TC Energy Corp (TRP) 2010 Q3 法說會逐字稿

Good day, welcome to the TransCanada Corporation 2010 third quarter results conference call. I would now like to turn the meeting over to Mr. David Moneta, Vice President of Investor Relations and Corporate Communications. Please go ahead, Mr. Moneta.

Thanks very much. Good morning, everyone. I would like to welcome you to TransCanada's 2010 third quarter conference call. With me today are Russ Girling, President and Chief Executive Officer; Don Marchand, Executive Vice President and Chief Financial Officer; Alex Pourbaix, President of our Energy and Oil Pipelines; Greg Menuz, our Vice President and Controller; and Greg Lohnes also joins us, he is joining us from our Toronto office this morning.

Russ and Don will begin with some opening comments on our financial results and other general issues pertaining to TransCanada. Please note that the slide presentation will accompany their remarks. A copy of the presentation is available on our website at transcanada.com and it can be found in the Investor Relations under the heading events and presentations. Following their prepared remarks we will turn the call over to the conference coordinator for your questions. During the question and answer period, we'll take questions from the investment community first, followed by the media. In order to provide everyone with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have additional questions, please re-enter the queue.

Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments and key elements of our financial performance. If you have more detailed questions related to some of our smaller operations or your detailed financial models, Terry and I would pleased to discuss them with you following the call.

Before Russ begins, I would like to remind you that our remarks today will include forward-looking statements that are subject to important to 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.

Finally, I'd 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 operation. These measures do not have any standardized meanings under GAAP, and are therefore considered to be non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities. These measures are used to provide you with additional information on our operating performance, liquidity and our ability to generate funds to finance our operations. With that, I'll turn the call over to Russ.

Thanks, David, and good morning, everyone. Thank you very much for joining us today. I'm pleased to report that TransCanada posted solid third quarter results. If you look at our net income and earnings per share year over year, we saw that figure climb by approximately 8%.

As I told you last quarter we have accomplished this by continuing to do the things that have made us successful for a number of years. That is, following a disciplined approach that focuses on growing TransCanada's core businesses. We are currently growing those core businesses by focusing on completing the remainder of ourambitiousCAN$21 billion capital program. In the future, we will continue to reinvest in additional growth opportunities where we havewe have competitive advantage, we will grow our earnings and cash flow and deliver long-term shareholder value.

TransCanada's core businesses of pipe and energy continued to perform well in a very challenging business environment. Net income applicable to common shares for the third quarter was CAN$377 million or CAN$0.54 per share. Comparable earnings were CAN$374 million or CAN$0.54 per share. Comparable EBITDA for the third quarter was CAN$1 billion and funds generated from operations in the third quarter were CAN$861 million.

Also today, the Board of Directors declared a quarterly dividend of CAN$0.40 per common share for the three months ending December 31, 2010.

While we did see year over year increases in third quarter earnings, the quarter was not without its challenges. Power prices in our core Alberta and northeast US markets where we have exposure to market prices continued to be weak which of course impacts our bottom line. And with natural gas prices hovering in the mid CAN$3 range, conventional gas production has declined impacting throughputs on our Canadian pipeline systems. We are confident in a recovery of energy commodity prices, however, the timing of that recovery is dependent upon weather, economic recovery and demand growth. TransCanada is well positioned to benefit as and when that recovery occurs.

As we have said before, the majority of our business is not affected by short term fluctuations in commodity prices and it has that stable base that underpins our large capital program. Over the past quarter, we have made substantial progress bringing some of those major projects on line and we have advanced several others. When I spoke with you last quarter we had just celebrated the start of commercial operations of our Keystone pipeline system near St. Louis, and for over four months now oil has been flowing to refineries in the Wood River and Patoka area under interim contracts. The first phase of the Keystone pipeline has a nominal capacity of 435,000 barrels a day. TransCanada is now poised to mark another significant milestone in the Keystone project, that is the extension to Cushing which is now over 90% complete. This section of the Keystone project should be operational in the first quarter of 2011 and will increase our capacity from 435,000 barrels a day to 591,000 barrels a day. Firm and binding long-term contracts are in place for 535,000 barrels a day of crude oil to the Midwest including Cushing, that commenced currently with the start-up of the Cushing segment. These contracts represent approximately 90% of line's capacity. With the startup of Cushing, we will see a significant increase in cash flow from the Keystone project.

The Keystone Gulf Coast expansion continues to progress well. We remain confident that this crude oil pipeline should receive its final environmental impact statement by the end of 2010 or early into 2011,and a presidential permit to proceed with the construction in the first half of 2011.

I'll remind you that the market has supported this project in a substantial way. Shippers have signed long-term contracts for 380,000 barrels a day or about 75% of the Keystone expansions' initial capacity to deliver oil to refineries along the Gulf Coast. I'd remind you that these shippers are not only Alberta producers but Gulf Coast refiners who are looking to diversifying their source of supply of crude oil. When combined with the base Keystone system, TransCanada has binding signed contracts with producers and refiners to transport crude oil for an average of 18 years for a volume of 910,000 barrels a day, which is approximately 83% of the line's 1.1 millionbarrels day of capacity. These contracts demonstrate Keystone is very much needed by the marketplace to replace off shore imports into the United States.

Recently we also announced open seasons for our Bakken and Cushing market link pipelines that will transport crude oil on the Keystone expansion. Bakken has become the fastest growing domestic US oil play, while Cushing is the largest crude oil storage hub in North America. With respect to Bakken, TransCanada would take receipts of up to 100,000 barrels a day of crude oil at Baker, Montana, and deliver that crude to Cushing, and Port Arthur, Texas. On Cushing market link, our Company would take receipts of up to 150,000 barrels a day of crude oil at Cushing, Oklahoma, for delivery to the US Gulf Coast. If companies express interest in shipping their crude oil in these lines, US domestic crude could make up to 25% of the volume transported on the Keystone expansion.

