate share is flat. What you are seeing there is just the difference or the ratio or the proportion between Bruce A and Bruce B. As you know, we own roughly 31.6% of Bruce B and about 48% of Bruce A. And as we mentioned in some of the narrative that Bruce did experience some planned and unplanned outages this quarter as well as costs. And they were just a little higher on the A side and we own more of that. So proportionately, we didn't reap as much as that positive variance. As far as the expiry of the sales contracts, where you are seeing that is in the line below that that's called adjustments, and these some of the historical or legacy contracts that we had acquired at the time of our original ownership and they've just rolled off. So we've handled those through our purchase price accounting. So it ends up just showing up in that adjustments line.

And that the roll off is -- basically means that your pricing may go higher in going forward, is that --

Yes, I think those -- what we had recorded on that was just the contracts at the time. And as far as where things go in the future will depend more on where the market prices go and contracting strategies.

Okay, thank you.

Okay, thank you.

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

Thanks. Just with the agreement that you have with the shippers on the higher capital costs on Keystone, was there anything either in the discussions or if some sort of within the agreement, either just a memorandum of understanding with respect to further extensions south Cushing into the Gulf Coast?

There isn't any tie between the base Keystone project that goes to Cushing and what we are calling Keystone XL which goes to the Gulf Coast at the current time. Does that answer your question, Robert?

Yes, thanks Russ. But I guess just is there anything then in terms of Keystone XL, any update as to your timing in terms of potential open seasons or anything on that side?

Nothing in terms of concrete dates for open season. We continue active discussions with both the refining community and the producing community. I would say that that -- those discussions have been delayed as a result of the royalty discussion here in Alberta where the producers in Alberta have been focused on the impact that that's going to have on their future capital investments and their future needs for export capacity from the province. So I would suspect once that sort of the dust settles and people understand what the impact on their investment profile is going to look like and timing, then we'll be able to get back to moving forward with Keystone XL discussions.

Great. Thanks Russ.

Thank you. The next question is from Shawn Burke from HSBC Securities. Please go ahead.

Yes, good morning. A couple of dead questions if I can. First of all, on the Keystone cost increase, particularly in the context of a lengthy list of projects that you have going on, can you tell us how the Keystone costs increase that you announced today is going to affect your external financing plans in '08 and '09? And then you talked about success in maintaining A level credit metrics. This year you were successful in doing a significant amount of new issue equity and hybrids in the U.S. markets for ANR and Great Lakes. Do you intend to do similar securities on the equity side going forward?

It's Greg Lohnes; I'll tackle those. Our balance sheet is in the strongest position it's ever been in. When we go to the equity markets, it's very rarely and it's for significant size as you saw us do in 2007. We are in a great spot right now moving forward. We have got lots of dept capacity. These projects come on over a period of years, and so the spend profile is spread out. We have got very strong cash flow. And as you have seen from the quarter, it's growing as we move forward. So we have got lots a capability on the debt side. We have also got our DRIP program operating. So as you saw, it was $104 million for two quarters. So, and we would expect that to stay about at that rate. So we are adding small amounts of equity at very reasonable cost to the company. And then we maintain our flexibility with our LP and other facilities and look at the opportunities we have around our entire asset portfolio as we always do when we prudently manage our portfolio.

Just in terms of your external financing, have you been -- have you focused on a particular CapEx budget dollar figure for '08 and '09 that you can share with us?

No, at this point, really, we are refining that. As Hal mentioned in the first quarter of '08 or later this year, we will be determining what percentage of Keystone we have, and that's really a huge driver for our CapEx. I would say generally our cash flow is committed over the next two or three years going forward with our substantial greenfield development program. And then we continue to look of course at acquisitions and other opportunities in the ordinary course of business.

I'd just -- it's Hal here. I'd just add to that that if you go back to say the 1999, 2000 period, we were generating some thing like $700 million U.S in cash from operations for the full year. And in this current quarter, we generated something like $700 million U.S. in one quarter. Cash flow generation has grown very significantly within TransCanada and that has given us the ability to fund a much larger capital program. And to the extent that that larger capital program is directed at projects that bring subsequent increases in cash flow, we have a process that continues to strengthen the company and allow us to pursue bigger projects. So I would just point out don't overlook the internal cash flow and the growth in that when you think about how TransCanada can fund some of these significant projects.

