TC Energy Corp (TRP) 2007 Q3 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2007 third quarter results conference call. I would now like to turn the meeting over to Mr. David Moneta, Vice President of Investor Relations and Communications. Please go ahead, Mr. Moneta.

Thanks very much. 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 2007 third quarter financial results and other developments concerning TransCanada.

With me today are Hal Kvisle, President and Chief Executive Officer; Greg Lohnes, Executive Vice President and Chief Financial Officer; Russ Girling, President of PipeLines; Alex Pourbaix, President of Energy; and our Vice President and Controller, Glenn Menuz.

Hal and Greg will begin today with some opening comments on our financial results and other developments pertaining to TransCanada. Please note that a slide presentation will accompany their remarks. A copy of the presentation is available on our website at transcanada.com and can be found in the Investor section under the heading Conference Calls and Presentations.

Following Hal 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, 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 detailed questions relating to some of our smaller operations or your detailed financial models, [Miles] and I would be pleased to discuss them with you following the call.

Before Hal begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian Securities Regulators and with the U.S. Securities Exchange Commission.

Finally, I'd also like to point out that during this presentation we will refer to measures such as comparable earnings 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 not likely to be comparable to similar measures presented by other entities. These measures have been used to provide interested parties and additional information on the Company's operating performance, liquidity, and its ability to generate funds to finance its operations.

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

Thank you, David. Good morning, everyone. Thank you all for joining us today. I will take a few minutes to talk about recent developments in our business, and I'll then turn the call over to our Chief Financial Officer, Greg Lohnes, who will review our financial results in more detail.

TransCanada's strong financial performance during the third quarter is a result of solid contributions from our long life legacy assets and growing cash flows and net income from newly acquired and developed assets such as the ANR pipeline system and the Bécancour power plant in Quebec. We continue to grow our pipelines and energy businesses in a disciplined way with an unwavering commitment to large-scale, long life infrastructure of the highest physical and financial quality. Through development of assets such as Bruce Nuclear and the Keystone pipeline system, we expect to generate strong financial results for our shareholders over the longer-term.

For the third quarter of 2007, TransCanada Corporation's net income from continuing operations was C$324 million or C$0.60 per share compared to C$293 million or C$0.60 per share in the third quarter of 2006. Comparable earnings were C$309 million or C$0.57 per share compared to C$243 million or C$0.50 per share for the same period in '06; an increase of approximately 14% on a per-share basis. Funds generated from operations in third quarter 2007 were 6% higher at C$702 million compared to C$662 million for the same period in 2006.

TransCanada's Board of Directors declared a quarterly dividend of C$0.34 per share for the quarter ended December 31, 2007 on the outstanding common shares. Shareholders that reinvest their dividends in additional common shares for the Company through our dividend reinvestment and share purchase plan will continue to receive common shares from treasury at a 2% discount to the average market price. You will hear more about our financials from Greg Lohnes.

First, I'd like to make a few comments on some of the sizable developments over the last few months in our pipeline and energy businesses.

First of all, on the pipeline side. During the third quarter, there was significant activity on the Keystone Oil Pipeline project. Today we announced that based on strong industry support, we have entered into contracts or conditionally awarded approximately US$3 billion for major materials and pipeline construction contracts. The Keystone team continues to secure land access agreements in preparation for the start of construction in the spring of 2008, about six months from now. Based on the increased size and scope of the project and the executed material and service contracts, the total capital cost of Keystone is expected to be approximately US$5.2 billion.

Also on the Keystone front, in September we received NEB approval to construct and operate the Canadian portion of the Keystone Oil Pipeline. We intend to file an application with the National Energy Board in November for additional pumping facilities required to expand the Canadian section from a nominal capacity of approximately 435,000 barrels per day to 590,000 barrels per day. In total, Keystone has secured firm long-term contracts for a total of 495,000 barrels per day with an average contract duration of 18 years. Further to that, that, producers and refiners continue to express interest in contracting for additional long-term capacity on the pipeline. Keystone intends to hold a buying open season for the remaining capacity by the end of this year.

Keystone will provide us with attractive returns and also give us another platform for growth. The support from committed shippers and ongoing expressions of interest for additional capacity clearly confirm the value of Keystone as a competitive way to link growing oil sands production to U.S. energy markets.

Finally, just a bit of background about the product Keystone will move. Keystone can move all types of crude oil. Keystone is designed to move the variety of crude oils determined by the industry and the same crude oil pipes that are moved today on all other crude oil export pipelines. The producing industry has determined and will continue to determine the specification of crude oil that can range from light crude to bitumen blended with synthetic crude or other types of crude oil. We move what our customers want and will continue to do that with the Keystone project.

