TC Energy Corp (TRP) 2009 Q3 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2009 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. Good morning, everyone. I would like to welcome you to TransCanada's 2009 third quarter conference call. With me today are Hal Kvisle, President and Chief Executive Officer, Greg Lohnes, Executive Vice President and Chief Financial Officer, Russ Girling, our Chief Operating Officer, Alex Pourbaix, President of Energy and Executive Vice President in Corporate Development, and Glenn Menuz, Vice President and Controller. Hal and Greg 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 web site at TransCanada.com and it can be found in the Investor section under the heading conference calls and presentations. Following their prepared remarks, we'll turn it 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 anyone with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have any additional questions please reenter the queue. We ask that you focus your question on the industry, our corporate strategy, recent developments and key elements of our financial performance. If you have detailed questions relating to of some our smaller operations, or your detailed financial models, Miles, Terry 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 US Securities Exchange Commission and 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, earnings before interest taxes, depreciation and amortization or EBITDA comparable EBITDA 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, they may not be comparable to similar measures presented by other entities. These measures are 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. With that, I'll now turn the call over to Hal.

Thank you, David. Good morning, everyone and thank you for joining us today. I just note before I begin my remarks that the TransCanada team is in our Calgary office. I'm working from our Toronto office today. So, I don't expect any difficulties with that arrangement but if there are, please bear with us. So, to begin, as outlined in today's news release, TransCanada's net income for the quarter ended September 30th, was CAD345 million or CAD0.50 per share. Comparable earnings were CAD335 million or CAD0.49 per share. Comparable EBITDA was approximately CAD1 billion for the quarter and funds generated from operations were CAD772 million. We continue to post solid earnings in cash flow on the strength of our diverse energy infrastructure business. Third quarter earnings were ahead of last year from our pipelines to natural gas storage assets while the economic downturn continues to impact our power revenues. On September 30th, we completed a public offering of first preferred shares. Proceeds totaled CAD550 million and will be used to partially fund our large capital program among other purposes. With this and other offerings earlier this year, TransCanada has raised approximately CAD5.6 billion. As a result, our 2009 capital expenditure program is fully funded through in strong eternally generated cash flow and the capital we've raised in the markets. We have, in effect, now commenced our 2010 funding program.

We continue to make significant progress on a number of our growth initiatives this quarter. I would like to discuss those in more detail starting on slide seven in our third quarter investor presentation. As you know, in the second quarter, we announced our intention to become the exclusive owner of the Keystone oil pipeline system. In August, TransCanada completed the acquisition of ConocoPhillips remaining 20% share in Keystone for $553 million US dollars plus the assumption of $197 million US dollars of short-term debt. TransCanada now owns 100% of the Keystone project. Keystone will play a vital role in transporting a growing supply of Canadian crude oil to the largest refining markets in the United States. First phase of pipeline is now 90% complete. TransCanada expects to begin filling the line with oil in the fourth quarter with deliveries to the US Midwest, commencing in first quarter 2010. Keystone is currently seeking the necessary regulatory approvals in Canada and the United States to build and operate an expansion and extension of the Keystone pipeline system that will provide additional capacity of 500,000 barrels per day from western Canada to the Gulf Coast in the year 2012. In September of 2009, the National Energy Board held a hearing to review that application for the Canadian portion of the Keystone Gulf Coast expansion. We expect the NEB's decision in early 2010. Permits for the US portion of the expansion are expected by mid-2010 and construction of the Keystone expansion is expected to begin in 2010 once we receive all of those necessary regulatory approvals.

Turning now to our Natural Gas Transmission business, work continues on our north central corridor pipeline in Alberta. The pipeline is expected to be complete by April 2010. The north central corridor pipeline will provide capacity needed to deal with increasing gas supply in northwest Alberta and northeast BC. Declining gas supply in northeast Alberta, growing natural gas markets within the province and give us the ability to deliver more gas to interconnecting pipelines at the Alberta Saskatchewan border. Notably, the pipeline is expected to reduce fuel consumption on the entire Alberta system by approximately 50% which could result in shipper savings of CAD50 million to CAD75 million per year depending of course on gas price. In the north, the Alaska pipeline project continues to move forward with the joint TransCanada and Exxon Mobil project team actively advancing the engineering technical, commercial, environmental and stakeholder engagement work leading to the project's initial open season targeted for completion.

