TC Energy Corp (TRP) 2008 Q3 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2008 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 and good morning, everyone. I would 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 2008 third-quarter financial results and other general issues 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 general issues pertaining to TransCanada.

Please note that a slide presentation will accompany their remarks. A copy of that presentation is available on our website at TransCanada.com, and it can be and found in the investor section under the heading conference calls and 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 will take questions from the investment community first and then allow some time for 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 any additional questions, please reenter the queue. We ask that you focus your questions on our industry, our corporate strategy, recent developments, and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations or your detailed financial models, Terry and I would be pleased to discuss them with you following the call.

Also please note that we intend to provide a more detailed update on our growth initiatives and future capital program at our upcoming investor meetings in Toronto and New York in early November.

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 US Securities Exchange Commission.

And finally, I would also like to point out that during this presentation we will refer to measures such as comparable earnings, comparable earnings-per-share, 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.

With that, I will now turn the call over to Hal.

Thank you, David. Good morning, everyone, and thank you for joining us today. I would like to take a few minutes to highlight third-quarter results and recent developments in our business. Following that, our Chief Financial Officer, Greg Lohnes, will review our financial results in more detail.

TransCanada's strong third-quarter financial results demonstrate our ability to generate significant sustainable earnings and cash flows from our growing portfolio of high quality energy infrastructure assets. For the third quarter of 2008, TransCanada's net income was CAD$390 million CAD0.67 per share, an increase of 12% on a per-share basis compared to the same period in 2007.

Comparable earnings for third quarter 2008 of CAD$366 million or CAD$0.63 per share increased by approximately 11% on a per-share basis compared to the third quarter of 2007. Funds generated from operations for third quarter 2008 were CAD$711 million. TransCanada's Board of Directors declared a quarterly dividend of CAD$0.36 per share for the quarter ended December 31, 2008 on all outstanding common shares. Shareholders that reinvest their dividends in additional common shares of the Company through our dividend reinvestment and share purchase plan will continue to receive common shares from treasury at a 2% discount to the average market price.

I will now expand on some recent developments that occurred in the third quarter. First of all, the Keystone Oil Pipeline. As you know, we announced the results of our open season for the Keystone expansion this morning. In addition to the 300,000 barrels per day we previously announced, we secured an additional 80,000 barrels per day for a total of 380,000 barrels per day of firm long-term contracts with an average term of 17 years.

The significant commercial support we received confirms the value of the Keystone Gulf Coast expansion as a cost competitive way to connect a growing of reliable supply of Canadian crude oil with the largest refining market in North America. TransCanada has begun working with the contractually committed Keystone expansion shippers to optimize the construction schedule.

With the additional contracts Keystone has secured long-term commitments for 910,000 barrels per day for an average term of 18 years. These commitments represent 83% of the 1.1 million barrel per day commercial design of the Keystone system.

We also announced today that TransCanada has agreed to increase its equity ownership in the Keystone partnerships from 50% to 79.99%. ConocoPhillips equity ownership will be reduced to 20.01%. Certain parties who have made significant volume commitments on the Keystone expansion have an option to acquire up to a combined 15% equity ownership in Keystone partnerships. If those options are exercised, TransCanada's equity ownership would be reduced to 64.99%.

Let me now speak about recent developments in our gas pipeline business. Here in Alberta, TransCanada received approval from the Alberta Utilities Commission for a permit to construct the North Central Corridor expansion, which comprises a 300 kilometer natural gas pipeline and associated facilities in the northern section of the Alberta system.

In other pipeline news, TransCanada acquired Bison Pipeline LLC from Northern Border for US$20 million in the third quarter. The capital cost to Bison to construct is estimated at approximately US$500 million to US$600 million. The Bison Pipeline project has shipping commitments for 405 million cubic feet per day and is intended to be in service in fourth quarter 2010. One of the committed shippers has an option to acquire a 25% ownership in the Bison project.

In addition, we continue to work on developing the Pathfinder and Sunstone projects to connect additional US Rocky Mountain gas supplies to our existing pipeline network and to provide customers with access to diverse markets throughout North America.

On the Alaska front, it seems like a long time ago, but in the third quarter the Alaska Senate voted in favor of granting TransCanada a license to build the Alaska pipeline. The Governor signed the bill on August 27, 2008 and we do expect the Alaska Commissioners of Revenue and Natural Resources to issue the AGIA license in late November 2008, after the obligatory 90-day waiting period for the bill to become effective. This is an important step in advancing this major natural gas pipeline project to connect stranded US natural gas reserves in Alaska to Alaskan and lower 48 consumers. We have commenced the next stage of engineering, environmental, field, and commercial work and expect to conclude an open season by July 31, 2010.

Turning now to our energy business, in our energy portfolio, TransCanada acquired the 2480 megawatt Ravenswood generating station for US$2.9 billion subject to certain post-closing adjustments. We are very pleased to have acquired this baseload and peaking facility in this critical market. Ravenswood represents excellent long-term value for our shareholders. Its strategic location right in the attractive New York City market, along with its revenue diversity coming from energy sales, capacity, and ancillary services, makes Ravenswood a great addition to TransCanada's growing North American power generation portfolio.

On the wind front, we commenced construction of the 132 megawatts Kibby Wind power project in Maine. The project is expected to be fully commissioned in 2010.

Finally in energy, after running the Portlands Energy Centre in Toronto in simple cycle mode during the summer season, we have returned to the final construction phase and we expect to commission that very important power generating facility in combined cycle mode capable of providing 550 megawatts of power in the first quarter of 2009.

We are pleased with our strong third quarter and year-to-date performance and the progress we've made on a number of major growth initiatives. We recognize global finance markets are experiencing severe turmoil. However, TransCanada's financial position remains solid. We conducted a sizable financing program in 2008 and our liquidity position remains strong. It is underpinned by highly predictable cash flows from operations, our continued access to capital markets and revolving bank lines of more than $2 billion.

I would now like to turn the call over to Greg Lohnes, our Chief Financial Officer. Greg will provide more information on our third-quarter results and additional information on our liquidity and capital resources. Greg?

Thanks, Hal. Good morning, everyone. As Hal mentioned, earlier today we released our third-quarter results. Net income for the third quarter was CAD$390 million or CAD$0.67 per share compared to CAD$324 million or CAD$0.60 per share for the same period last year, an increase of approximately 12% on a per-share basis.

Third-quarter 2008 net income included $26 million of favorable income tax adjustments and CAD$2 million of net unrealized losses resulting from the changes in fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts.

Third-quarter 2007 net income included positive income tax reassessments and associated interest income of CAD$15 million. Excluding these items, comparable earnings were CAD$366 million or CAD$0.63 per share in the third quarter of 2008 compared to CAD$309 million or CAD$0.57 per share for the same period last year, an increase of approximately 11% on a per-share basis. The quarter-over-quarter increase is due to increased contributions from all segments.