Also in pipelines, the Alberta Energy and Utilities Board provided approval in July to initiate negotiations on a three year settlement for our Alberta system. Negotiations with stakeholders on the Alberta System revenue requirement began in September 2007 and are ongoing. Our goal is to reach a settlement for a term of up to three years, beginning January 1, 2008.

In the northwest United States, Palomar Gas Transmission, a joined initiative by TransCanada and Northwest Natural Gas Company, was announced. This is a proposal to build a natural gas pipeline connecting to TransCanada's existing GTM System over to Northwest Natural's distribution system that would serve growing markets in Oregon, the Pacific Northwest and the Western U.S.

In October 2007, TransCanada's North Baja pipeline received a certificate from the U.S. Federal Energy Regulatory Commission to expand and modify its existing pipeline system. The modification will facilitate the import of regasified LNG from Mexico into the California and Arizona markets.

Turning now to our energy business. The scope of the Bruce A restart and refurbishment program that set out to deliver an additional 1,500 megawatts was expanded. The expansion includes installing 480 new field channels in Unit 4, extending the operation life of Unit 4 from 2017 to 2036, about 750 megawatts. The expansion is estimated to cost an additional C$1 billion.

In total, the restart and refurbishment program is expected to cost C$5.25 billion, of which TransCanada's share is expected to be approximately C$2.63 billion. Bruce is a very cost competitive, long-term solution to help meet Ontario's power needs.

Also at Bruce, critical work continues on the Unit 1 and 2 restart. We recently completed replacement of all eight steam generators and replaced the steam drums on Unit 2. This is a very significant milestone for that project.

Construction is also progressing on a number of (technical difficulty) power plant projects in Eastern Canada. The Halton Hills Generating Station, a 683 megawatt natural gas-fired power plant located at Halton Hills, Ontario, and the 550 megawatt Portlands Energy Centre located near downtown Toronto in partnership with Ontario Power Generation. Construction continues on the 100 megawatt Anse aValleau wind farm in Quebec and remains on schedule for completion by December of this year.

Cartier Wind received [an] environmental approval from the Quebec government to build its proposed C$170 million Carleton wind farm. This is the third project to be developed after Hydro-Quebec's first wind energy call for tenders in 2004; all three of those projects developed by Cartier Wind in which TransCanada has a 62% ownership interest.

Also in the third quarter, TransCanada and the Saskatchewan government agreed to contribute up to C$26 million each for the engineering design phase of a proposed polygeneration project near Regina. The [belt plain] facility would have a very low greenhouse gas emission and use petroleum coke as feedstock for industrial uses and also generate 300 megawatts of electricity.

In closing, we're continuing to progress nicely on our portfolio pipeline and energy opportunities that will create significant future value over the longer-term for TransCanada shareholders.

I'll now turn the call over to Greg Lohnes, who will provide additional details on our financial results. Greg?

Thanks, Hal, and good morning, everyone. As Hal mentioned, earlier today we released our third quarter results. Net income from continuing operations or net earnings for the third quarter were C$324 million or C$0.60 per share compared to C$293 million or C$0.60 per share for the same period last year. The third quarter 2007 net earnings included positive income tax adjustments of C$15 million. Third quarter 2006 net earnings included a C$50 million favorable income tax adjustment as well. Excluding these items, comparable earnings were C$309 million or C$0.57 per share for the third quarter 2007 compared to [C$233 million] or C$0.50 per share for the same period last year; an increase of approximately 14%. The quarter-over-quarter increase was due to increased contributions from both the pipelines and energy businesses.

I will briefly review the third quarter results for each of our segments, beginning with pipelines.

The pipelines business generated comparable earnings of C$163 million during the third quarter; an increase of C$33 million over the same period in 2006. The increase was primarily due to the additional income earned from the acquisition of ANR, higher earnings from the Canadian Mainline, and a higher earnings contribution from other pipelines. TransCanada completed the acquisition of ANR on February 22 and included net earnings from that date. For the three and nine months ended September 30, 2007, ANR's net earnings were C$19 million and C$69 million respectively, which is generally in line with our expectations.

The Canadian Mainline's net earnings increased C$10 million for the third quarter when compared to the same period last year. The increase was primarily related to the higher common equity ratio. Certain performance-based incentive arrangements and operations, maintenance and administrative cost savings under the five year toll settlement effective January 1, 2007 to December 31, 2011. Partially offsetting these increased earnings were a lower rate of return on common equity and a lower average investment base, since Canada's proportionate share of net earnings from other pipelines in the third quarter 2007 increased by C$10 million when compared to the same period last year. The increase was primarily due to increased earnings from TC PipeLines LP and lower project development costs. The earnings contribution from TC PipeLines LP increased primarily due to TransCanada's increased partnership interest and TC PipeLines' acquisition of a 46.45% interest in Great Lakes gas transmission.