Now moving to the gas side of our business, construction began this summer on our CAN$155 million Groundbirch pipeline project in Northeast British Columbia which will connect the Alberta System to the [Verlithic] shale place in northeast British Columbia. The pipeline should be operational in the fourth quarterof this year. And Groundbirch has firm contracts for 1.1 billion cubic feet a day of natural gas that comes on line between 2011 and 2014.

The CAN$310 million Horn River pipeline continues to move through the regulatory process. When you add its contracted natural gas volume of 540 million cubic feet a day to our contracts from Groundbirch, TransCanada will bring on a total of about 1.6 billion cubic feet a day of BC shale gas to the market over the next four years. This will help offset the Western Canadian sedimentary basin supply that we have recently seen decline.

I would also point out that we have requests for service from the northeast BC region for an additional 1 billion cubic feet a day and we expect that interest to turn into contracts in the coming months. So between now and 2014 we could potentially connect up to 2.6 billion cubic feet a day of shale gas to our system.

On the US side of our gas pipeline business, Q4 should also mark the completion of our Bison project, the CAN$600 million line is expected to begin deliveries from the US Rockies to markets in the Midwest United States later this year. Bison has long term contracts for CAN$407 million cubic feet a day which is 100% of its capacity.

In Mexico, our 305 kilometer Guadalajara pipeline project continues to takes shape. Construction of the CAN$320 million pipeline is approximately 40% complete. And as we have mentioned before, 100% of that capacity is subscribed by CFE which is the Mexican state electricity company.

As well as celebrating the beginning of Keystone's commercial operations last quarter, TransCanada and ExxonMobil's pipeline project also marked the end of a very positive open season. This was the first time in Alaska North Slope's history that a project to deliver natural gas has been tested in the market place. The project received multiple bids from major industry players, for significant volumes. The project team will continue to work over the next several months to resolve the conditions placed on some of those bids by shippers and we're very hopeful that the process will result in binding agreements to transport that gas to the market place.

Now, moving over to the power side. Another project that has been part of our ambitious CAN$21 billion program marked a major milestone this quarter. We announced last week that the 683 megawatt, CAN$700 million Halton Hills generating station in Ontario is now officially operational. It will operate under a 20-year power purchase agreement, generating stable earnings and cash flow for the next two decades.

In addition, we just announced this past Monday that TransCanada's Kibby Wind project is operational. The CAN$350 million project's second phase of 22 turbines is now producing power. The 132 megawatts of clean, renewable energy produced by 44 turbines has the ability to produce enough power for 50,000 homes in the state of Maine.

Construction of our 575 megawatt Coolidge generating station is 90% complete and the CAN$550 million power plant should begin producing power in the second quarter of 2011. Again, 100% of the energy and the capacity from the Coolidge plant is contracted to the local utility, the Salt River Project, for 20 years.

Moving to Bruce Power. Refurbishment of units one and two at the Bruce Power A site continues to progress well. AECL is expected to wind down its work on unit two by the end of this year and unit one by the second quarter of 2011. The last of the 960 calandria tubes were installed in the reactors in October. These tubes house the fuel channel assemblies that cool the uranium fuel during operation. This installation marked an industry first for Candureactors worldwide.

You can appreciate that whenever you take on a project like this that has never been attempted before, there will be challenges and delays. But we are moving forward and I believe this project is now in the home stretch. Once regulatory approval is received, Bruce expects to be begin commissioning of unit two in the second quarter of 2011 and it should be operational in the first quarter of 2012. Commissioning of unit one should begin in the third quarter of 2011 with full operations scheduled for the third quarter of 2012. TransCanada's share of the total capital cost is expected to be approximatelyCAN$2.4 billion, an increase of CAN$400 million from the last formal budget update in Q3 2009.

On October 7, the Ontario government announced that it would not proceed with the Oakville generating station. TransCanada has begun to negotiate with the Ontario power authority on a settlement which would terminate the contract and compensate TransCanada for the economic consequences associated with the contract's termination.

Ontario is a large province and we know that there's a need for power and infrastructure. TransCanada can help meet that need as it has done with projects such as Portland's energy center and the Halton Hills generation station. As the government develops its long term energy plant, we would hope to play a significant role in the development of safe and reliable and efficient power for the province.

And lastly a comment on our main line negotiations. We continue to work with shippers to develop a proposal that would improve the competitiveness of the western Canadian sedimentary basin while improving the Canadian mainline (inaudible - background noise) and certainty. We have been meeting and talking with key stakeholders for months now and we are hopeful of reaching a negotiated settlement. We continue to listen to our customers' concerns, understand those concerns and try to find the very best way of adapting to the changing market.

The mainline is a very important piece of North American infrastructure that will be needed for many years to come. The supply patterns of natural gas are changing and we have to change with them. But I do believe that all parties recognize this value and we are hopeful that we can come to a mutually beneficial agreement.

In conclusion, over the next few months, they look very positive for TransCanada as a number of our large scale projects become operational. Halton Hills and Kibby Wind are now on line and we continue to progress Groundbirch, Bison, Guadalajara, the Keystone extension and the Coolidge project. All of these projects will contribute greatly to the Company's bottom line, generating significant cash flow and earnings in the months and years ahead. We are mindful, however, of the challenges of a depressed economy in both the Canada and the United States, but our large scale, stable asset base will allow us to weather that storm, complete our CAN$21 billion capital program, grow earnings in cash flow and provide a platform for ongoing investment and growth for many years to come.

I'll now turn the call back over to Don Marchand who will provide you the additional details of our third quarter 2010 financial results. Don?

Thanks, Russ, and good morning, everyone. As you know earlier today we released our third quarter results. Before I get into the details I would like to highlight a few key elements for you.

First, the diversity of TransCanada's assets contributed to higher earnings and cash flow quarter over quarter even though lower power and natural gas prices continued to impact a portion of our business. Second, we are successfully advancing our unprecedented CAN$21 billion capital program for the long term benefit of shareholders. We have now invested CAN$13 billion in the program and over CAN$8 billion of these projects have either begun or are about to commence operations. Keystone, the Halton Hills and Coolidge power generating stations, the second phase of the Kibby Wind project and the Bison, Groundbirch, and Guadalajara natural gas pipelines are expected to generate significant EBITDA next year as they enter full commercial service.