I will briefly review the third-quarter results for each of our business areas beginning with pipelines. The pipelines business generated net income and comparable earnings of CAD$173 million during the third quarter, an increase of CAD$10 million over the same period in 2007. Of note, ANR's net income in the third quarter increased CAD$5 million primarily due to higher revenues from new growth projects. GTN's comparable earnings also increased CAD$5 million to merely due to the positive impact of the rate case settlement in January 2008 and lower (inaudible) [and the expenses].

Next some comments on energy. Energy generated comparable earnings of CAD$202 million in the third quarter 2008, compared to CAD$156 million in the same period last year. Western Power's operating income was CAD$126 million in the third quarter compared to CAD$120 million last year primarily due to an increase in sulfur sales at significantly higher prices in 2008. TransCanada has been selling modest quantities of sulfur on a breakeven basis since 2005.

Western Power's operating income was negatively impacted in the third quarter 2008 by decreased margins from the Alberta Power portfolio due to lower overall realized power prices on both contracted and uncontracted volumes of power sold in Alberta.

Eastern Power's operating income in the third quarter was CAD$100 million, an increase of CAD$48 million compared to the third quarter of last year. The increase was primarily due to higher realized power prices in New England, increased water flows from the TC Hydro generation assets, lower overall cost per gigawatt hour on reduced purchase power volumes, and incremental operating income of CAD$9 million from the acquisition of Ravenswood, which as Hal mentioned we closed on August 26.

In September, the Ravenswood 972 megawatt Unit 30 experienced an unplanned outage as a result of a problem with its high pressure steam turbine. Although the repair costs and lost revenues associated with the unplanned outage have not been finalized, it is not expected to have a significant impact on earnings as a result of expected insurance recoveries.

Finally in power, TransCanada's combined operating income from its investment in Bruce Power of CAD$83 million in the third quarter increased CAD$19 million compared to third quarter 2007 primarily due to higher revenues resulting from higher output higher realized prices.

At September 30, 2008, Bruce A had incurred CAD$2.4 billion for the restart of Units 1 and 2 and approximately CAD$200 million for the refurbishment of Units 3 and 4.

Turning now to corporate, net income from corporate in the third quarter 2008 was CAD$17 million, compared to net income of CAD$5 million in the same period last. Excluding CAD$26 million of favorable income tax adjustments from an internal restructuring and the realization of losses in 2008 and CAD$15 million of favorable income tax assessments and associated interest income in 2007, comparable expenses from corporate in the third quarter were CAD$9 million compared to CAD$10 million in the same period last year.

Turning to the cash flow statement. Funds generated from operations were CAD$711 million in the third quarter, an increase of CAD$9 million when compared to the same period in 2007. Capital expenditures and acquisitions in the third quarter were approximately CAD$3.9 billion and related primarily to the acquisition of Ravenswood as well as the ongoing development of greenfield projects such as the Bruce A restart, Portlands Energy Centre, Halton Hills, and Cartier Wind, as well as expansion of the Alberta system and construction of the Keystone Oil Pipeline.

TransCanada's financial position remains sound. At the end of September, our balance sheet consisted of 53% debt, which included our proportionate share of joint-venture debt, 4% junior subordinated notes, 1% preferred shares, and 42% common equity. I would note that our debt on this slide is calculated net of cash.

TransCanada has conducted a sizable funding program in 2008 which consisted of a CAD$1.3 billion common equity issue in May and term debt issues of US$1.5 billion and CAD$500 million, along with a US$2.5 million draw on our Ravenswood acquisition bridge facility in August. In addition, dividend reinvestment planned proceeds are expected to approach $250 million in 2008.

TransCanada's liquidity position remains stable underpinned by highly predictable cash flow from operations, as well as committed revolving bank lines of CAD$2 billion and US$300 million maturing in December 2012 and February 2013 respectively. To date, no draws have been made on these facilities as TransCanada continues to have largely uninterrupted access to the Canadian commercial paper markets on competitive terms. TransCanada views its bank group as high-quality and its relationship with these institutions as excellent.

TransCanada is presently seeking to establish a further committed bank line in support of the Keystone Pipeline construction program and expects this to be in place in the fourth quarter of this year. Also in the fourth quarter, TransCanada expects to file a new US$3 billion debt shelf which will supplement the existing $3 billion equity shelf and the $1 billion capacity available under the Canadian debt shelves.

That concludes my prepared remarks. I will now turn the call back to David for the question-and-answer period.

Thanks very much, Greg. Before I turn the call back over to the conference coordinator, a reminder that we will take questions from the financial community first and once we've completed that, then we'll turn it over to the media. A reminder once again that we ask you to limit your questions to two and then if you have a follow-up to reenter the queue.

With that, I will turn it back over to the conference coordinator.

(Operator Instructions) Linda Ezergailis, TD Newcrest.

Thank you. I have a question with respect to the increased ownership of Keystone. I guess my first question is when will the other shippers have to exercise that 15% ownership option buy? But on a broader scale, I'm just wondering if we look at the US approximately $12 billion cost of that project, and moving from 50% to potentially 80% would add quite a bit more to your capital expenditure outlook for 2009 and 2010. Especially by my calculations, that could increase your equity needs over those years by up to CAD$3 billion.

I'm just wondering if you can give us an update and I realize there's a lot of instability in the capital markets. But just give us some of your initial thoughts on first of all when you might want to put in permanent financing either during or at the end of the project and how you might achieve that?

Linda, it's Hal. I would open first and then Greg and Russ may wish to add to this. First of all, it's an excellent turn of events for TransCanada to be able to increase our ownership interest in a pipeline that is so fundamentally sound and much in demand by the market, much in demand both on the oil supply end here in Alberta and also by the markets that we are aiming to serve down in the Wood River, Patoka, Cushing, and US Gulf Coast areas. It's a pipeline concept that has proven extremely popular with the oil producing community, but also with the oil refining community down in those markets in the US.

So as in all of our big strategic capital projects, we are aiming to own more of it rather than less of it and so it's a good turn of events for us to be able to increase our ownership. But we do recognize that there is a couple of challenges with this project. One on our side is the financing challenge and timing is important as to just how quickly we move into the expansion part of the project.

But also for our customers, we had very strong support in the open season but many of those customers have indicated that they have their own uncertainties with respect to the pace of oil development at Fort McMurray and other places here in Alberta. Hence the comment in my remarks this morning that we will be working closely with our customers on the Keystone expansion project to determine the optimal time to go ahead.

On the one hand we have to make sure the capacity is there when our first shippers need it, but on the other hand if there is a room here for some deferral of some of that construction, that's probably a good thing for all of us. So there are uncertainties at Ft. McMurray right now and we do need to be very careful about that.