Turning now to our Energy business . [Hario] Power Authority awarded TransCanada a 20-year clean energy supply contract to build, own and operate the 900 megawatt Oakville generating station in Oakville, Ontario. That contract has now been finalized with the Ontario Power Authority. TransCanada expects to invest approximately CAD1.2 billion in this natural gas-fired combined cycle plant with an expected after tax unlevered internal rate of return of 9%. Oakville is scheduled to start producing power by the end of 2013. Also in Ontario, construction of the approximately CAD670 million, 680 megawatt Halton Hills generating station is continuing on schedule and the facility is anticipated to be in service in the summer of 2010. In Arizona, TransCanada began construction of the $500 million US dollar Coolidge generating station in August 2009. This 575 megawatt power facility is expected to be online in second quarter 2011. The Oakville Halton hills and Coolidge natural gas fired power plants will provide TransCanada with a steady stream of earnings and cash flow under 20-year tolling contracts with strong counter parties.

On the wind front, commissioning began on the first phase of the Kibby Wind Power Project in September. 22 of the 44 wind turbines were in service effective October 30th. Roads and foundations for the remaining 22 turbines will be completed this year and the turbines are expected to be installed and operational the end of the third quarter of 2010. Once completed, Kibby will have the capacity to produce 132 megawatts of power. At our Cartier Wind Project in Quebec, initial brush clearing work for the 212 megawatt wind farm in Quebec has been completed. Clearing for the 58 megawatt Montane Cartier Wind Farm will be completed by the end of November, 2009. These projects are expected to be operational by 2011. Grow more in phase two is expected to be operational by 2012. These are the fourth and fifth Quebec-based wind farms under development by Cartier wind. An entity that is 62% owned by TransCanada. These two wind farms are expected to have a capital cost of approximately CAD340 million. Once these two phases are complete, Cartier will be capable of producing 590 megawatts of power, 62% of which will be TransCanada's. All of the power output is sold under long-term contract to Hydro-Quebec.

Turning to the Bruce Nuclear Project, progress continues on the refurbishment and restart of Bruce A units one and two with work now advanced to the reassembly of the reactors. The units one and two project is approximately 75% complete. With the bulk of the highly technical high-risk work now completed. Although a significant amount of work remains, most of the remaining work is conventional power plant construction activity. The Bruce 1 & 2 project has experienced some delays in reaching this stage and we now expect the unit two will be restarted in mid 2011 with unit one expected to follow approximately four months later. The impact of this delay is largely mitigated by the extension of the operating lives of unit three to at least 2011 and unit four to 2016. Further life extensions are expected as additional reactor optimization activities proceed on units three and four. In summary, although we face a delay on the Bruce restart project, all of our other capital projects continue to progress as expected during the quarter on time and on bunt.

Going forward, we will continue to place a significant amount of effort into delivering these projects. Beginning with the Grandview project in New Brunswick in 2004 and continuing with Cartier Wind, Becancour, Portland's Energy Center, Halton Hills, Bruce and now Oakville, we are building a superb eastern Canadian power generation business. In all of these locations, we are paid to convert wind, natural gas or nuclear fuel into electricity without exposure to commodity prices. This business model is consistent with the risk return profile of our Natural Gas Transmission business. As these assets, along with Keystone and our other pipeline growth projects are placed into service, between 2010 and 2012, we expect to generate significant growth in earnings and cash flow. I will now turn the call over to Greg Lohnes, our Chief Financial Officer who will provide additional comments on our third quarter financial results.

Thanks, Hal. Good morning, everyone. As Hal mentioned, earlier today, we released our third quarter results. Starting with slide 11, comparable earnings in the third quarter were CAD335 million or CAD0.49 per share compared to CAD366 million or CAD0.63 per share for the same period in 2008. The primary reason for the drop in Q3 comparable earnings per share is an 18% increase in the average number of shares outstanding as a result of common share issuances in the second quarter of 2009 and the fourth quarter of 2008. The proceeds of these share issues are being used to fund our CAD22 billion capital program including the acquisition of additional interest in Keystone and other capital projects that are expected to contribute significant earnings and cash flow growth in the future. Proceeds were also used for general corporate purposes and to repay short-term debt.