Project development costs decreased due to the timing of costs incurred relative to the same period last year and the capitalization of project costs related to the Keystone Pipeline extension in the third quarter 2007.

Net earnings also increased due to earnings from Tamazunchale, which commenced operations in December 2006. These increases were partially offset by decreased earnings from Portland in comparison to third quarter '06 due to a bankruptcy settlement received in '06.

Next, some comments on energy. The energy segment includes our power and unregulated natural gas storage operations as well as our business development initiatives in liquefied natural gas. Energy generated comparable earnings of C$156 million in the third quarter compared to C$123 million in the same period last year. The increase was primarily due to higher contributions from Western power operations, Eastern power operations and natural gas storage. These increases were partially offset by lower contributions from Bruce Power and higher general, administrative and support costs.

Bruce Power contributed C$64 million of pretax operating income in the third quarter compared to C$72 million last year. The C$8 million decrease was primarily due to higher post-employment benefit costs and other employee-related costs; higher costs associated with planned and unplanned outages; and lower positive purchase price amortizations related to the expiring of power sales agreements.

These impacts were partially offset by higher revenues resulting from higher realized prices. Bruce Power prices achieved during the third quarter 2007 were C$55 per megawatt, compared to C$51 per megawatt hour in the third quarter 2006. Looking forward, Bruce A Unit 3 is expected to have an outage lasting approximately 1.5 months which began in late third quarter. The overall plant availability percentage in 2007 is expected to be in the high 70s for the two Bruce A operating units and in the low 90s for the four Bruce B units.

The capital costs of Bruce A's revised four unit seven-year restart and refurbishment project is expected to total approximately C$5.25 billion, with TransCanada's share being approximately C$2.6 billion. As of September 30, Bruce A has incurred capital costs of C$1.8 billion on the restart and refurbishment project.

Turning to Western operations. Western operations operating income was C$120 million in the third quarter compared to C$84 million last year. The C$36 million increase was primarily due to increased margins from the Alberta power purchase arrangements resulting from a combination of higher overall realized power prices and lower PTA costs, partially offset by lower volumes. Higher prices were realized despite a 3% decrease in average spot market prices in Alberta due to short-term contracting at prices higher than the spot market.

In the third quarter 2007, approximately 25% of Western power sales volumes were sold into the spot market, consistent with the same period last year. To reduce our exposure to future spot market prices, Western power operations has fixed price sales contracts to sell approximately 2,600 gigawatt hours for the remainder of 2007, and 7,600 gigawatt hours for 2008.

Finally in power, Eastern operations operating income in the third quarter was C$52 million, an increase of C$12 million compared to the third quarter of last year. The increase was primarily due to incremental income earned in 2007 from the startup of the 550 megawatt Becancour cogeneration plant in September 2006, and payments received under the forward capacity market in New England, partially offset by decreased generation from the TC Hydro facilities, resulting from reduced water flows.

In the third quarter of 2007, approximately 98% of Eastern power sales volumes were sold under contract. To reduce our exposure to future spot market prices, Eastern operations has fixed price sales contracts to sell approximately 4,000 gigawatt hours for the remainder of 2007, and 12,400 gigawatt hours for 2008, although certain contracted volumes are dependent on customer usage levels.

Finally, in the energy segment, Metro gas storage operating income of C$39 million in the third quarter increased C$15 million compared to the same period last year. The increase was primarily due to incremental income earned in 2007 from the startup of the Edson facility in December, 2006.

Turning to corporate. Net earnings from corporate in the third quarter 2007 were C$5 million compared to C$40 million in the same period last year. Excluding favorable income tax adjustments in the quarter, corporate's comparable expenses were C$10 million in each of the third quarters of 2007 and 2006. Higher financial charges, primarily as a result of financing ANR and Great Lakes acquisitions were offset by gains on derivatives used to manage the Company's exposure to foreign exchange rate fluctuations and the impact of positive tax rate differentials. We have natural hedges in place for our U.S. dollar asset and income positions primarily through using U.S. debt to finance our non-Canadian operations. In addition, we actively manage the remaining currency exposure using financial strategies and products within established policy limits. The combination of these long standing programs reduces our exposure to changes in exchange rates.