But I would remind all listeners on this call that the commitments we've received are binding. They are long-term. They are generally in the range of 70 to 20 years. This is one of the best contracted oil pipelines anywhere in North America. It's a different model that we have chosen to pursue here, highly secure with these long-term contracts and those of course will be important to us as we move into the financing phase. We have the ability to finance a project that has that kind of contract and it's often not the case in the businesses that we are in.

I will turn it to Ross here. Russ, I don't know if you would add any more comments on the path forward for the development of Keystone.

The only thing I would add is to answer your first question on the exercising of those equity options, Linda. It would be early Q1 of next year sort of January/February that we will have those negotiations and discussions and they will make their election to exercise or not at that point in time.

And to Hal's point on the timing, we are having discussions with both our contractors, suppliers, as well as the shippers on finding the optimal way to meet the needs of all the parties. So we will have that construction schedule put in place probably over the next quarter here and then we will be able to give you more details as time goes on.

Linda, the financing challenge at 80% is obviously different than it was at 50%. And it has to fit into our cash flow profile and our own ability to raise financing. So that's really our motive for discussing what's the right timing to proceed. But I would ask Greg Lohnes to offer some additional comments on our financing options.

Sure, Hal. Thanks. Linda, I will be speaking more to our overall financing plan when we get together for the investor day. But just briefly, obviously we have a large portfolio of greenfield ahead of us. But greenfield is different than acquisitions like Ravenswood and ANR, where you need to have a large sum of money available on one particular day in order to close those financings.

So we feel that there is some flexibility in order to time access to the market. We were prudent on the debt side in August and accessed the market in a window for CAD$2 billion of debt and then we also drew down I think it was CAD$255 million on the Ravenswood facility. So a substantial debt capacity.

You'd asked about permanent financing and with regard to permanent financing, our view would be to wait until construction is completed at least at Phase 1 if not of the entire project. Obviously it's a large sum of money and we have indicated that we are prudent in the way we finance and the way we keep our balance sheet metrics and our rating agency ratios in check. We are working closely with the rating agencies and talking to them about our financing plan and have spent significant time with them discussing this project and others.

We prefer to finance with subordinated capital and we look at all of our various sources of subordinated capital which includes mandatory convertibles, preferred shares, potential divestitures, the hybrid market, which we accessed successfully a little while ago for CAD$1 billion. So we look at all these various sources. We also look at our LP.

As you know, these markets are in turmoil and there are windows and sometimes some of them aren't available, financing at the LP is fairly expensive right now with the high yields that that market is seeing on its units. So -- but we will be prudent and as we move forward, we look at all our available sources and that includes common equity if required.

Great, thank you.

Andrew Fairbanks, Merrill Lynch.

Good morning, Hal. I was wondering if you could line out as you see it sort of the sequence of events for the Alaska pipeline. Do you have a sense for how the process of firming up that project will move forward or any sense when you might be able to come to a consensus with producers on the shape of the project, the alternative projects, which pipeline will end up getting behind?

Sure, Andrew. First of all, our plan is fairly well laid out in the AGIA filings and the AGIA approvals that we reached with the State of Alaska. The first critical step here is that by midyear 2010, we will have completed an open season and there's two aspects to that. One is the formal open season where we invite parties to nominate for capacity for long-term shipping arrangement on the pipeline and there could be both existing producers in Alaska and those companies that are exploring on the north slope we would see potential for commitments from both camps there.

But of course the most likely shippers that are going to underpin this pipeline are the three existing Prudhoe Bay Producers. And so while the open season is out there in parallel with that, we are also holding discussions with those people in advance of the open season and leading up to the conclusion of that, and that is probably the single most important step in moving that project forward, are fruitful discussions with the existing producers on the north slope.

Many complicated issues there, both in terms of the nature of the shipping commitment, any ownership role that they may wish to take in the pipeline, and we've made it very clear that we are willing to accommodate them in that regard. And they have their own issues of course with the State of Alaska, all of those things need to be resolved.

The other major track and one that sometimes gets ahead of itself in my view on these projects is the regulatory permitting. It's obviously important that we get regulatory permits from the Federal Energy Regulatory Commission in the United States and in the case of the Canadian section, the Northern Pipeline Agency for the portion through the Yukon and Northern B.C. But I just emphasize that the commercial arrangements and commercial discussions with the major Alaska producers and any new shippers that might come along, that's really the critical step.

So we are commencing work on the regulatory front and we will be devoting a fair bit of time and energy to that, but we will be curtailing constraining expenditures on the regulatory front in a very disciplined way. I just observed that historic projects sometimes get ahead of themselves in terms of going down that regulatory path, spending a lot of money when the real issue is sorting out the commercial arrangements, and so that is where our focus will be for the next little while.

Right. So then you've begun discussions with the three majors and it would be reasonable to think of that as sort of a 12-month to 18-month discussion period just to try and set those expectations reasonably close to [what may well] happen?

I would agree with that. I would point out that I have been having discussions with the Alaska producers since I took this job in 2001. So this has gone on for a long time, but I acknowledge that the pace of those discussions has picked up and is likely to pick up in the next 18 months as we move towards that open season in midyear 2010.

Thanks, Hal.

Carl Kirst, BMO Capital Markets.

Good morning, everybody, and congratulations certainly on the quarter and the Keystone contracts. Hal, if I can -- [fact] on the Keystone and actually circling back to Alaska, starting with Keystone on the ownership shift here, was this a Conoco initiated move presumably to reduce their CapEx? And along with that, was there any funds paid to Conoco for their -- the NPV of their 30% equity stake?

And as you kind of expand that forward, does this have any follow-on implications for Denali or the merger of the two Alaska pipeline proposals, if indeed Conoco perhaps has not seen the pipeline as a core business.

I'll start out, Carl, and then I'll get Russ to fill in the details that he will be more aware of than I would be. First of all, on the ownership level of Keystone, we have worked very closely with ConocoPhillips from day one on structuring that project. And of course we've also worked very closely with ConocoPhillips on the Mackenzie Valley Project, so we have a long history of collaboration with that company and our relationship is very good with them.

Now, we have discussed from day one what is the appropriate ownership? And we started out the project 50-50. We thought that as we went through development, that was the right place to be, but both parties always acknowledged that at some point in the process it might make sense for a transition to a different ownership structure to occur.

I can't speak for ConocoPhillips. I don't know their decision-making process, but it's obvious that this is a period where all energy companies are looking for ways to reduce capital commitments and looking for additional sources of capital. So ConocoPhillips remains very committed to the project. They have retained a 20.1% interest in it. They are working very closely and constructively with us to move the project forward and they of course will be a major user of the crude oil when it gets particularly to the St. Louis area, Patoka Wood River in Southern Illinois.