I will now briefly review the third quarter results for each of our business segments at the EBITDA level beginning with Pipelines on slide 12. The Pipelines business generated comparable EBITDA of CAD730 million during the third quarter 2009. An increase of CAD7 million over the same period in 2008. Increase is primarily due to increased earnings from the Alberta system as a result of a settlement approved in December 2008. And higher operations maintenance and administrative cost savings for the Canadian Mainline. The third quarter and more particularly, 2009 -- the 2009 year-to-date results also reflect the positive impact of a stronger US dollar on our pipeline's assets in the United States.

Next, some comments on Energy on slide 13. Energy generated comparable EBITDA of CAD292 million in the third quarter 2009 compared to CAD366 million in the same period last year. The decrease is primarily due to lower power prices in Western Power and reduced volumes in Western and Bruce power. Along with lower volumes of power sold to customers in New England as a result of unseasonably cool weather. These decreases were partially offset by incremental EBITDA from the Ravenswood facility and the start-up of Portland's Energy Center and the Carleton Wind Farm. Energy's EBITDA also reflects a higher contribution from the natural gas storage business due to increased third party storage revenues.

Now, looking at slide 14, I would like to take a few minutes to talk about how we use hedging strategies to mitigate our exposure to power markets. To reduce its exposure to spot market prices on uncontracted volumes, as that September 30, Western Power had fixed sales power contracts for 3,200 gigawatt hours or approximately 70% of the planned sales for the remainder of 2009 and 9,200 gigawatt hours or approximately 50% of planned sales for 2010. 100% of Eastern Power sales volumes were sold under contract in the third quarter and are expected to be sold under long-term contract in 2010 and beyond. 100% of the output from Bruce A in third quarter was sold at fixed prices. All of the output of Bruce B is subject to a floor price. Both the fixed price received at Bruce A -- excuse me -- And the floor price at floor B are adjusted annually for inflation April 1st. And finally, US power has entered into fixed price power sales contracts to sell forward approximately 2,500 gigawatt hours for the remainder of 2009 and 7,600 gigawatt hours for 2010.

Turning now to the corporate segment results on slide 15. Corporate EBIT for the third quarter 2009 was a loss of CAD28 million compared to a loss of CAD23 million for the same period last year. Corporate costs were higher primarily due to higher support service costs in 2009 reflecting a growing asset base.

Now, looking at a few lines below EBIT on the income statement, on slide 16. Third quarter 2009 interest expense of CAD216 million reflects an increase of CAD3 million compared to third quarter last year. Increase in interest expense was primarily due to new debt issues of US $1.5 billion and Canadian $500 million in August 2008 and US $2 billion and Canadian $700 million in January and February of 2009 respectively. In addition, the impact of a stronger US dollar on US dollar denominated debt increased interest expense. These increases were partially offset by increased capitalization of interest to finance the Company's larger capital spending program in 2009, particularly Keystone. Interest, income and other increased CAD21 million compared to third quarter 2008 primarily due to higher gains from the positive impact of a stronger US dollar including changes in the fair value of derivatives used to manage exposure to foreign exchange rate fluctuations. Income taxes were CAD107 million for the third quarter 2009 compared to CAD129 million for the same period in 2008. A decrease was primarily due to reduced pretax earnings as well as higher tax rate differentials and other positive tax adjustments in 2009.

Turning to cash flow on slide 17, funds generated from operations were CAD772 million in the third quarter 2009 compared to CAD711 million in the third quarter 2008. Capital expenditures and acquisitions in the third quarter 2009 of approximately CAD2.2 billion are linked primarily to a number of growth opportunities including the increased ownership position in Keystone as well as construction progress on Keystone and other capital projects.

Now, looking at slide 18, at the end of the third quarter 2009, our balance sheet consisted of 50% debt, 3% junior subordinated notes, 3% preferred shares, 44% common equity. We have an A grade credit rating with a stable outlook. Our working relationships with all three credit rating agencies are strong. This year, we've raised approximately CAD5.6 billion in debt and equity capital. As Hal noted on September 30th, we completed a public offering of 22 million first preferred shares for gross proceeds of CAD550 million. At the end of the third quarter, we had CAD2.4 billion of cash on hand along with additional committed revolving bank lines of CAD3.4 billion. This strategy of strengthening our liquidity and financial position through our ability to successfully access capital markets in very volatile and uncertain economic times has reduced TransCanada's future financing risk around its committed growth program.