Good enough. Thank you.

Thank you.

Thank you. The next question is from Karen Taylor from BMO Capital Markets. Please go ahead.

Hi. I have got a follow-up question, just probably for Greg or Glenn Menuz. And on page 20 of the release, it talks about a $35 million after-tax realized gain from settled derivatives. Is that related to your interest rate hedges or power contracts? Can you give me some indication which segment that would in -- would be in and where whatever comes from?

Karen, what I would suggest is we get back to you on that one.

Okay. And was there sort of timing issues related to the recognition of incentive gains on the Mainline? I think originally you had anticipated somewhere between $10 million and $15 million of incentive returns this year under the settlement.

And I am not sure what you mean by timing. I would say that they are fairly constant throughout the year, Karen; if that's your question.

And then just lastly, I noticed that you filed an application on the Alberta system to recover a CO2 cost I think under bill two or bill three rather and in the amount of about $3 million to $4 million. Given that the federal government has carbon legislation on the table, does the current settlement agreement on the Mainline explicitly provide for carbon costs as a flows through?

Yes.

Or do you have to have a filing?

I don't know if we have to have a filing because I guess I suppose it depends on how things are sorted out at the time. But from a commercial perspective, we have the right to recover those costs under the agreement.

So you won't have to file then if --

I don't know the answer to the regulatory question on whether we have to file or now. But commercially, we have agreed with our shippers that we can collect those costs.

Okay, thank you.

And Karen, it's Hal. I'd just add that the bigger question is whether or not the costs to comply with carbon legislation on the Mainline will be significant or not. And there are a number of factors that give us a reasonable outlook for carbon compliance costs on the Mainline. The much bigger worry that we would have is how carbon costs will work in the power side of the business, and we are very focused on that.

Okay, thank you.

Thanks.

Thank you. The next question is from Bob Hastings from Canaccord Adams. Please go ahead.

Thank you. Just a different topic on the APG, you've funded a fair amount of money over to that, and I am just wondering what circumstances would trigger you writing that down as opposed to capitalizing it.

Well I think our view, Bob, would be that the project continues to move forward. We continue to see the Mackenzie Pipeline as a viable project, and there is many thorny issues that need to be worked out and resolved. And we are working with the APG and with the producers in the Mackenzie to do that. Clearly, when the project gets to a point that we all conclude it's not going to go ahead, well then we have got a write-down issue to deal with on those costs. But at this particular point, we remain optimistic that we can pull all the details of this project together. It's not easy. The Mackenzie has been a work in progress for about three decades or more, and the challenges continue to be significant. But all parties are engaged and all parties are working on it and that's I guess about all I can say on it right now.

Right. I am just looking at triggering [ph] plants where you might change your mind. And I don't think you'd say it's economic at this point of time, would you?

Well, it depends on your outlook for gas prices. If you use today's gas price and the very highest cost estimates that have been generated for it, I think you'd have to question the economic liability. It's not clear that it would be an uneconomic. A lot of it also depends on production rates and how much other gas is available up there. But I think we look forward a little more optimistically because I don't think anybody would be more aware than us of the challenges of sustaining gas production in Alberta. We see roughly flat line production in Alberta and significant growth in demand, which sets the stage for higher price in Alberta. We frankly see a similar scenario unfolding all the way across North America with flat production at best over time. I see lately some people have come out with quite bullish forecasts of gas production growth in North America. I think those forecasts overlook the inexorable decline from our base producing sources in all parts of Canada and the U.S. So our scenario would be flat production at best out of existing areas of North America, setting the stage for higher prices and demand on both the LNG and Northern Gas sides. That would be the fundamental reason why we remain enthused by the project.

Now certainly pricing has something to do with supply and demand over time, so I would agree with that. Thank you.

We'll see where it goes. Thanks.

Thank you. The final question is from Daniel Shteyn from Desjardins Securities. Please go ahead.

Yes. I had a follow-up question in relation with the cogeneration facility. I guess the couple of things that are out there that you've disclosed is that the timing is likely to be by 2013. Well, first of all, how do you see a financing structure for that particular project? How much of it, if it goes ahead, debt versus equity in terms of potential project economics and how long would a project like that take to build?