Turning to the cash flow statement. Funds generated from operations were C$702 million in the third quarter; an increase of C$40 million or 6% when compared to the same period in 2006. This increase was mainly due to an increase in cash generated through earnings. Capital expenditures in the third quarter were approximately C$364 million and related primarily to the ongoing development of greenfield projects such as the Bruce A restart, Portlands Energy Centre, Halton Hills, and Cartier Wind, as well as growth and maintenance capital associated with the Canadian main line and the Alberta System.

Finally, our financial position remains strong. At the end of September, our balance sheet consisted of 55% debt which included our proportionate share of joint venture debt; 4% Junior Subordinated Notes; 1% preferred shares; and 40% common equity. On July 5, 2007, TransCanada redeemed all of the outstanding US$460 million, 8.25% preferred securities due [2047]. The redemption of these preferred securities was exercised in conjunction with the National Energy Board approved five year settlement for the Canadian Mainline. TransCanada and its subsidiaries have raised significant capital in 2007, in part to fund the acquisition of ANR and the remaining portion of Great Lakes. Of this, a considerable amount has been in the form of equity and equity-like instruments including the C$1.725 billion raised in common shares issued in a public offering.

In the second and third quarters 2007, TransCanada issued common shares from treasury under its dividend reinvestment and share purchase plan totaling C$104 million. In April of this year, we issued US$1 billion of Junior Subordinated Notes. This hybrid security currently receives 50% equity credit from S&P and Moody's and 55% equity credit from DBRS. Also, TC PipeLines LP raised US$612 million in equity, of which 50% was acquired by TransCanada and 50% by third parties.

TransCanada will continue to manage the balance sheet in a prudent manner consistent with maintaining our A credit rating. A strong balance sheet and our significant discretionary cash flow will continue to provide us with the financial flexibility to make future investments in our core businesses.

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

Thanks, Greg. Just a reminder, before I turn the call back over to the conference coordinator, we'll take questions from the financial community first. And once we've completed that, we'll then turn it over to the media. Again, I ask that you limit yourself to two questions. If you have further questions, please re-enter the queue.

With that, I'll turn the call back over to the conference coordinator.

(OPERATOR INSTRUCTIONS). Matthew Akman, CIBC World Markets.

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

Yes, Matthew. We will earn a full return. All of these issues have been agreed by contract with our shippers. The capital cost increase is partly due to an expanded system, moving more volume, more equipment and that sort of thing. It's also the result of capital cost increases in pipe and construction contractor rates.

We've moved actively to nail down those costs, securing long-term supplies of steel for the pipe itself and entering into contracts with contractors for specific construction of the different sections of that pipeline. But under the terms of our arrangement with the shippers, we had the opportunity to come back and firm up the cost estimates and, of course, to expand the project to move more crude oil. And we've done all of those things over the last six or eight months. And the announcement today is really what we think the project will cost when it comes in and the volumes that we think will move under the current phase.

We continue to work on subsequent phases of the project and we look to increase volumes further. The demand is there. Of course, everybody is considering carefully the impact of the current royalty changes. But early indications that we've had are that volumes we'll need to move to market, there's a number of very big projects that are underway today. And regardless of the final analysis of the royalty changes, there will not be an issue about volumes adequate to fill the current contracted capacity. And we believe further expansion capacity on Keystone.

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

Well, we continue to finalize the ownership arrangements with certain other parties that have the right to take a piece of it. We'll get to a final resolution on that I would think sometime in the next three to six months. And I think that the rate of return issues will become clear over that time as well.

Linda Ezergailis, TD Newcrest.

Perhaps just a follow-up on Matthew's Keystone questions. The cost increase, can you allocate that between the core system and then the expansion on the Keystone?

It's approximately about -- if I remember correctly, about C$1.5 billion for the Cushing Lake. And then the balance would be I guess about [C$3.7] for the Patoka/Wood River Lake.

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

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

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

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

Okay. And while we're on the subject of Bruce Power, perhaps you can let us know what the next major milestones would be for the Bruce restart and if you're still on time and on budget?

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

And so, and that's on time and on budget versus your original estimates?

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

Robert Kwan, RBC Capital Markets.

Just on the Western power side, the implied hedge price looks like it was in the mid-C$80 per megawatt hour range. That looks like it's a pickup from prior quarters. Is this something we can expect going forward just in terms of having seen the forward curve [in that]?

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

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

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

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

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

Maybe, Alex, if I put it a different way. Your earnings are up very significantly in the quarter; volumes are down. How would you characterize what was driving the big change then year-over-year, given [how] spot power prices were very similar. Was it just all the contracting strategy?

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

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

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

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

Sam Kanes, Scotia Capital.