Going forward, we intend to use TransCanada's growing internally generated cash flow, the dividend reinvestment plan and the issuance of long-term debt, supplemented by further subordinated capital as required in the form of preferred shares or other hybrid securities to fund our existing capital program. As demonstrated by the sale of North Baja earlier this year, TransCanada will also continue to examine opportunities for portfolio management, including an on-going role for TC pipelines LT in the financing of our capital program. In summary, TransCanada's financial position remains sound. Our 2009 capital program is fully funded. And we're well-positioned to fund our capital program in 2010 and beyond. That concludes my prepared remarks, I will now turn the call back to David for the question and answer period.

Thank you. Just a reminder, we will take questions from the financial community first and following that we will turn it over to the media. With that I will turn it to the conference coordinator for your questions.

We'll now take questions from the telephone lines. (Operator Instructions) There will be a brief pause while participants register for questions. Thank you for your patience. The first question is from Carl Kirst. Please go ahead.

Good morning, everybody. Couple of quick questions, if I could on Bruce and I guess one, just trying to drill down a little more so I better understand the cause of the six to nine month delay here. Did anything specific happen over the last three months? Was it one large -- one item behind it in specific or was this just kind of a collective slowdown? That's the first question. And then the second question also on Bruce is what has to happen to get everyone comfortable that we can extend unit three from 2011, for instance, out to 2016?

Ok. Carl, it is Alex. With respect to the extension of the in service date, I would say that there were probably a couple of programs that were running behind schedule. I think particularly we had some challenges sort of -- not in the last several months but probably about four or five, six months ago, with some delays in the retube package. We are now seeing productivity has very significantly increased but we feel that we're going to see both of the units move from late 2010 into 2011 as a result. With -- sorry?

Oh with respect to unit three, Hal mentioned in his prepared remarks that we are quite confident of getting future extension -- life extension out of both unit three and unit four. I think what we would say is we are now comfortable that the life will be extended significantly beyond 2011 and that would be subject -- there is a course of work that needs to be done with both unit three and unit four to ensure that they will get that incremental life. The good news is that we have already started that course of work or have done a significant portion of it in prior outages which has given Bruce management the comfort that we should be able to get significantly extended life out of the units.

Alex, is that engineering or is that regulatory in nature? And when do you think that would come to conclusion so that you could put it down definitively so to speak?

I think we're very -- we're quite comfortable right now that those present dates that we have, that both units will have life in extended beyond there. We have no further regulatory approvals required to get that extra life, it is really as simple as just conducting a program of maintenance over the next probably about one to two year period that should give us that extended life. You'll probably see a more specific time frame from us on that over the next probably over the next quarter or two.

Great. Thank you.

Ok.

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

Thank you. I'm looking at the amount of interest capitalized in the quarter and I'm just wondering what you could provide us with some color on why it spiked up so much. Is there some catch up related to the Keystone acquisition related notionally to prior periods or can we expect that higher run rate to continue?

Linda, it is Glenn. I think as far as the increase in the quarter, couple of things are happening there. Obviously, we're just increasing our spend, all of our projects that have been mentioned continue to move along and spending continues along those lines. Also, given the acquisition in the third quarter and near the beginning of the third quarter there, you've got a large incremental spend, if you want to call it that. That will also attract interest capitalization. So, that is -- there are some small adjustments in there but nothing major. That is generally the reason for the increase. I think as far as the run rate going forward, I think all you do is continue to see it grow with the increased spending and then as these projects come on, you would see the interest capitalization fall off.

Ok. Thank you. And just as a follow-up, with respect to some of Carl's questions on the Bruce, are we still comfortable with our restart cost estimates? Or has the -- have the delays also translated into further cost escalations?

Bruce and the partners are in the middle of taking -- really comprehensive look at cost and schedule. But I think certainly from our perspective and we've been very highly involved in the restart activities over the past year, I would say that we mentioned the delay in inservice because we felt that that was potentially material. We do not have the same concerns about the cost.

Ok, thank you.

Thank you. The next question is from Matthew Akman. Please go ahead.