And last, TransCanada's financial position remains strong. We have completed our financing requirements for 2010, and are well positioned to fund the remainder of our capital program in 2011 and 2012. I'd now like to take the next few minutes to elaborate on these themes in our third quarter 2010 results.

Net income applicable to common shares in the third quarter was CAN$377 million or CAN$0.54 per share compared to CAN$345 million or CAN$0.50 per share for the same period in 2009, an increase of 8%. Comparable earnings in the period were CAN$374 million or CAN$0.54 per share compared to CAN$335 million or CAN$0.49 per share in 2009.

As we mentioned in our last conference call, we expected to receive National Energy Board approval of the three year Alberta System settlement in the third quarter. That did happen, and we recorded CAN$30 million of net income or CAN$0.04 per share as a result of the higher allowed return under the settlement,CAN$20 million, or CAN$0.03 per share of which related to first six months of 2010.

In addition, other positive items contributing to the increase in third quarter 2010 were higher plant availability at Bruce A, a higher contribution from the US power, and lower net interest expense from increased capitalization of interest related to the Company's large capital growth program. These increases were however partially offset by lower power prices realized at Bruce B and Western Power. Despite these short term challenges, TransCanada's low cost base load generation is well positioned to benefit as power prices recover.

In addition, as noted, our CAN$21 billion capital program is expected to generate significant sustainable earnings in cash flow as projects are completed and assets commence operations.

I will now briefly review the business segment results at the EBITDA level. The pipeline's business generated comparable EBITDA of CAN$714 million in the third quarter compared to CAN$730 million in the same period last year . The higher revenues earned by the Alberta System associated with a higher equity return from its settlement with stakeholders was more than offset by a reduced revenue requirement for both the Alberta System and the Canadian main line. The reduction isrelated to certain regulated flow through items that do not affect net income.

And as I mentioned last quarter, although the first phase of Keystone is now in commercial service, EBITDA will be capitalized until the project is operating at its phase one design capacity of 430,000 barrels per day. This is expected to occur in late fourth quarter.

Energy generated comparable EBITDA of CAN$311 million in the third quarter compared to CAN$292 million for the same period last year. The net increase was due to a combination of factors, higher realized prices from sales volumes along with increased capacity revenues in US power, as well as increased generation volumes in lower operating costs at Bruce A, partially offset by lower realized prices at Bruce B and Western Power and reduced revenues from natural gas storage.

Halton Hills had a modest impact on third quarter EBITDA, as it went into service on September 1. The impact of the weaker US dollar on both USpipelines in energy EBITDA on a consolidated basis was partially offset by the positive impact on US dollar denominated interest expense.

Now, turning to the income statement items below EBIT on slide 25. Interest expense in the third quarter was CAN$159 million compared to CAN$216 million last year. This CAN$57 million decrease was primarily due to an increase in capitalized interest related to our capital growth program and a reduction in translated US dollar denominated interest expense resulting from a weaker US dollar. This was partially off set by incremental interest expense from US$1.25 billion of new debt issued in early June 2010.

In third quarter, CAN$160 million of interest was capitalized to assets under construction compared to CAN$113 million in the same quarter in 2009. Interest income and other of CAN$27 million in the third quarter of 2010 was CAN$16 million lower than the same period last year. The decrease results from higher gains realized in 2009 related to the impact of a weakening US dollar on the translation of US dollar denominated working capital balances.

Income taxes were CAN$120 million in third quarter 2010 or CAN$13 million higher than the same quarter last year, primarily due to an increase in pretax earnings. Preferred share dividends totaling CAN$14 million in third quarter 2010 reflect the cost of issuing CAN$350 million of cumulative redeemable first preferred shares in each of March and June of this year and CAN$550 million in late September of last year.

Moving on to cash flow and capital expenditures on slide 26. Cash generation remains resilient. Funds generated from operations increased by CAN$89 million to CAN$861 million in third quarter 2010 compared to CAN$772 million in the same period in 2009. The increase was mainly due to higher earnings and the income tax benefit generated from bonus depreciation for US tax purposes on Keystone which was placed into service on June 30. The Company is on track to generate funds from operations well in excess of CAN$3 billion for 2010.

Capital expenditures were CAN$1.3 billion in the third quarter. Principally related to the construction of Keystone, the Coolidge power plant, Guadalajara and Bison natural gas pipelines and the Bruce A restart. So far this year we have spent over CAN$3.5 billion to further advance our CAN$21 billion capital program, bring the total amount invested to CAN$13 billion.

Now, looking at slide 27, our liquidity and access to capital remains strong. At the end of the third quarter, our consolidated balance sheet consisted of 42% common equity, 4% preferred shares, 3% junior subordinated notes and 51% debt net of cash.

In addition, as of September 30, we had CAN$1.1 billion dollars of cash on hand, along with CAN$4 billion of available and undrawn revolving bank lines.

Our two commercial paper programs remaining well supported by the market, and continue to provide a flexible and attractive source of short term funds.

In September 2010, TransCanada issued US$1 billion of ten year senior notes at a coupon rate of 3.8%. This was the lowest ten year yield ever achieved by the Company in the second lowest coupon in the portfolio. TransCanada has now raised approximately CAN$3 billion of term debt and preferred share capital year to date and has effectively secured all of its funding requirements for 2010.

In addition, our dividend reinvestment program is running at 38% participation right now, generating the equivalent of about CAN$100 million of equity on a quarterly basis.

Finally, just a quick comment on international financial reporting standards or IFRS. In light of the on going uncertainty around rate regulated accounting under IFRS, TransCanada will take advantage of a one year deferral permitted by Canadian regulatory bodies and continue preparing its consolidated financial statements in 2011 in accordance with existing Canadian GAAP to order to continue using rate regulated accounting. We will actively monitor developments with respect to rate regulated accounting and other standards under IFRS, while at the same time, assess the Company's option and position it to adopt US GAAP as an alternative for 2012 onward.