So we saw it as an opportunity that has been cultivated from day one. We've always made it clear to ConocoPhillips that we would be interested in more ownership of that pipe. I think you know that our bias is to have very large ownership in these major projects. Sometimes that's there from day one and sometimes it increases over time as we move through construction and into operations.

So then I will comment briefly, Carl, on any precedent this may imply for the Alaska project. I think there is nothing particularly directly significant about this, but I think it should be recognized that it is indicative of the good relationship we have with ConocoPhillips. We've worked diligently with ConocoPhillips for seven years on exploring different ways to collaborate on the Alaska Pipeline Project and we will continue to do that.

I would be optimistic that they would see merit in our way of doing the Alaska project and bringing them on board with our project would be our objective at the end of the day. And Russ, I don't know if you would add anything on the Keystone or Alaska fronts.

Just to be specific about your question on payments in NPV, there was no payment up front for the Conoco share. Basically it will be done -- the equalization will be done at book value. It will be done via funding over time, so there's no immediate payment required today. And I would agree with Hal on his comments with respect to the producers at the current time focusing on their core business of E&P in a currently capital constrained environment which is a great opportunity for us to do what we do, which is own and build pipelines.

I think the other thing that I guess this shows is that companies like ConocoPhillips have a great deal of confidence in TransCanada's ability to construct something like this. The reason that they take ownership stakes in these large projects up front is often to ensure that they get built in a way that meets their needs and I think in working with Conoco over the last year, we've moved a long way in constructing Keystone to date. And I think they are confident in TransCanada's ability to execute these projects in a way that makes them comfortable. And as Hal said, we would hope that that would play well for us in our discussions with them to build the Alaska pipeline.

Great, and then one follow-on if I could. Russ, probably more for you. Just also with respect for Keystone on the binding open season, obviously that's closed, but can you comment on whether there were any further discussions on the Spurs to Houston, which I understood could be as much as 50,000 barrels a day? Is that something that is still very much alive? And if that's the case, how much would something like that cost and what might be the timing of knowing whether or not that might happen?

The lateral to Houston is probably in the neighborhood of CAD$300 million, so in the scheme of the project, not a large capital expenditure to make that connection. There is a couple of shippers that are interested in that lateral. Unfortunately the timing of our open season and the nature of open season didn't allow those shippers to put forward a proposal. So I would expect that we would have a follow-on open season in the next few months to capture those.

And as Hal pointed out in terms of our Alaska negotiations or any pipeline expansions that we move on, we tend to try to negotiate with the shippers' [present] agreements up front that meet their needs before we hold the open season, and this will give us some time to be able to do that. And then further from that, there is still some capacity potentially on the system to Patoka and Wood River post 2013, the way that we are going to operate the system. And we may hold another open season. We've had considerable interest in that piece of it as well. So I think you could see at least maybe two more open seasons on the system as it is designed today over the coming months.

Great. Thanks, guys.

Robert Kwan, RBC Capital Markets.

Good morning. Can you give us a more detailed attribution of the rough doubling of Eastern Power operations profit during the quarter, particularly given such a small amount of volume sold into the spot market?

Robert, it's Alex. I think primarily the reason for the really good results in the eastern business, as you may have experienced or heard, it was a very wet quarter in the Northeast and our hydro assets delivered much, much more energy than we would have anticipated in a normal Q3.

And do you have a sense as to how much that contributed to the earnings during the quarter?

I'm just looking. On a pretax basis, it was somewhere CAD$20 million, CAD$25 million.

CAD$20 million, CAD$25 million, okay.

We -- the other thing I would say is we obviously -- we had Ravenswood in for the month of September. And the other thing, we just had some pretty good returns from our marketing business.

Then just if I can ask one last question on for Keystone. Greg, have you had detailed discussions with your banks yet for the bank line you want to put in place in the fourth quarter particularly with respect to just the availability of the size of credit that you are going to be looking for? Is that something where you are going to be initiating the discussions ultimately?

Robert, we've had discussions. We've held initial bank meetings and we have commitments for approximately half of what we're looking for for that facility. We are looking for about CAD$1 billion facility to put that in place. And we would expect that we would be somewhere in that upper end CAD$800 million to CAD$1 billion.

And in the half that you've been able to secure, has that covered most of the banks in your existing bank group and are you going to be looking for new banks to come in? Or is that just the timing of people who have committed to date?

Is more a timing issue. In this environment, generally commitments aren't as large as they probably were a year ago. We are confident that we are able to do this facility we would expect within the existing bank group. So we do have a number of other banks that have showed an interest who would like to become part of the lender group to TransCanada.

Okay, great. Thanks, Greg.

Bob Hastings, Canaccord Capital.

Thank you. Just going to Ravenswood for a moment, did the CAD$9 million you are basically in the month of September, is that a good going forward rate because you basically have the Hess arrangement in for the rest of the year?

Yes, I really don't think you can use that as any form of a run rate, Bob. That's very much related to the Hess deal and probably isn't indicative of going forward.

So would you have any sort of expectations looking out for the rest of the year?

The rest of the year -- this year?

Yes.

(multiple speakers) Because isn't Hess going on for the rest of the year?

Pardon me?

Isn't the Hess arrangement going on to the rest of the year -- end of the year as well?

Yes, it is. It's a combination. What we earn from Ravenswood -- it's Glenn Menuz -- what we earn from Ravenswood in 2008 is a combination of what we would earn under the tolling agreement with Hess and obviously they're taking all of the fuel costs, etc. plus any amounts that we receive through the capacity payments in the capacity market or the capital market. That ends up being very cyclical or seasonal by quarter, usually higher in the summer quarters, much higher in the summer quarters and much lower in the winter quarters.

So as far as going forward, we are not looking to see a lot in the fourth quarter. But those are the factors that are impacting it.

Okay, thank you. Looking -- just a general question on the Canadian dollar, it has had a little bit of volatility and two questions I guess on that or two aspects of one is going forward sort of what is your exposure to the dollar from an operating basis? And secondly, what would be the impact given the large capital expenditures you have in the US? Is that fully picked up in tolls? Is there any risk they are from swings in the dollar or how have you protected yourself on that?

I will let Greg go first.

So generally with regard to income, we are long US dollars. So we are long about $180 million a year and so we have US income but also US interest payments. So as the Canadian dollar changes, a 0.01 change would have sort of CAD1.8 million impact before hedging. We have some hedging programs in place which would roll through our P&L. We run a rolling 12-month hedge program.

Specifically on Keystone is the tolls are set in US dollars. So it offsets the increase in costs from a Canadian perspective if you look at it that way. Basically it is a US project and the US tolls or the US shipping is paid in US dollars.

So if everything goes to plan, the lower Canadian dollar actually boosts up your Keystone earnings?

It will make it larger Canadian earnings in Canadian dollars, yes.