Thanks. Just a last cleanup question on Bruce. Alex, I don't know if you can tell us this right now, but is unit three still supposed to be down starting in 2011 or is that all part of what is subject to the restart to the life extension program?

Yes, there is a course of work that needs to be done on unit three. On the pressure tubes, to get that life past 2011. I think what I would say is we're quite comfortable that the life is extending past 2011. That's subject to this course of work that will be done over the next year, year and a half on the reactor.

Ok. Thanks for that. I guess this is a question for Hal. There's been some discussion publicly about Mexico. Perhaps privatizing some of its gas midstream assets. And obviously TransCanada is in the gas pipeline business in that country. Is that an area where you see potential for further acquisition?

Matthew, we're always interested in acquisitions if the outsets are blue chip and have a long-term outlook. Long-term, positive outlook. We would have to look very carefully at that. For example, if Mexico was interested in privatizing some gas processing or some raw gas transportation assets, we probably would not be interested in that. But if it was part of their large diameter and they have some very impressive large diameter pipeline systems running up along the Gulf Coast. We would certainly take a look at that. For now though, our focus in Mexico is on the new build projects where we think TransCanada can really add value through our ability to manage large diameter pipeline construction projects. Some of the terrain in Mexico is challenging. And we have a lot of experience in that and so far, we've been able to bring things in on time and under budget. That's really the value creation model that we're pursuing in Mexico.

Ok, thanks for that answer. I just have one last question. I don't know if this is maybe for Glenn or for Greg but it is around ANR. I remember when ANR was acquired by TransCanada there was some natural gas commodity in the system that was potentially going to be available for sale. Now, there's conversation about slightly lower EBITDA year over year because of reduced sales or sale prices of the natural gas. Can you please explain what you've done in the past with it and what you plan on doing going forward and if we can expect sales revenues from that pipeline going forward?

Yeah, Matthew. It is Glenn here. I'll take a shot at this. My understanding and it is more with the operations folks. But is that as gas is pulled out of storages, there is a certain amount of natural gas liquids that has come out. Those are sold. Similarly, there is a certain amount of proprietary gas that comes out. It is not something we're trading like base gas or something like that. So, that is -- when those do come out, they're sold on the market. And there is a fluctuation in the volumes that come out and obviously we're exposed on the price. It is not a significant part of the operation such that we would go forward and try to do a hedging program but they are -- there are some ancillary revenues there.

Matthew, it's Russ. I believe it was in the first year or two, there was significant volumes of natural gas to be sold as a result of some reclassification of base gas. And so that gas has actually been moved out. On an on-going operating basis as Glenn said, there is some minor amounts of gas that are available for sale. But that's not going to be material going forward and I think what the disclosure says is the price currently is below what we anticipated that it would be. Just like any other natural gas seller right now, but the volumes are not material.

Ok. Thanks, guys, for those answers.

Thanks, Matthew.

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

Thank you. Just another question on the interest expense. Was there anything else kind of moving through the lines that was kind of bringing that number down? Similar because I remember you booked a bunch of losses in Q4. Did that get reversed in this quarter?

Give me a second to take a look.

Do you have another question, Robert, while they're looking?

Sure. The other question I had related to main line tolls, there's been talk about the toll increasing very significantly for next year. I just wanted to get your thoughts as to -- I know you expect it to come back. What do you expect in terms of such a significant toll increase potentially shutting in more gas. Can you talk about anything you might be thinking about right now in terms of negotiations with shippers around alternative tolling structures.

By way of background for everybody listening is obviously production in western Canada is down by about a billion to a billion and a half cubic feet a day year over year. As a result, our 2010 tolls will rise considerably. We're looking at a number right now probably in the neighborhood of a CAD0.55 higher than last year. Your first question on whether that will have an impact on gas being shut in, I'm not sure that will. There is more volatility than that in the commodity price itself. Commodity prices have come up relative to this spring. Obviously that is the major issue right now is the commodity prices are down and therefore, drilling is down and volumes are down. So, we will deal with that in our negotiations with our shippers. We'll try to mitigate it as much as possible. So, we're looking at every angle to reduce our cost for 2010. And there is a number of different things that we've been in discussions with them on. There's things like deferrals of undercollections and those kinds of things that can be spread over longer periods of time. If that's what the shipper group wants to do which has the impact of mitigating tolls in 2010 and spreading it out over a longer period of time. About CAD0.20 of that increase is due to under collections in 2009 when we forecasted our 2009 volumes. They were higher than they actually turned out to be as you would expect. That undercollection has to be usually collected in the subsequent year. But there's ways that we can spread that out over time. So, those are the kinds of things we're working with our shippers on right now. I guess my view is I wouldn't anticipate that causing any shedding of gas but again, that's a producer decision. I think that's more linked to where people think the commodity price is going to be in 2010, 2011, 2012.