In summary we had a solid third quarter. We have now invested CAN$13 billion into our unprecedented CAN$21 billion capital program and over CAN$8 billion of these projects have begun or are about to begin contributing to earnings and cash flow. And we are well positioned to finance the remainder of our capital program through 2011 and 2012.

That's the end of my prepared remarks, I'll now turn the call back to David for the Q&A.

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

(Operator Instructions). The first part of the question and answer session will be for analysts, so the first question is from Carl Kirst from BMO Capital. Please go ahead.

Thank you. Good morning everybody. The first question, I just want to make sure I'm understanding on Bruce. I understand we've got the CAN$400 million uplift here. With respect to timing, and when we're going to see revenues, presumably that's going to be matched with when they come into commercial operation, and I'm not sure if that is a delay from prior or not, but the way I was going to wrap it up was earlier, Russ, I think you were talking about new projects adding in an incremental CAN$1 billion of EBITDA into 2011. Are you still tracking to that or how should we be thinking about that now?

I think that number still accurate. The major components of that, obviously the key major component is the Keystone Cushing extension. But then the other ones that I mentioned in my remarks, obviously Halton Hills, Bison, Guadalajara, and our tie-in of the Groundbirch projects all sort of add you up to that number and they come on in various stages. So those would be sort of run rate number, not necessarily CAN$1 billion of EBITDA for the calendar year, but on a run rate basis that's the kind of number they add up to.

Okay. Appreciate the clarification. And with respect to the Keystone Excel now that we might have approval perhaps being delayed into the second quarter, understanding that it's a bit of still uncertainty, but hypothetically under that perhaps June 30 approval, what would that have an impact on as far as the in service date of Excel. Should we be moving that out to mid 2013?

Carl, it's Alex. Even with that date we're talking about mid next year for the presidential permit, we have planned for and are still online for a Q1 2013 in service.

Great, thank you.

Yes.

Thank you. The next question is from Ted Durbin from Goldman Sachs. Please go ahead.

Yes, if you could just talk a little bit more about your negotiations on the main line tariffs. What are the key points of negotiation you're looking at?We're rapidly approaching the end of the year here, are you looking into 2011 at all when you're in the negotiations? Maybe get a sense of the range of the outcomes we should expect on those.

As I have said before, our desire is to lower and stabilize tolls. The primary route to getting there is througha reduction in our collection of return of capital, if you will. Which is depreciation. The way that we get there is -- well, we do believe there's an increased supply available for our pipeline over the longer term. Reserve estimates in western Canada have gone from some 100 TCF of recoverable resource to about 300 TCF of recoverable resource. Based on that, we believe that the pipeline has a longer life and through sort of shifting costs around in the system, to those portions that have longer life, we're able to reduce our depreciation and then with some rates and services changes we would hope that those would reduce total substantially between the east and the west. Those are sort of the major components. In terms of timing, what we said on timing is that we would have an agreement by the end of the year or we'd be filing something similar to what I just outlined.

Okay. That's helpful. Thanks. And then if I could ask a little bit bigger-picture question. We've got power prices are obviously quite depressed. Maybe just talk about where you feel we are in the cycle for that business. Does it make you feel like there might be some acquisition opportunities out there given the fact that we may be bottom in the cycle. Maybe just talk a little bit about the power business.

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

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

Okay. I appreciate it. Thank you.

Thanks, Ted.

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

Thank you. Good morning. I have a quick question on Bruce Power. In the past you have provided sensitivities to cost -- changes in capital cost estimates which have been very helpful. Can you provide us with perhapssome sort of sensitivity on projected returns to delays of in service dates for the restart?

Yes, I don't have those right in front of me. I would say right now, Linda, we're looking at an IRR with the present dates we have probably in the range of nine -- slightly higher, but right around nine. And I'll have to -- I don't have the detail right in front of me on a delay, but I don't imagine it would be too sensitive. We're at the point now where we would expect -- we're almost completely through the construction, we will be through construction sort of towards the end of Q1 so any delays that we would expect would probably be in the range of a month or two.

Great. Thank you. And just a slight shift in focus on your power business. Can you perhaps describe your Oakville contract, whether or not there's any clear language around cancellation and would it be similar to the agreement at Becancour, or would it be more of a one-time payment or would it be perhaps be an alternative investment opportunity somewhere else within Ontario or is it unclear based on how the contract is written?

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

Greet, thank you.

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

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

Hi, Juan, it's Alex. As I think you might have heard, we have been operating base Keystone under a pressure reduction on the original line one in Canada by the NEB. That was just based -- they wanted us to do some further investigation and work on the integrity of that line. All of that work has been done. We have run the in line tools, we have done all of the analysis. That information is now with the NEB and we would expect to have that de-rate lifted some time as we get towards the end of this year. Once -- and that is really -- we have delayed the recognition of income from and revenue from this project, just based on when we get to the full design capacity. So as I said, we expect to do that towards the end of this year.

Okay. Thank you. And shifting gears a bit, Russ, you commented that your business environment will be challenged in the short term by depressed power pricing and natural gas pricing. Can you elaborate a little bit on that?

I think that -- I'm trying to elaborate on it. In those places where we have exposure to market prices, from a power side, those revenues will continue to be depressed until we see a turn around in the marketplace. It's not our attempt to sort of forward lock in these prices at the current time. We think that we're at the bottom of the cycle. And then secondly, on lower gas prices, we have seen that impact. Western Canadian drilling on the conventional side. And we have a time frame between when that gas has declined and when new shale gas comes online. So in terms of turn around on that front,we'd expect a change in through puts prior -- irrespective of a change in gas pricing environment. But if gas prices do sort of more normalize, then I think that we would see an increase in conventional drilling activity in western Canada which would augment those new volumes that I talked about in northeast British Columbia.

Okay. Thanks. So this wasn't a shift in your outlook then?

No, it's just recognizing that this is -- this has been a prolonged recession. And it could last a bit longer.

Okay. Thank you.

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

Thanks, guys. Maybe this for Alex, but follows on what Russ was just saying on hedging and in particular your strategy for Alberta. I'm just wondering whether you would continue to put any hedges on I guess at these forward prices or whether you just kind of leave that open now and ride the ups and downs?