Bob, it's Hal. We don't really place too much emphasis on that. We look at US dollar investments generating US dollar earnings and the fact that it all gets consolidated in Canadian dollars I think everybody kind of understands that.

Yes, just people are looking at these swings and what they mean to everybody. We've had about a CAD$0.20 swing in the dollar recently, so to be clear, that -- if I'm saying CAD$0.01 decline, I can multiply CAD$0.20 times the 1.8, but then there's some hedging offset?

That's right, so that rolls through the P&L because they don't qualify for hedge accounting treatment and we mark those to market.

So I would see the full 1.8 on a reported earnings basis?

No, you won't.

Okay, thank you.

Because of the offset of the mark-to-market on the -- out of the money hedges.

The hedging would be more lumpy?

Yes.

(multiple speakers) you have a big gain or loss in any particular quarter?

That's right, because we keep rolling it out on a rolling 12-month basis and we've hedged about 50% of that.

Okay, good. Thank you very much.

Andrew Kuske, Credit Suisse.

Good morning. Just how do you see your balance sheet metrics on a go-forward basis? I ask the question in part because of the turmoil we've seen in the last call it two months. And the last time we went through some very industry-specific issues, we go back to Enron collapsing in late '01 and we saw the debt raters essentially get changed where the goalposts were quite dramatically, forcing a lot of companies to delever in a significant fashion. And that was very industry-specific and this is a broader deleveraging that we are seeing across the economy right now. What is your outlook on a go-forward basis where your balance sheet will be in a lot of your coverage ratios?

I think generally obviously we are in constant discussions with the rating agencies. We generally keep our balance sheet in the 60/40 kind of balance sheet. It looks like it's a little thicker on the equity side, but the rating agencies have different methodologies around how they treat certain things on the balance sheet including goodwill. So we work with them with respect to those ratios.

Generally I think we are in a pretty reasonable spot from a balance sheet perspective. Ratios that they use with respect to cash flow to debt etc., are fairly defined and we do -- are aware of those and we work with them on it. There are also qualitative criteria and a number of the things that we are doing are very positive from a qualitative perspective. You read the rating agency reports, they -- the Canadian regulated business which has no volume risk is seen positively by the rating agencies and as you can tell, we've been adding to the Alberta rat base significantly. And we have North Central Corridor and some expansions potentially in the Horn River and Montney areas, which are positive from that perspective.

We do obviously have a need for additional debt and we will need to look at the subordinated capital or equity markets in order to keep those in line over time.

Then when you think about your business mix and the direction it's going, are you trying to keep a fairly good balance between projects with good long-term contracts like Keystone and a lot of the PPA power plant facilities that you have right now and really a more merchant or unregulated type business? What would that divide be and how do you see that divide on a go-forward basis?

Andrew, it's Hal. We are first of all -- I make the broad comment that we are committed to deleveraging, that this has been a consistent direction within TransCanada over the past seven years. We have always moved to reduce the amount of debt on our balance sheet and we have argued very thoroughly I think with Canadian regulators for thicker equity on our Canadian regulated pipes. We are currently sitting at 40% equity on the Canadian regulated pipes and we would be delighted to see that equity thicken further. We think that it's a good thing for key infrastructure in North America to be less highly levered and to be as stable as it can be.

As we expand beyond the Canadian pipeline business, which is no longer the dominant largest business in our Company, we do look for assets like Keystone, where we have long-term contractual backstop. The power plants, of which we build many now in Ontario and Quebec, are very soundly financed and have good long-term contracts behind them.

We recognize there are opportunities particularly in our power business and to some extent in our storage business to create significant value for our shareholders by taking merchant positions in market circumstances where we are very comfortable with that. I think our track record speaks well for the astuteness of our people and what we have been able to do in terms of generating shareholder value from some of those positions.

But the base case always is that we would drive for a less volatile income stream. We particularly focus on the volatility of cash flow and we don't want to suffer significant volatility in our cash flows. And we do continue to move to a less levered balance sheet. We think that's a general trend in North America and that's a good thing, and we are not going to fight that direction. We think it's good for our shareholders too.

I would note that over the past two or three years we could have reported significantly higher earnings per share if we had been a little bit more adventurous in terms of both debt leverage and also in greater use of LP structures and things like that. We have the one LP in the States, which is a very rock solid MLP and we continue to run that in a very prudent manner. We are not big fans of a lot of exotic structures for doing things and I think relative to some others in the industry, we've been pretty conservative in that regard. All of which we think has set us up well to go through exactly the kind of period that we are in now. We raised CAD$1.7 billion of equity in 2007 and we raised CAD$1.2 billion roughly earlier this year. CAD$3 billion of new equity plus significant dividend reinvestment, that has been good for our balance sheet.

And I would also note that our finance group did a great job raising significant debt in August just to make sure we were ahead of anything that might come along, and we are obviously feeling very good about that today.

Okay, thank you.

Steven Paget, FirstEnergy.

Good morning. Bruce Power has announced that it is looking at a realignment as it goes in the home stretch of the restart in particular as ECL works on Unit 2. I'm wondering when that realignment might be complete and we can have a picture where the Unit 1 and 2 restart will be in about a year from now?

Steven, it's Alex. One thing I would say is that we were intending at our upcoming investor day to talk a little more fulsomely about Bruce and the restart. So I won't go into the depth today that I will there, but what I would say is that Bruce, as everybody knows, it really is a massive project and with any of these massive projects, as time goes on and you progress through the construction. And at the 1 and 2, we are very significantly through the big chunky parts of the refurbishment.

But as you go through these large projects, some things go better. Some things go as expected and some things go slower and really what I think you were referring to, what we are doing at Bruce is we are just seeing certain areas and particularly I think the area that has been the most challenging as it has really been from the start is the Unit 2 retubing project and that is the project that is being done by ACL. And we are seeing the lead unit, Unit 2, going a little slower than we would like. We are just taking this opportunity to reposition some of the labor force to be more productive as we work through that Unit 2 issue.

So for example, rather than have people waiting around, we have redeployed a significant number of the labor in the craft on site to working on other projects that are becoming critical path, things like valve refurbishment and some of the commissioning activities that we are getting into.

Okay, great. Thank you. My next question is on pipelines. Spectra announced that it is holding an open season looking for shipper commitments to ship both eastward to TransCanada as well as westward. Is -- are you -- is this a cooperative effort between you and Spectra or would your open season be in B.C. be more in competition with them there?

We would be more in competition. What we are offering is an integrated toll through the Alberta system and its somewhat dependent upon us receiving a favorable decision to our jurisdictional application that's in front of the National Energy Board currently. We expect that decision in early Q1 which has dovetail with what we've offered the marketplace here. So basically what we're offering is an integrated service, so it wouldn't be a service that's combined with a West Coast open season.