I guess just looking at that and your outlook, how confident are you in kind of your medium term outlook for gas such that you would be willing to defer what could be a very material portion of the toll into future period where there may be some uncertainty as to the ultimate collection.

I would say that at the current time, we're as confident as we always are in our forecast. What we know is they're never right exactly. They could be slightly greater or slightly less. We have seen considerable activity in [Montane and Horn] River. Our understanding is that both of those locations are -- drilling is sort of on target. As you know, we announced a little while ago that Horn river will be delayed slightly. But we built that into our current forecast. So, we see that gas volume coming on and I guess offsetting the decline of conventional here in Alberta. Sometime in the gas comes on in 2010, but probably in larger quantities in 2011. So 2011, 2012, we see things returning back to sort of where they were say last year. In that period of time. And we're as confident as we always are. We have the best information to make a forecast. We collect it from all kinds of sources, as you know in western sedimentary basin. So, as information changes, we update our forecast. But that's the best information that we have today.

Do you think that you could use this as a catalyst to maybe sacrifice some of the toll up-front here to set up a better deal and take a bigger bet on throughput increasing whether that is negotiating much higher ROE kind of down the road or even taking a little bit of throughput risk for the bigger return when the throughput comes back or is that something you don't want to visit right now?

Those are more longer term issues that we will discuss with our shippers but I would say that those are 2011 and beyond. The issue at hand is the toll increase in 2010 and what can we do in the immediate term because obviously anything like that is going to take a considerable amount of thought and discussion to change the model, if you will. And obviously we're not going to jump into that in a month or two. So, 2010, I think that you can expect that you wouldn't see anything, any sort of major changes like that. There will be minor modifications to our toll, the adjustments that I talked about. Longer term, I think we're open to a discussion on different modeling structures, but obviously, the risk return balance has to make sense to us.

Ok, great. Thank you, Russ.

Robert, it is Glenn. To get back to you on your interest expense question. Just to clarify, were you -- was your question coming from a comparison to Q2 of this year or Q2 of last year?

I guess if you were taking the debt balance and applying the interest rates, is there just anything market to market or otherwise that is pushing the number around this quarter?

Oh, okay. That's fair. I think generally, what makes this up is our interest on obviously our interest on our long-term debt, our interest on our short-term debt. The capitalized interest as well as the gains or losses on interest rate derivatives that are used for our interest rate management program. So, any of those things will move around, but also the other one is foreign exchange and the US dollar exchange rate because we do have a fair bit of US dollar debt. So, in comparison to last year, and to second quarter of this year, I think the biggest adjustment is -- the biggest change is probably around the capitalized interest. As I mentioned to I think it was Linda, previously, that a lot of that is due to the increased spend as well as the acquisition of Keystone. There is some small adjustments or there are some adjustments in there in Q3, but it really is a combination of effects here. I think the other thing that comes into play versus Q2 of this year is that the exchange rate is lower and we do have a sizable amount of US dollar debt. So, there's -- I think CAD1.15 versus CAD1.08. What we are seeing this year with the financing that we've had, we're carrying less short-term debt than we've seen before as well as the fact that rates on the short-term debt is generally down. So, it ends up being a combination of all of those factors.

Were there any material gains or losses on the derivatives?

In this quarter? No. Especially not compared to other quarters such as fourth quarter of last year.

Perfect. Thanks, Glenn.

Thanks, Robert.

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

Thank you. Good morning. In the event that you don't get favorable regulatory decisions for the Keystone expansion, what would be your approach?

I guess at this point in time, I wouldn't expect that -- I guess you're probably referring to the NAB application for a certificate of public convenience and necessity.

Yes.