Yes, that's kind of exactly where our view is. I mean, we're hedging forward sort of a month or two or a quarter if we see what we would consider good short term value. But right now, I mean there's almost no -- I would expect there's almost no downside left in Alberta Power prices and the skew to the upside is pretty significant. So you're dead on with our strategy right now.

I think our strategy, Matthew, has always been to maintain that portion of our portfolio that's exposed to market prices at a fairly minimal level. That gives us the strength at the bottom of the cycle not to have to hedge. We have a very stable base business, and so we can -- we're not forced into selling at prices that we think are not as good as we would otherwise be able to achieve by waiting for a period of time here.

That's a good comment. If you look at our overall portfolio, because of the heavy weighting of power purchase agreements even going into 2011 I think we're -- if you value those we're about 75% to 80% forward sold.

Okay, thanks, and maybe if I could just follow up with one question on the pipeline side of the business. We've got Bison coming in soon which looks like a good project. Also, other take away capacity out of that basin in the form of Ruby. Have you got any preliminary views on how that can affect your other pipelines, in particular I guess GTN and maybe the main line?

I think that on the GTN one, maybe I'll pass that over to Greg who is on the other end of the line here.

Yes. With respect to those projects, we'll see Bison coming on at 400 million a day, we would expect to see some production then from western Canada on moving to the main line that's been moving this year on northern border. And I think that's in our modeling in the range of about 250 million a day. And then GTN, I guess Ruby coming on kind of midyear we would expect to have some impact as well probably in that same range. Maybe higher.

The key I think, Matthew, on GTN is that we have most of out revenues on GTN are derived from long term contracts that run through to 2023. And even if the volume movement on GTN is decreased as a result of Ruby coming online our revenues won't be impacted to any material degree. And that sort of as we sort of think longer term having two sources of supply moving in our GTN pipeline is probably a positive going forward. Many pipeline that has multiple sources of supply and multiple markets provides greater optionality and greater opportunity to prosper in the future.

Okay, great, thanks guys. Those are my questions.

Thanks, Matthew.

Thank you. Your next question is from Pierre Lacroix from Desjardins Securities. Please go ahead.

Thank you. Good morning. Just coming back on the Western Power, you mentioned that you have a substantial portion of your portfolio that is hedged going forward, but if you look at 2010 versus what it will be in 2011 given the average price that you are getting under those hedges, do you see the 2010 year to be the bottom for the Western Power side?

Yes, I think 2010 will be amore challenging year than -- sorry, 2010 is tough. 2011 is going to be tough. We would expect to see some recovery in 2012.

Okay. Good, thank you for that. And looking at the US power side, CAN$77 million of capacity revenue, could you give some kind of a breakdown between Ravenswood and your other operations that you had on this decline?

Sorry, I missed the last part of that question.

Could you give the breakdown of Ravenswood and that capacity revenue versus other operations?

Oh, sort of New England. The -- I'm trying to think of it off the top of my head, but I would say probably at least 75% of that capacity split would be Ravenswood and I think one of the things that I think is important to keep in mind is that the capacity calculations in New York are based -- one of the key components of the capacity calculation is your unit claim capacity. And our capacity at Ravenswood has been depressed for 2009 and 2010 as a result of that extended unit 03 outage that we had shortly after we acquired the plant. In 2011 we no longer have the rolling impact of that, so we'll see a significant increase in capacity payments coming out of Ravenswood in 2011.

And talking about capacity there, in terms of the pricing situation are you heading toward the AN$10 to CAN$15 level that you were previously guiding on?

Yes, we're right -- the one thing we're in the middle of -- another big -- there's several factors that factor into the value of capacity. We are right now in the middle of a regulatory process to settle on one of the features of the capacity value which is called the cost of new entrant or CONE. That is a regulatory process we'rein the middle of that and we expect to be done probably in Q1 of 2011. But we're probably looking, in the winter season, we're probably looking at capacity values in that sort of CAN$12 to CAN$15 kilowatt month. Maybe a little bit towards the lower end of that range just because of the modest demand drop we have seen. But we're in that range that we talked about earlier.

That's great. Thank you very much, Alex.

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

Good morning. Just coming back to the main line toll negotiations. Based on kind of where you are in the negotiations, do you think that what -- either you're going to come to an agreement on or hopefully I guess that --that it's going to be something smaller with the tweaks, and I know Russ you mentioned something under depreciation, or should we be expecting something more radical coming out of those negotiations with respect to the tolling methodology?

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

We're currently in discussions with all the stakeholders, and I would say, I think we're making some reasonable progress here. We would hope to be in the position where we could file a settlement towards the end of the year which would deal with 2011 tolls and look a little bit longer term. One way or another, we will be filing, as Russ said, by the end of 2011. With regard to the -- your question , there are a whole number of things that we're considering and we're working with our stakeholders on a confidential basis on and I can't really disclose the nature of those discussions quite yet.

Something kind of much larger, maybe even a departure from the regulatory framework that we have seen that is still on the table? Is that fair?

No, that's not fair. We're under the same regulatory construct we have been under all along, and we would expect that we will continue to work within that framework.

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

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

I believe if I remember correctly, a 100 basis point change in our financing cost, which I think was pegged at about 6.5%, made a 0.3% difference in IRR. So I think that's sort of a sensitivity that we gave, I think it works both up and down.

Okay. And has anything else changed within the project that we can't just use the old numbers and make some adjustments?

No, I think at the time we announced the projects, we had given an IRR range of around 7% to 9% and I think 7% at the bottom end is a good number for just sort of base Keystone with the contracts. If we get our expected spot volumes growing over the years, that number probably looks like 8% and then if we're able to go to the total design -- the volumes of the total design capacity of 1.5 million with incremental pumping we're probably looking at 9%. And then any of these other assorted projects like Bakken, the Cushing market link, those would be on top of that.

That's great. Thank you very much.

Okay.

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

Thank you. Good morning. Do you have a perspective, just post the election in the US, on what that really means from an infrastructure standpoint to your business as far as the future development of it goes?