As you know, we've announced our own open season in the similar area that I think we announced it yesterday. It's on our website. It will run from October 27 through to November 21 and it's a follow-on to the nonbinding open season that we held here a few months ago. So I guess we are running them at the same time as the competition and the marketplace will decide which direction they want the gas to go.

Okay, great. Finally if I may, just a couple quick comments on the schedule for the open season on [dawn] connector. Are you -- what's your schedule there?

Again, we are just assessing what we -- the information that we got back and determining whether or not there's sufficient support to move forward with a -- with a binding open season. There's a lot of interest in moving gas that direction as a result of increased production both in shale plays in the Rockies that want to move gas east. Our system has some advantages in moving that gas east, but there are other proposals in the marketplace and I'd say stay tuned on that one as we move forward and assess what we have and we will be announcing our next steps probably in the next three or four months.

Great. Thank you, everyone.

Barry Klein, Citi.

I have a couple questions on the energy division. First, you touched briefly with another caller on Bruce and Unit 2 retubing. I was just wondering if that's going to be -- of the remaining cost, will that take the lion's share of this cost? And how much are -- how much is remaining on the costs for the refurbishment? And then with regard to the sulfur sales that you touched upon in the comments, I guess how much of the earnings related to the sulfur sales and how much of that should be considered continuing versus one time?

Sure, I think I'll talk about the sulfur one first because that's pretty simple. The sulfur, I would really think of that as a one-time item. It was about CAD$17 million pretax in the quarter. And that really what the sulfur block was was it was just a residual asset left over from sale of some previous businesses of TransCanada. And we've really been selling that sulfur for several years, really at kind of a breakeven rate.

And then in 2008, we all of a sudden saw a massive run-up in the value of sulfur, so we took that opportunity to sell basically the entire remainder of the sulfur block. So I just think of that as a one-time item and then -- sorry?

Okay.

And then with respect to Bruce -- do you have the total numbers that we've spent? So we are right now at about CAD$2.4 billion on the restart. The ACL contract is basically a fixed-price contract, so any slowdown that they have is -- or any challenges that they've had on the Unit 2 is not really relevant in terms of increased costs and they would be significantly through their total cost of their -- of that retube project.

As noted in the quarterly report, the CAD$2.4 billion that Bruce has spent to date is at 100% ownership.

Yes, so our share would be about half that.

Okay, and how much was the total contract for?

Well, the total estimate for the project I think at this point is in that CAD$3.4 billion range. So you can think of it that we are two thirds, roughly two thirds down the whole exercise.

Got you. Thanks a lot.

Sam Kanes, Scotia Capital.

Thank you and good quarter, gentlemen. I have several balance sheet and credit questions. Maybe I'll start with some fine tuned clarity on your foreign currency hedges. Would you say roughly I guess 50% on a roll-forward basis. Is there any skew to that? Like some folks will do 80/60/40/20 or some other relationship to that? Is it just straight 50% month in, month out?

It varies, just depending on our view of the market. But it's just generally around that. It's a very small number when we look at the overall scheme of things.

But it does vary, so you don't have a mathematical formula. Okay. Alex, TC Hydro, you said CAD$20 million, CAD$25 million of pretax. That was the difference I presume from normal hydro levels on a long-run basis for those assets. Is that correct?

Yes, I think just as an example, Sam, I think we hit the sort of 100-year average or 50-year average hydro production for those facilities. We hit that in early September, which gives you a bit of an idea of just how productive they've been.

Thank you, that's helpful. Going into your gas storage business, read it, reread it. It sounds like pretty much you are 100% hedged every which way and that's just a simple answer to it.

Yes, I think that's a fair statement particularly for the next year.

Switching to capitalization and what's on your balance sheet and what credit rating agencies as you were saying obviously look at different things different ways. What does your balance sheet currently have for McKenzie capitalization, Alaska capitalization, and all other capitalizations and how are the rating agencies looking at those?

We don't capitalize anything on Alaska. The financial statements disclose that capitalization in McKenzie was I think around CAD$140 million.

Okay, so the CAD$140 million for instance, would those agencies look at that as equity? I presume not.

That's not really material to their overall review of the balance sheet metrics.

Okay, that's all I have. Thank you.

Brian Beargie, Legal & General Investment Management.

Good morning. Just -- I apologize if I missed this. The CAD$2.5 billion acquisition facility, that is drawn?

Sorry, you are referring to the Ravenswood acquisition facility?

Right.

Sorry, so we drew down US$255 million on that facility as a portion of closing. The balance of that bridge facility then expired.

Okay, so it's basically US$255 million drawn, is that correct?

That's correct.

Okay, and as far as your outstanding commercial paper balance, what is that right now?

It's a little in excess of CAD$1 billion right now.

Okay, CAD$1 billion.

We are sitting on significant cash, which offsets against that. We are probably net about CAD$400 million.

There was about CAD$700 million in cash on the balance sheet at the end of September, Brian.

Okay, and just I guess this is a point of clarification for bondholders. When you look at your preference, you talked about preferences for subordinated capital and expectations as far as getting the bank facility done? As we all know, the subordinated capital market is all but gone especially if you want to do preferred, you'd certainly have to pay up a lot to do that. Banks are constricting credit right now. So you are trying to figure out your ability to get the other half of the facility financed.

I guess as we head up into the investor Day, are we going to get little bit clearer picture than in the past about I guess the timing of capital expenditures and just trying to figure out a little bit more specific sources and uses as we head into what I would call very uncertain times? Then the next 12 to 18 months?

Yes, Brian, we've got some excellent charts which will lay out what the capital expenditure program is and what our funding program looks like. So I think there will be significant information on the sixth in that regard.

Actually, I look forward to seeing that. Thank you very much.

Ross Payne, Wachovia.

Thank you. A quick question on the shippers that are engaged on the Keystone project. Are they going to share any cost overruns if there are any, anything in the contracts on that?

Yes, on the expansion, the shippers share 75% of those costs. TransCanada incurs 25% of those costs and then we just adjust the toll accordingly. On the base Keystone, which is the one under construction, once we put the pin in the capital, we share those ups and downs 50-50 with the shippers.

Okay, and how much of the pipe has been purchased on this project so far?

The bulk of the pipe for the first phase of the project has been purchased. Minimal amounts have been -- I guess we are in the process of negotiating the contract for the second phase of the project currently and that was part of the discussion. Hal had earlier in terms of timing of those expenditures and the timing of mill space, the timing of contractors. All of those things will play into our scheduling over the next quarter as we sort out when exactly our shippers want this capacity in place.

Okay, and I assume prices are moving down for that?

That seems to be the direction that at least steel prices are moving at the current time and I would expect that the mill space and others would follow as well. We are seeing a number of projects across the globe right now being canceled which has had the impact of reducing demand for steel, at least perceived demand for steel, and we ha seen those prices come off here a bit.