And I guess at this point in time, we're operating under the notion that we will get regulatory approval. At this point in time, I don't see any reason why we wouldn't get regulatory approval. As you probably have been through the transcripts and the application is underpinned by significant amount of long-term contracts between Alberta and new markets which traditionally has been what the national energy board would look for for evidence of public need and necessity. If it doesn't go forward, obviously we would look at alternatives that -- to be able to move that gas to market. If it would start with where are the deficiencies in the application, but at this point in time, I don't see any deficiencies in the application.

Ok. And then just a different question. One more for Hal. Really, as it relates to on-going oil [fans] development and also a little bit of carbon emissions coming off of coal fine generation, what are your expectations of what will come out of Copenhagen in December as it relates to emission standards.

Andrew, I think all of the participants in the Copenhagen talks are much more knowledgeable than they were when we went in ti [Kyoto] about ten years ago. And I think the Canadian position is going to be much better informed in particular. People need to respect the capital replacement cycle that as we aim to reduce emissions from coal-fired generation, people have to understand it takes time and you have to let these coal-fired plants reach end of normal operating life and then really take them out of service and replace them with something cleaner. That's going to be the big challenge. The activists would have you believe that you can shut off those coal-fired plants today. And some technically-inclined people would think that you can get carbon capture and sequestration retrofitted on to those plants quickly and cheaply. Nothing could be further from the truth. It is very expensive and complicated to do carbon capture and sequestration and we eagerly await the first successful project. We would like to see how people are going to do that. So, I think thinking has matured there. There will always be positions taken by activists that we need to achieve a 25% reduction by the year 2020. I think both in the United States and Canada, government officials realize that's simply not possible and the conversation has shifted more to as these high emission facilities reach end of normal life, how can they be replaced with something that has much lower emissions and that's what we're all working on today.

Thank you.

Thanks.

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

Thanks, guys. Just a couple of quick follow-ups actually on the US side of the equation. Alex, I guess we'll keep asking this until it happens. Any shift in Poletti as far as retiring in January?

Poletti has filed their formal documentation to shut down the plant in January of 2010. And it looks to me that the market has finally realized that we have seen post-january 2010 winter strip capacity prices have moved up to the levels we had originally anticipated in our pro forma.

Ok. And then last question there, just on your US power hedges, are those power swamps or are those sparkbred hedges? Are we still economically open on those hedges?

There's a whole range of hedging products that we enter into. So, it is a little -- there is a real mix in there.

Ok.

Sorry.

All right. Ok. Thank you.

No problem.

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

Well, yes, can you tell us what the accounting treatment for Keystone is going to be as you roll up the volumes in terms of depreciation and interest, et cetera?

Bob, it is Glenn. As far as the depreciation goes, it will effectively look like it will match up against the flow-through of the volumes. I don't want to say it is prorated but effectively, you get something that looks very similar to that. Until this thing is in service and flowing full volumes. As far as the capitalized interest goes, that's something that we continue to work on. Both internally and with our auditors. So, at this point, I don't have an update on that.

Ok. Good news so far. Thank you. And the Oakville plant, this I guess is for Alex. The Oakville generating station, you have the OPA contract put to bed now I guess but there's still a lot of issues surrounding the building permits from Oakville. Can you give us an update on what's going on there?

Sure. The government and the Ontario Power Authority made the determination that for this RFP, that the power had has to be constructed and delivered into a very, very restricted area on the Ontario power grid. Which basically left for all intents and purposes, the winning bid either had to be in Mississauga or Oakville. And we were -- we were the winning bid. And it is an interesting and I guess not untypical story in these situations. The city council of Oakville -- were not overly thrilled with the prospect of a power plant in their municipality so they purported to put in place what is called an interim control bylaw which purported to basically ban any power plants from construction in the municipality for a period of time while they studied the issue. We have appealed that interim control bylaw. We believe that it is beyond the authority of the municipality to enact. What I would say in any event is that we are very hopeful of working with the municipality to come to mutually-agreeable outcome for this and the event that we're unable to -- the provincial government has very significant powers that allow them to override the views of municipalities to provide developers with required approvals and permits to go forward. So, we're quite comfortable that we're going to have a positive outcome under one of those scenarios. And I would say, Bob, this is not dissimilar from what we've experienced on most of the power plants that we've built over the past decade.

Now, I just haven't seen any municipalities issue specific bylaws to support you though.