I think, Andrew, that would be very hard to give you any sort of insight as to what the election yesterday will have on the development of infrastructure. Obviously, the marketplace determines the need for infrastructure. And right now that marketplace is depressed. And so the need for infrastructure isn't as great as it has been say over the last five to ten years. But as the economy recovers we'd expect that to pick up. I'm not sure that politics at the end of the day actually drive the need for infrastructure. It's really the marketplace that drives the need for infrastructure.

But would you anticipate some of the changes that happened yesterday from a mix in the House and the Senate making things maybe a little bit easier from an approval process, I mean in particular if we look at things like, say, Keystone?

Again, I think Keystone stands on its own merits. It is a good project. The market as I said, the market will drive that project, the market needs crude oil. They need that 10 million barrels a day of imported crude oil. We believe that the safest and most reliable place to get it is Canada. So it's a fundamental need even with a depressed economy. They're still needing 10 million barrels a day of imported oil and Canada is a great source of supply. So that along with the economic stimulus that comes with the project, CAN$7 billion project and some 15,000 direct jobs are very much needed in this economy. So I think again the marketplace will drive those decisions at the end of the day.

And then somewhat related, and I know this builds upon a previous question in the call, as it relates to Oakville, what effect do you believe this will have, the Oakville decision, from the government on other power plant developers within the province? Because if we look over the last 10 to 15 years of Ontario politics in power plant development, it has been a challenging one at times. We can go back to market opening and then market closing among other things. So I'm just interested in your perspective. Either Russ or Alex on what impact does this have, not just on TransCanada, which I think you have been clear about, but on broadly power plant developers within the province.

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

That's helpful. Thank you.

Thanks, Andrew.

Thank you. The next question is from Pedro Panarites from CIBC. Please go ahead.

Thank you, and good morning. Just back to Ravenswood for a second. Are you able to quantify the incremental EBITDA from Ravenswood this quarter year over year? And also, on the capacity you'll be able to offer into the market next year, again, could you quantify the proportional increase in capacity?

We don't typically break out that information on an asset by asset basis. But I'm trying to think of the exact number, but that sort of range that I gave you of kind of winter capacity prices kind of towards a low end of that CAN$12 to CAN$15 range, I think we're looking at some -- I'm sorry, summer capacity in CAN$12 to CAN$15, the lower end, winter capacity in the sort of probably around CAN$4 to CAN$5 per kilowatt month. And we are now getting credit under that capacity calculation in 2011 for the full output of the plant and I think when you run that through the capacity calculator that the regulator has, that looks like somewhere in the range of 2,200, 2,250 megawatts.

Okay. Just one more question. How is demand holding up in that market and also do you see anything on the supply side that might impact capacity rates going forward?

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

And on the supply-side?

There is one project coming on. II believe it's the Astoria plant. But there's one combined cycle project coming on that we had always had in our calculation. I think that's coming in some time in later in 2011. I think it's around a 500 megawatt project, but that's been in our calculation. We tend to be fairly skeptical about these various cable projects and A, their feasibility, and even if they're feasible, we tend to be a little skeptical about the challenges of permitting those types of projects.

That's great. Thank you.

Okay.

Thank you. The next question is from Faisal Khan from CitiGroup. Please go ahead.

Good morning, it's Faisal from Citi. Thank you. I think you may have answered this in a previous question but I may have missed this, but can you elaborate a little bit on the -- when you expect the extensions from Cushing to Port Arthur and Easton to be in service given the time that it's taken to get the State Department approval for the expansion of the pipeline?

Hey Faisal, it's Alex. As I said earlier, we're still on a Q1, 2013, timeline for in service for all aspects of Keystone Excel. I think that there might be some opportunity to advance that phase of the Excel project, but I think right now sort of an early 2013 is probably a good time for everything.

On that one, Faisal, as we said before, it would be our intent to try to build that one first, as Alex said, depending on the start date, we'll have to sort of figure out how to configure our construction. But what we hope is to build that first. You can look at a map and it's about the same distance as say our Cushing extension. And we would hope that if we could do that one first we might be able to finish that in a sort of a 12 to 15 month time kind of time frame. So if we got startedmid 2011 we might be able to finish sort of mid 2012. That at least is certainly our intent would be to -- our customers are asking us to bring that capacity on as quickly as possible. But depending on start date and construction windows we'll have to assess that when we get there. But that's our intent is to build that piece first.

Is there any change in the regulatory process in order to do that or is that pretty straightforward?

No, once we get our approvals, then we can determine sort of the most appropriate construction schedule, if you will, for the whole project. As I said, being further south that does pose less challenges and constraints than the more northern parts of the project. So we're confident that we can probably still start that piece of the project first.

Fair enough. Then on the main line ofvolumes, kind of looking at the volumes year over year, how much of the volume decline year over year has been a function more of declines versus customers looking at other systems to move their gas on?

Greg, you might want to take that?

Yes. I think it's mixed. The producer just looks at a net back and determines where they're going to sell, whether it's at mid or move down stream. We certainly saw with Rex moving further east opportunities for improved net backs on border, both at Chicago and at Ventura, and so we saw increased volumes moving down border which we would have otherwise I think in the past have seen moving on the main line. But the conventional production is down and so that is also having an impact. I think we expect to see a similar impact in 2011. Maybe just slightly more and then a recovery as the Horn River and Montney volumes that Russ spoke about earlier start to come on and we have some impact from the Bison project also pushing volumes to the main line. So we are looking for things to pretty much bottom out similar to the discussion we had around power prices and start to ramp up as we move through 2012.

Okay. Is it fair to say that the volume uptick on GTN was a function of this shift in volumes from the main line to other systems?

Yes. I think that's fair to say that some of that was that shift there. There's also a demand pull at unusually low hydro volumes so there was a demand pull into that market as well as we're always impacted by weather constraints and weather challenges that tend to move volumes for short periods of time in different directions.

Great. Thanks for the time. I appreciate it.

My pleasure.