I guess in terms of financing, I guess what I would say is it's still very early days in that project. I think some fundamentals about it. Basically, 100% of -- that right now it is planned, the 100% of the off takes from that polygen plant would be sold under long-term contracts to very creditworthy counterparties. And that would be -- it would be very much a kind of plant that would be done on a tolling basis. So we as the owner and operator would not be sitting on any significant commodity exposure. We would have operating risk and capital risk. So obviously I would think that kind of plant would lend itself upon commissioning, would lend itself to a relatively high level of debt financing, probably something north of 50:50 notionally.

Okay. And the economics would be, presumably, on the equity piece would be north of what you are getting, for instance, on your pipeline side or --

Yes, for this kind of project, we would be looking for an unlevered after-tax return, I would argue, at least somewhere at the 9% or north range.

Very good.

Not dissimilar from the kind of returns that we look for in our nuclear business. They are similar. I mean they are not dissimilar in the complexity of the projects.

Okay, excellent. Thanks very much.

Okay. Thank you, Daniel.

Thank you. We'll now take questions from the media. [Operator Instructions]. The first question is from John Hardine [ph] from the National Post. Please go ahead.

Good morning. On the cost increase for Keystone, I am trying to find a reference point or understand how much they have gone up percentage wise or again from what point.

I think I'd give a shot at that is our original cost estimate in 2005 for the project as it's configured today would have been about $2.8 billion or $2.9 billion. So we have escalated by approximately $2 billion and a bit. So I guess that would be a number that would get you in that 70% kind of range.

Okay.

From where we were originally. And as Hal pointed out earlier in the call, it's due to a number of factors. One, we have increased the scope and scale of the project, moving from 435,000 barrels a day to 600,000 barrels a day approximately. And then the escalation in both materials and labor costs would be the balance of that. And I think I would be consistent with the kind of escalations we have seen in other projects across North America. I think you were looking for benchmarks, you could look at some of the Alberta oil sands projects in terms of material changes in cost estimates from about that 2004, 2005 period to today.

Okay. And who is that, sorry?

That was Ross Girling speaking.

Okay. Can I ask one follow up?

Sure.

The issue of nuclear came up and just wondered if -- were you saying that you are looking at nuclear opportunities in Alberta?

We are looking at nuclear opportunities in many parts of North America, and Alberta certainly one of them. We think Alberta is an interesting situation just because the long-term supply demand fundamentals are good in Alberta, there is certainly demand for power. We would not undertake something major like that unless Alberta was -- enjoyed much better interconnects with the bigger markets in other parts of North America. So you can't, we don't believe, drop several thousand megawatts of any kind of power, nuclear, river, hydro, world scale coal into a market like Alberta without seriously disrupting the market if you don't have the transmission connections to the bigger North American market. But we look at nuclear power opportunities in all parts of the country. Our main focus today is at Bruce and we have got an exceptionally competent nuclear development team at Bruce that has done a very good job of guiding the refurbishment of the Bruce A plant, which in many ways is similar to a complete newbuild. And we have confidence that that team would do a very good job of pursuing nuclear projects in Alberta if they make sense. What we don't know is whether it would be competitive with exotic forms of coal generation. We don't think simple coal-fired generation makes sense in Alberta going forward for CO2 reasons. But there are other coal gasification and projects like that that might make sense, and that's what nuclear has to compete with. So it's not a simple question. We are doing our detailed homework as always and looking at that opportunity as well as many others in different parts of North America.

Thanks very much.

Thanks John.

Thank you. The next question is from Ian McKinnon from Bloomberg News. Please go ahead.

Hi there. I have a question for Russ Girling and it's regarding Keystone, the base cost. Like checked some of our old stories and we talked about $2 billion, $2.1 billion. I am wondering if that $2.8 billion, $2.9 billion figure that you are using includes the extension to Cushing.

That's correct. The original estimate -- of the Patoka Wood River leg was about 2.1 billion in 2005 dollars.

Okay. So that brings me to my next question. If Cushing's now going to cost approximately $1.7 billion; that's basically double what it was a couple of years ago, does that mean you are seeing greater cost increase in the U.S. side than in Canada? I am just kind of curious on this point.

No, it's related to, as I said, steel and materials and labor. And those changes are the same on both sides of the border, I would say. Actually, the closer you get to Alberta the higher the labor component of those costs are going to be. Materials such as pipe and valves and those kinds of things are going to be common no matter where you buy them. But I'd say labor is more extensive and more in sort of scarce supply the closer you get to the West.