Well, it was interesting. You might recall in that there was that North York RFP about a year ago and in that one, I believe there were three or four municipalities that fell within the OPA guidelines. And every one of them issued a similar control, interim control bylaw purporting to stop the power plants in their municipalities. So, it appears to be becoming a popular technique.

Ok. Thank you. Last question, in terms of when we look at 2010 funding, I know you're just starting that program and you look to maybe do some asset rolldowns, et cetera. Do you anticipate that there is going to be any significant equity issues hitting the markets next year?

It is Greg. I think we've demonstrated our ability to raise other subordinated capital and when we look at the program going forward, you see the cash flow starting to ramp up and Bob will be talking more about this at our investor day. But the cash flows ramping up. The prep share issue was twice as large as we had initially gone out with. We think that market is wide open for us. We really like the hybrid product we did in 2007. We're seeing that market recover. We've had good success with North Baja. We continue to look at other opportunities for drop-down. So, in our view, there are significant opportunities to issue other forms of subordinated capital to keep our metrics in line while we complete our build program and therefore, at this time, we don't see the need for additional common equity.

Excellent. I know you're going to have a huge problem with all of that cash flow once all of these projects start up and hit to volume.

We're really worried about that.

Thank you very much.

Thank you.

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

Good morning. I'm just curious, I guess with respect to the cash for long-term, your positioning or thoughts in renewables, ex nuclear and curious, more specifically, whether or not with the Canadian hydro developers turned friendly from a hostile, whether or not that asset or slash company and its growth profile had any interest to you or any other company like that in North America.

Sorry, do you mean [Transelta]?

No. Canadian hydro developers, because they're looking for a white knight.

Sorry. I thought you were talking about after the deal.

Oh, no.

I'll talk a little bit about renewables. We are -- certainly, we're one of Canada's largest renewable developers. We have our projects in Quebec and our projects in Maine going ahead. What I would say we have been very, very active over the past several years looking for attractive opportunities to either large scale acquisition of assets or of a development company. What I would say is before the economic meltdown, we just found that valuations were just out of our reach. There were lots of interesting companies but we could just never get to the price that was necessary to get a deal done. We are seeing better valuations and I think we'd still would be open to that opportunity. I think under any scenario, the renewable business is going to -- I hate to say renaissance because I don't know if it has dropped off. But I think for at least the next 10 to 15 years, the renewable business is going to have a lot of momentum, particularly, I would argue in the US with the impact of the various stimulus efforts and the other efforts being proposed by the federal government to get renewables more renewables built. So, we keep looking.

Our criteria, if we were to acquire and I think this might kind of help you with sort of your second question on Canadian hydro developpers, but our criteria is that if we were to do an acquisition, we would want it to be very material and really be of a scale that would move the needle for TransCanada. And we would like to see something that had a reasonably significant pipeline of development opportunities. And I think we have a great deal of regard for the Canadian hydroteam. It just -- from our perspective, it didn't quite get us to that level of scale we were looking for.

Hey, Sam, it is Russ. I would just add in terms of spending of the free cash, sort of post our build-up period here, I think what you can depend upon is this Company will continue to employ both its financial and strategic discipline, as Hal said, our criteria doesn't change as a result of that. Today, we have the three platforms for growth, the one that Alex mentioned, power which would include renewals, but natural gas obviously in our view will play a larger and larger role in North American energy demand. As a result of its low CO2 content, it is an obvious choice to meet the need going forward. We think gas continues to have a bright future as shale gas comes on. We've now positioned ourselves in an oil market where we've got a huge growth in oil sends over the next decade or two. And it continues large need for that crude oil in the United States. We have multiple platforms for growth. We'll continue to look at those. Longer term, we look at the frontiers, Alaska, MacKenzie. We're not worried about opportunities to spend that cash flow at the current time. I think what we're more focused on is making sure we maintain the discipline we've employed in the past with respect to both financial and strategic integrity.

I appreciate the answers from you both. Thank you.

Ok.

Thank you. We'll now take questions from the media. I would now like to turn the meeting back over to Mr Moneta.

I would like to thank you all of you for participating this morning. We very much appreciate your interest in our Company. And I think as Greg mentioned, we look forward to seeing many of you at our upcoming investor meetings later this month. Thanks very much and have a good day.