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

Yes, this has to do with big projects longer term, now that you're well-entrenched in your CAN$21 billion. Maybe just go through these maybe with quick sound bites. Obviously the Athabasca has now passed, I presume that was friction with Native groups or with your partner or was there some specific reason?

No, Sam, that was -- we had a great relationship with ATCO on that. We always characterized that as a very early stage development. And we always said that we weren't interested in pursuing it at all. If we weren't able to get the support of the Native groups, so when they made the decision that they really wanted to disengage, we really took the view that we weren't going to be interested in pushing water uphill so we'll put that on the back burner and see if they change their mind some time in the future.

So that was Native group generated?

Yes.

Okay. Big transmission, western US. I know you've got one project part way through the regulatory process. Has that moved any further at all or your other one going to California from the US Midwest?

Well, I think the one, the Zephyr project, which is the HVDC project from Wyoming down to the Las Vegas market, we did have a successful open season. The project was fully subscribed, but we've taken the view that the main market for this power is a California market. And the main driver for that are the RPS standards that have been enacted and that are continuing to be enacted . But there is still a lot of uncertainty as to how that power is going to be contracted, and particularly whether renewable sources outside of the state are going to be eligible and I think certainly everyone has the view that that is likely where it will end up, but at this point, there's still some uncertainty about that. So what we have done is we, with the agreement of our partners, we've all agreed to take a go-slow approach on that and work with utilities and stakeholders in California to see if this very attractive wind resource in Wyoming is going to be attractive and suitable for consumers' utilities in the state.

Thank you. Lastly, the pipeline, Frontier pipelines. You sound positively surprised with your response so far, yet, we have depressed economy and depressed gas prices. Can you speak to that a bit more in terms of your view of timing? If that's changed any and/or Mackenzie here and NEB is just going to rule on the project in a month as well?

I didn't hear the first part, you were asking about Alaska?

Yes. You seem positively surprised. I'm surprised as well in your response to date. Of course, the proof is in the pudding when you have long-term firm contracts and long-term firm demand. But you've got depressed gas prices. Much higher I guess, gas proof (inaudible) potential for the continent and a depressed US economy. So that kind of surprised me to even hear that. In terms of probable timing of Alaska proceeding, Russ, you still on the thought process for 2018 or 2019?

I would say 2018, 2019, 2020 is probably the time frame as sort of by the end of the decade. The driver, Sam, is really I think all of these large companies that are in Alaska, are sort of looking beyond sort of the current power price environment. They look to a North American marketplace that is about 80 BCF a day today, the marketplace that could be 90 or greater ten years out. And on the supply side, a decline rate in conventional supply anyway of somewhere of the neighborhood of 15% to 20% on annual basis. So replacement is about 15 billion cubic feet a day just to stay even so we have seen a proliferation of new shale gas come on. But as you can see sort of in places like the Barnett, for example, where it ramped on very quickly to 5 BCF a day but it appears to have leveled out, because the decline rates for that shale gas production is actually pretty steep in the first couple of years.

Once you reach sort of a production level, run rate production level in those basins, those level off as well. So our long term view, and I think that would be shared by those producers. And I can't speak for them, but given the bids into our project, which suggests they're thinking the same, that sort of as you get out towards the end of the decade, you're going to need shale gas, your going to need conventional gas and you're going to need northern frontier gas. I think the other sort of primary driver out of Alaska would be that gas is being produced today and I think they're producing some 78 billion cubic feet a day. It is being reinjected into the gas cap today. So there's no additional development costs, if you will, associated with that. So really the cost associated with bringing that gas to market are a processing plant and a gas pipeline.

We think that we can build that in the range of, pick a number between CAN$3 and CAN$4 an MCF, so if you can land that gas into a CAN$5 market you're getting a CAN$1 net back which makes it even economic in sort of the current market, but obviously lots of complexities in getting that project to market which will take us in that neighborhood of the next seven to ten years to get through the regulatory process, through the design of the complex project and actually build it the challenging environment.

So I think that's the driver behind Alaska. I don't think anybody is looking at the spot price today and making their long term decisions based on that. But I think that the companies that we're involved with are large sort of global gas players that see that opportunity sort of ten years out from now. And if you want to hit that you've got to start on that project today. Mackenzie, your question on Mackenzie, we have not yet received our permit. We're hopeful that the National Energy Board will come to a positive conclusion on the certificate of public convenience and necessity. Once they do, then all the parties that are stakeholders in that arena will have to sit down together and determine when that gas is economic to bring to market and when they would like to make those kind of investments, that the stakeholders at the table will obviously be the producer proponents that we have been dealing with for the last eight or nine years and actually probably longer than that, the Aboriginal groups and the Canadian government. And on that one, I'd say stay tuned to the conversations that should ensue post the issuance of a permit. I would hope that we'd see that sometime before the end of the year, maybe just into next year.

Thanks very much, Russ and Alex.

Thanks, Sam.

Thank you. (Operator Instructions.) The next question is Brian Horey from Aurelian Management. Please go ahead.

Thanks for taking my question. Based on pipeline flow data, it appears that the main line has really lost most of its export market to the northeast US. And it seems unlikely that that's going to come back given the growth of the Marcellus [and the compression of] basis in the East Coast markets that we have seen. I'm just curious if you're going to elaborate, how do you see overcoming that with respect to the main line. By shifting some of the cost around as you put it?

Greg, you want to take that?

Sure. Well, obviously we do have new volumes that are coming into the marketplace and allow eastern users to have some options as to where they get their gas. The Canaport LNG and the Marcellus coming on. And you heard Russ mention earlier that with regard to Marcellus, we are certainly negotiation precedent agreements, and we're looking at our system as to how we can move some of those volumes. Any time you have existing depreciated infrastructure, you can be very competitive in moving volumes to wherever they need to be moved. So we're fortunate in that we have a large eastern system which can take some of the new supply as well as the supply from western Canada. We're working hard with the producers and with the end use market to make sure that western Canada stays competitive.