Good. Thank you.

Carl Kirst, BMO Capital Markets.

I'm sorry, just a couple of quick clarifications on Keystone. The first is -- are the debt costs a pass-through to the shippers on both phases?

No, the debt costs aren't a pass-through on both phases.

The debt costs are not?

No. There's a fixed number in our shipping contracts with them that were set at a number that we are still comfortable with.

Okay, then just going back to the timeframe and understanding kind of the flexibility that's needed now, as we have kind of shifted from sort of an early 2012 to just generally stating 2012, is this something also that can slip into 2013? Or is it really just a matter of I guess gauging within that one year?

I think it depends on our shippers' desires. We have the ability to go into 2013. If that's what they want us to do and as you see by the drawing, I mean what's critical to them is getting to the Gulf Coast some time in 2012. The building of the leg from Hardesty to Steel City, the direct leg, doesn't necessarily need to be done in 2012 if that's not what they want to do. So that piece could move into 2013 if that's what our shippers wanted us to do.

Great, appreciate the clarification. Thanks, guys.

A follow-up from Bob Hastings, Canaccord Capital.

Thank you. That last question was mine as well, but maybe to be a little bit more clear. I think you said that the debt costs weren't -- that debt costs have risen, you end up having to swallow that yourself on -- is that on both phases or just one?

On both phases.

Okay, and you said you are comfortable with any changes there. So that means that they would have no certificate impact on your expected return on equity at this point?

Not -- we've run various scenarios and we don't think it has a material impact on our economics at the current time.

We are funding more in the shorter term during this particular time. It's a long life project to carry debt over a long number of years.

Right. You have said before, before you moved up to the 83% capacity utilization, I've given some sort of metrics around what kind of returns you might expect and how much needed to be shipped to your spot. Now that you are at 83%, is it to achieve your required returns, do you have to rely much on the spot -- additional spot sales or does the 83% sort of hit your hurdle rates?

The 83% gets us to the low-end of our hurdle rate and actually as you pointed out obviously an additional 80,000 barrels a day is substantial in that regard. We only have on the full system 120,000 barrels a day available for spot And in sort of our base case economics, we only run with half of that spot being shipped on an average day. So the difference between an average day or the difference between spot and not spot is a matter of about 50 basis points in our return. So at the bottom end of the return, I think you can think of numbers around seven without any spot all up to 9 with some expansion and some additional firm volumes on the system.

So that's sort of the range that was in that sort of seven to nine kind of range. I would say that it's tighter now. Our opportunity for upside is less because there's less spot volume, but on the downside as well there's less downside for us. It's a fairly narrow band of return or expected return that we have now.

Okay, is there --? We've seen some of these large projects get funded in different ways. Is there anything in your contractual arrangement that basically says the equity -- what you are allowed to capitalize into the rate base as you are going through construction period, is all debt with the equity financing done at the end or is it sort of just uniformly assumed debt equity balances?

There's no contractual commitment on how we finance ourselves through construction or even post-construction. The tolls are set off a cost estimate and a deemed capital structure, if you will. How we finance ourselves over the construction period in the long haul is really up to us.

Okay, there's obviously a lot of moving parts to this because you are negotiating with a lot of people at this point and some costs are going up and some costs are going down. But is it fair to say that where you see yourself today then is that you've still got negotiations and therefore sort of some costs might be offset by other savings?

Yes, I think that is where we would be sitting today. As I said, we're still comfortable with our estimates that we put out in the marketplace.

Okay, thank you very much.

Bob, it's Hal. I'd just add one thing to that that we haven't talked about today, and that's that the pace of construction on Phase 1 has gone very well. This summer season was really critical to us. We wanted to get off to a good start. We set out certain targets on both the Canadian and US sections for how many miles of pipe we'd get in the ground and how much work we'd get done on major river crossings and things like that. I just add everything Russ has said that the first season of construction went very well. We are a bit ahead of our targets and we are in a good position to get the first part of it done next year.

Excellent. Thank you very much.

Thank you. (Operator Instructions) Robert Kwan, RBC Capital Markets.

Thank you. Just wondering whether the guidance you gave on the natural gas storage segment coming out of Q1 is still good for the remainder of the year?

Robert, it's Alex. I think my guidance I had given was that we had earned about half of our expected -- the results from the storage business in the first quarter, and I would say we are probably slightly more bullish on -- than that original guidance.

Okay, then the last question I had was you booked a profit in G&A on the pipeline segment. You talked about capitalized costs. Was there any amount that related to previously expensed amounts that you capitalized and then drew back into the quarter?

It's Glenn, Robert. Basically what you are seeing there is because we were incurring the costs on the expansion ourselves, now they've rolled into the joint venture, so we are recovering some of that through the partnership arrangement.

Okay and how much of that, Glenn, was in the quarter?

After-tax about CAD$0.01 or so.

Okay, great. Thank you.

Scott Haggett, Reuters.

I'm wondering if you can give me a bit more clarity on the Alaska negotiations? Have you -- are you actively offering stakes in the line to the North Slope producers yet or is that still to come?

Well, Scott, we made it clear in our AGIA filings that we are prepared to do that and that's a fairly significant statement. There are other pipelines that we built where we don't offer those kind of stakes. We are very clear that such ownership stakes would be offered in return for long-term shipping commitments and working out all the details of that with those potential shippers is as you can imagine a very complicated process. Many issues to discuss there.

So yes, we are those discussions today. We have been in those discussions for some time. In fact, we were engaged in those discussions with a couple of the producers before we made our AGIA filing. So this has gone on for a long time and we hope to have that greatly progressed over the next 18 months so that we will have things pretty well lined up as we go into that open season in mid-2010.

Have the producers given you any indication that they are willing to walk away from their competing proposal and go ahead and ship on your line?

Well, we simply put to them the advantages of being involved in our project, including the fact that our project is strongly supported by the State of Alaska, and that is obviously pretty important. So these are discussions that cover many, many issues and of course they are not going to express a willingness to walk away from their project until everything is agreed between us.

Thank you.

Norval Scott, The Globe & Mail.

Is the strong interest from shippers in the Keystone expansion indicative in any way of the shift in sentiment to get more bitumen processed in the US rather than by upgraders in Alberta?

Norval, our message has been consistent throughout this that if the marketplace wants to ship upgraded crude oil to refineries in the United States, then we are prepared to do that. In fact, our Keystone Pipe system would have greater volume capacity if it was shipping low viscosity light oil than shipping bitumen blend. We are there to move whatever the market wants us to move. And so I really don't know whether it's indicative of that.