Okay. And then can you clarify like if you are saying pipe and labor is going up, what are we talking about? A third, 50%, any sort of clarity on that?

I would say that our pipe costs are probably somewhere in the neighborhood of 50 to 60% higher than they were two years ago.

Okay.

And there is one other factor. You'll notice that all our estimates for this project are in U.S. dollars. And the most significant part of the capital cost is on the U.S. side. That's the bigger side, half of the project. But as the Canadian side goes up, the strengthening Canadian dollar adds another element to higher costs.

Okay.

So there are labor costs. I think the steel is generally priced in U.S. dollars and most of the major equipment is priced in U.S. dollars. But the Canadian contractors, as Russ pointed out, are increasingly expensive the closer you get to Alberta or in Alberta. And there is some significant construction on this project within Alberta. So the rising Canadian dollar also plays a role.

Okay. And Hal, one follow-up question for. On Mackenzie Delta, can you give any color or comment on whether TransCanada's in negotiation or willing to assume leadership role and take over from Imperial, because certainly that's one of the thoughts that's been floating around?

We are and we have been for several years part of the project. We are involved in the project; we are not an outsider trying to negotiate to get in. We are in the project. And all I would say the partners in the project are examining every alternative to come up with a toll for the Mackenzie producers that makes it attractive for them. They've got billions of dollars that they need to spend to develop the gas fields up in the Mackenzie Delta. And sometimes as people talk about the cost of the pipeline, it's overlooked that there is very significant expenditure to be made in the development of gas reserves and processing facilities and equipment up there. TransCanada's not involved in the development of gas reserves up there. So clearly, the producers are in the lead on that. I'd just say we are discussing a whole range of different things. TransCanada's always been willing to contribute as best we can. We have a lot of construction expertise in building pipelines. We have a lot of cold weather expertise and we have a very good working relationship with the producers and with the APG. We are all working together to try to bring this project to fruition, and I think that's all I would say at this point.

Thank you.

Thanks.

Thank you. [Operator Instructions]. The next question is from Scott Haggett from Reuters. Please go ahead.

Hi. I wonder if you can refresh my memory --

I am sorry, Scott. We can't hear you very well. Could you just try that again?

Hi, is that better?

Yes.

Sorry about that. I am wondering if you can refresh my memory on the agreement with Conoco-Phillips and what the status of that is on Keystone.

Conoco has the right to purchase a 50% equity interest in the Keystone pipeline. They haven't exercised that option yet, and we expect them to exercise it sometime probably before the first quarter of next year, exercise or not. They'd like to make a decision one way or another, so rough some time before the end of first quarter next year.

And that will involve paying their share of costs after that -- incurred and forward, is that the --

Exactly.

Okay. And one more question, what effect do you see the higher price tag having on tolls to -- on the line?

Well, obviously, it will proportionately increase the tolls. So the tolls will go up by -- in fact they have announced that the capital went up. When we look at sort of the competitiveness of the tolls relative to other options that the producers have to get to both the Patoka, Wood River area and the Cushing, with the increased capital costs, we are still landing at an all in cost that less than what we believe the competitive alternatives to be. All alternatives are experiencing these very similar cost increases. We are all ordering steel from exactly the same manufacturers and utilizing exactly the same contactors. So across the board, the costs have risen and tolls will go up. And given that we have a significant portion of our pipeline, it's a 2000 mile pipeline, about 6 or 700 miles of that is across the Prairies from Alberta to Winnipeg. That steel is already in the ground. We are converting one of our existing Mainline gas pipes to crude oil. So we are not experiencing a cost increase of the same magnitude for that. It's about basically one-third of the project. So our cost escalations are less than others cost escalations would be if you had to build sort of 100% from supply source to delivery source. So even with the cost increases, we are still very, very competitive, and our customers agree with that and obviously are very supportive of the project.

All right. Thank you very much.

Thanks Scott.

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

Thank you and thanks to all of you for participating this morning. We appreciate your interest in TransCanada and we look forward to speaking to you again soon. Thanks.

Thank you. The conference has now ended. Please disconnect your lines at this time. Thank you for your participation and have a nice day.