And that's where Russ' discussions about depreciation and moving to areas where we do have higher flows and therefore can absorb those costs in a more effective way and keep our tolls competitive. So that's what we're working with all of our stakeholders is to make sure that western Canada stays a significant supply for the east. I think you're correct, we have seen some volume drop off --Niagara, Chippewa and Iroquois. The Niagara and Chippewa area would likely be a good source for these Marcellus volumes, and we would hope that we can continue to be competitive into the more distant markets through our settlement with our various stakeholders.

Okay, thank you.

Thank you.

Thank you. The next question is from Juan Plessis from Canaccord.

All right. Thank you. In regard to the US power side, we saw a significant increase in the purchases and resale of power. Is that a sign that the power markets in the US may be picking up?

You know, I think it probably would be more fair to say that particularly in Q3, I mean, we had some really hot weather in New York and New England and that created a lot of incremental opportunities. We were running our units more and we were also seeing opportunities to procure power in the market and fill other sales we had. So I think as said, I think generally we are seeing -- we saw little tiny tick back in demand overall in New York. I think we are seeing -- actually I think New England probably went up 1.5% or so. I would expect we'll move back to a growth mode over the next couple of years.

Okay. Thank you. And my last question, on the Alaska pipeline project, I notice that the state of Alaska started making some payments for reimbursement of costs as of July 31. Was there any impact on the Q3 earnings from that?

No. I think that there is -- the accounting is sort of based off expense and then reimbursements from the state follow on a lag basis. So I think if you actually look at the disclosure in Alaska, it will be different than our disclosure because their payments are a different timing than we're recognizing the cost from an expense perspective.

We understand through the contract which costs are reimbursable and so similarly as we need to accrue our expenses we can also accrue our recoveries on that. So it's not necessarily on a when the cash comes into our basis.

And again, Juan, in terms of expense expectation for next year --.

I think now that we're into the 90% threshold. I think it's relatively modest next year.

Okay great, thank you.

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

Good morning. I think we've gone through to Q4 given the time we have taken. But just quickly on Bruce, are you going to be exposed to spot power prices in 2012 until both units are up and running so that makes about three quarters of exposure to Ontario's spot power prices?

That is what the contract says, Steven. I think we're able to do a number of things to reduce that. I think most notably you have heard us talk about the life extension activities that we have done and continue to do to extend the life of the units three and four. So we are now looking at life cycles for units three and four probably getting out to around 2021. But as I've said there is this maintenance that is required. We call it west shift, but without going into great and gory detail it's just an extended outage that we have to do on the unit three reactor. What we've done, we were going to do that west shift in 2011. And it worked out well that we could shift it into 2012. So that is -- I think it's around 170 day outage. So an outage that we needed to take we have been able to move into 2012 which significantly ameliorates that challenge. So we do have much lower exposure to that. And also, I think that discussions are on going with the OPA and we'll see if we can't do something in that regard.

Okay. Thank you, Alex. My next question is on the Alberta System. There was some talk that the Alberta System might be expanded eastward to take in part of the Canadian main line. I guess -- am I right that the settlement you reached inSeptember means that that's unlikely to happen?

I think they're independent events but maybe Greg you want to talk about that?

Yes. When we put a proposal together, Stephen, in the spring, that was one of the matters that we were considering. And as we worked our way through the process, it's still there. Long term there are a lot of different things that we would be thinking about and working with our various stakeholders on in order to make sure we keep the competitiveness of the main line viable going forward. But we're in discussions. The Alberta settlement did not eliminate that as a potential solution, but I would say that the reaction from the upstream was quite negative with regard to that particular proposal so the settlement did allow if something were to happen that way that we'd continue to look at the upstream side. But that's just one -- was one potential option and we're now looking at a number of options with all stakeholders including the upstream cap group.

Thank you. Then those are my questions.

Thanks, Stephen.

Thank you. We'll now take questions from the media. (Operator instructions) . The first question is from Justin Amoah from Argus Media.

Hi. Thank you for taking my call. What were Keystone throughputs, what did they average in the third quarter and after -- and how quickly can you increase throughputs on that system after the MOP restriction is lifted?

It's Alex Pourbaix. I think on Keystone, we've been averaging about 120,000 to 130,000 barrels a day. And that will ramp up when we remove this

flow restriction on the Canadian portion then we'll move up to those numbers that you heard Russ discuss in Q1. Okay. So the incremental volumes that you're talking about, are those coming through contracted capacity or is it -- are you expecting a higher amount of spot shipments on the system?

It is overwhelmingly contracted capacity. In 2011, of the total capacity of 591,000 barrels a day, 90% of that would be contracted.

Okay. I just have one more if I could. Sunoco Logistics talked about a connection from Keystone Excel to their Nederland terminal. Is that going to be the only terminal that Excel connects to at the Gulf Coast or are you working on other connections as well?

We are right now -- we see an opportunity to advantage Keystone by increasing the connectivity at that end of the market. So we are continuing to look at connecting to other terminals. And that's something we'll probably progress our thinking over the next year or so.

Thank you.

Thank you. The next question is from John Spears from the Toronto Star. Please go ahead.

Hello. I'm just wondering if -- I understand most of the expense has been made now on the Bruce one and two refit, but what do you anticipate to be the total expense when it's finally done on the capital side? And I 'm just wondering given the delays and the cost overruns how attractive is this an asset for you to keep in the long run?

At the time we committed to go into the project, I mean, we had said that we would probably be looking at an internal rate of return of somewhere between, I think it was around 9% to 13%. And we said that -- and where we ended up on that would depend on the challenges of doing a lot of this first of a kind construction. It would be fair to say that we have experienced a number of those challenges, but at the end of the day we're still in that range that we're talking about that represents an attractive return to TransCanada shareholders. And I think equally importantlyit represents very competitively priced power for Ontario consumers. Even with the modest cost sharing that has taken place with the government through the OPA, this power still looks cheaper than any alternative source such as gas-fired power.

All right. Thanks very much. And the total cost for the one and two -- units one and two?

We have indicated CAN$4.8 billion total cost, our share CAN$2.4 billion.

Great. Thanks very much. Thank you.

Thank you.

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

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

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