What I think it is indicative of is confidence on the part of the producers that notwithstanding the weak oil price, there are significant volumes coming on at Fort McMurray and in other parts of Alberta and those volumes do have to get to a market. And as has always been the case over the last 20 or 30 years, it's very important to have assured capacity to get volumes out of Alberta and into the end markets. People don't want to be bottlenecked or backed up here into Alberta where they would suffer from a very wide price differential.

So holding capacity and having assured capacity to get to high-value markets is pretty important to the producer shippers. We are also seeing significant interest from refiners in the US Gulf Coast region who want to have assured capacity or assured access to bitumen volumes in Alberta. So a number of different shifts are occurring.

I think all of it underpins our original thesis going in here that we saw significant growth in all forms of crude oil out of Western Canada, upgraded and non-upgraded, and we saw the most significant and attractive demand location being the US Gulf Coast and some of the US Midwest markets on the way there. And so we have specifically designed the Keystone Pipeline to connect a region of growing supply with a region of strong demand and so far that's proven to be a very good idea. That has worked well for us.

Okay, one follow-up if I may. I mean, would you now say -- with the Gulf Coast wanting all this crude from Fort McMurray, have you now won the battle to supply that market with this announcement today?

Sorry, have we what --?

Have you won the battle over your competitors to supply that market today do you think?

Well, we see several million barrels a day of potential increased crude oil production out of Alberta over the next 20 years. So we obviously feel very comfortable that we now have a high volume, very low cost, attractively structured system that delivers what producers want to get crude oil from Alberta to the Gulf Coast. But there's much more to come in this and we may well see other tranches of crude oil go to other markets.

Enbridge's big system obviously delivers a lot of crude oil into the Chicago market and we did not want to compete with that. We recognize that's a strong market and they've got a good system, so we chose to go in a different direction.

As to how volumes move over the next 10, 15, 20 years, that remains to be seen. But I would say we continue to focus on markets that are going to be attractive and stable and that really want Alberta crude oil over the long term and in our view the US Gulf Coast is the best place to be and that's where we are focused. We will look at other opportunities as time goes forward.

Thank you.

Carrie Tait, The National Post.

Sorry if you've addressed this already. I am just wondering how much you've seen your debt costs go up on what you are negotiating for on Keystone?

Well, the way we are structuring the Keystone facility is as a backstop facility for running a shorter-term program in the commercial paper market. So it's really a backup. Certainly if we drew on it, we have seen a fairly significant run-up in costs in the several hundred basis point range. But we've kept the facility short-term in order to keep costs down. Obviously you've seen in the marketplace that longer-term facilities are quite expensive.

And then we would plan then as we see the market adjust to deal with extending, amending, or otherwise dealing with that facility after the first year. But we would have an ability extended out to two if we need to.

Okay, so is the CAD$1 billion facility just a one-year facility?

With an ability to term it out for a second year.

Okay, so then you are hoping that you could perhaps renegotiate it then?

Yes, we certainly would. We will be in service by 2009 with the first phase at Keystone. And so at that time, we would expect to be in a better position to deal with the balance of the borrowing needs for completion of the facility.

And that is the traditional way of financing in any market. Construction is usually financed with short-term funding and then once construction is complete, we put permanent financing in place for the facility. So the current environment hasn't changed our approach to financing. But as you point out, in the short run, we've got higher costs than we've had in the past.

Okay, thank you.

[Hun Yun Lee], Dow Jones.

I just wanted to ask a couple of quick questions on Keystone. You mentioned that the potential delays in the oil sands that this could affect the timing of the Keystone expansion. I don't know if I heard you correctly, but I think you mentioned a one-year delay so that would go into 2013, as to 2012?

Yes, I mean two comments here generally. One, there is some flexibility probably measured in months or periods of maybe 12 to 18 months where we could see a delay in certain volumes coming on. But I'd emphasize that most of the volume -- in fact all of the volume that's going to flow through the base Keystone project and most of the volume is going to flow through the expansion will come from projects there are already under way today. And these projects are not going to be canceled or curtailed, but these are major investments that people are making and they want that crude oil flowing to markets. There just may be some delay in their project, but not a cancellation or anything like that.

So for most of the volumes that we are looking at both in the base Keystone project in the expansion, there is no question about the volume coming on. That's why people have been able to sign 17- to 20-year long-term contracts. But it may be advantageous to both TransCanada and its shippers to delay the on stream date by some number of months or maybe at the outside maybe by as much as 18 months. But not a long -- not an issue where we are worried about long-term cancellation of projects.

But as we look at expansion of Keystone beyond that, and I've emphasized that the expansion of Keystone in future years through looping and more horsepower is really attractive to TransCanada. That's a major driver of long-term value for us. That will of course depend on new projects going ahead. There are a number of projects that are in regulatory process today and no doubt the price of oil will drive the decision by the developers of those projects as to when they go ahead. So longer-term extension volumes are a little bit more of a question mark right now.

Just to -- would that involve the potential expansion to Houston, which would jack it up to 1.5 million barrels a day or [0.5] million barrels a day -- sorry. Is that one of the expansions that you are mentioning?

No, I think that one is more driven by that there is existing demand in the Houston area, existing refineries that want access to that Canadian crude oil. So those -- I would say that that lateral expansion wouldn't be related to the kinds of things that Hal was saying. There isn't additional capital that needs to be spent at those facilities to take that crude oil. It's just that those parties weren't able to put in place all of the approvals and those kinds of things necessary to meet our deadlines on our current open season.

So our follow-up on open season will be shortly after this one and I would say that if it's successful, the delivery dates to the Gulf Coast have probably the least amount of flexibility in them. As I said, the delay going from Cushing to the Gulf Coast is something that those refiners want in place relatively quickly. If we do have flexibility, it would be on the upstream portions of the pipeline.

Great. Thanks very much.

There are no further questions at this time, gentlemen. I'm sorry, we did just get a follow-up question from Norval Scott from The Globe and Mail.

Sorry. Just one follow-up. With regard to the changed agreement with ConocoPhillips on the equity stake in the pipeline, did you actually -- was that just an agreement you came to or did you have to pay Conoco anything or how does that actually work?

There's no payment to them. It's basically it's just a shift in ownership. So moving forward, we will pick up a larger percentage of the cost and equalize our expenditures to that or chew up our expenditures to that 80/20 split over the coming years. It will take us quite some time actually to get equalized to the 80/20 split. There's no upfront payment or anything like that.

Great.

Thank you. There are no further questions registered at this time, gentlemen, so I will return the meeting back to you.

Okay, thanks very much. I would like to thank all of you for participating this morning. We very much appreciate your interest in TransCanada. To the extent anybody does have any further follow-up calls, we are available both on the investor side as well as the media side. Again, we appreciate your participation and we look forward to seeing many of you at our upcoming investor meetings in early November. Thanks.

Thank you. The conference call has concluded. You may disconnect your telephone lines at this time. We thank you very much for your participation.