Morning, Hal. I'm curious about the strategy with respect to your preliminary look at the Saskatchewan pet coke polygeneration unit watch for years, so it's power, study, study, study then kill a project, that sounds quite similar. I'm wondering if you could elaborate on whether this is A, the only project you're looking at this kind. Alberta obviously need something like this as well and all over the U.S. there is a variety of different projects. It is it the same project? How much has it changed? And what is the degree of interest from TransCanada's strategic point of view?

Well, I think, Sam, that the big picture would be that we see firstly declining gas production out of Western Canada. And we've seen increasing demand for natural gas at places like Fort McMurray. We look at the carbon dioxide agenda that's playing out and we recognize there has to be other forms of electricity generation that emit less CO2.

We look at IGCC integrated gasification combined cycle as a very interesting way. But we also recognize that the technology is in the early stages and most of these projects have been characterized by dramatic cost overruns. We visited gasification facilities in Dakota, IGCC plants in Florida. We've done a lot of work with General Electric and Bechtel on the Saskatchewan project. We continue to look at two or three different opportunities here in Alberta, both related to coal-fired power, perhaps using a gasification process, but also looking at petroleum coke in the Fort McMurray and Fort Saskatchewan areas. So we're looking at all of these things.

We think longer-term, we've got a very significant supply of pet coke and coal obviously here in the west, and there will be demand for natural gas, whether it's produced natural gas or synthetic natural gas.

On the Saskatchewan project in particular, we've tried to be very astute about the way we go forward. We've put several million dollars into the project so far. And we've said to the government of Saskatchewan, given their involvement and the CO2 agenda, we are not prepared to continue putting money into this thing without some complementary contribution from them. And so that's basically the structure that we've landed on. And we continue to work with some very sophisticated parties and GE and others on how you move the technology forward and exactly what it's going to take.

And I hear you, on science getting announced, a lot of hoopla, and then these projects getting canceled as people figure out it's just too difficult and they're at too early a stage in the technology cycle. So we're going to proceed cautiously. We're not aggressively trying to get this plant built in a hurry. We want to continue to move forward. But we're going to make sure that we spend the necessary money up front on technology and engineering and avoid the kind of multi-billion dollar mistakes that we've seen on some others.

And Alex would add to that.

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

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

Yes, we have always followed wind in Alberta very closely. And obviously, the cap that had been imposed really made it difficult to consider anything. Now that hard cap is gone but I think practically the issue that remains is still the issue of transmission access to these wind opportunities in Alberta.

So we continue to look at them. But I think Alberta continues to be challenged with a lack of transmission infrastructure and the costs associated with building transmission infrastructure to some of these isolated sites.

Bob Hastings, Canaccord Adams.

Just a clarification from Alex on the transmission side. One of the things that you've been looking at, I gather, is Northern Lights. Does that impact you at all and what are your plans on that these days?

We have said for years that probably the most significant problem plaguing the Alberta power market is its relative lack of interconnectedness with surrounding jurisdictions, particularly the Pac Northwest. We think that right now there is a unique opportunity with Northern Lights to really do a couple of things.

Number one, better connectivity between northern Alberta and southern Alberta, which is obviously a problem with the cancellation of the recent Altalink project. But I think more fundamentally as we move to a CO2-constrained world, we see a lot of opportunity to connect wind in southern Alberta, hydro in northern Alberta, cogen in northern Alberta to markets in the South.

So with the cancellation or the delay in the Altalink project, would you be able to be looking at ways to propose other projects around that?

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

And can I get a clarification on the Keystone project? You capitalized costs in there and I wondered if you could tell us sort of what those were and whether there was any catchup and the previous cost was maybe expensed in other quarters?

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

Karen Taylor, BMO Capital Markets.

I just have a couple of questions, really quickly. Maybe David, if you've got the tax rates for Bruce and in the gas storage segments, that's my first question.

Haven't got them here handy. My recollection was we've used approximately 32%, 33% on those two businesses. And I don't expect they would have changed.

And just a couple of other (inaudible) How much was the adjustment to the TC PipeLine LP contribution arising from the higher ownership. I'm not sure I understood what that comment meant in the release.

I think there were two things there. One, obviously we're up from last year just due to the LP owning a share of Great Lakes or a significant share of Great Lakes. We also own a more significant share of the Pipe LP. And in the laundry list of items, there was a small adjustment in there.

So are you talking less than C$1 million? Or non-material?

Non-material, a couple, C$3 million.

I think it was about C$3 million give or -- or so, Karen.

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

I guess if you say without hedges, we have our income offset by the interest on the debt. You say without hedges there's about C$100 million to C$130 million of exposure there, which would be about C$1.3 million [per cent] change in the exchange rate -- 1.3 net income. That's virtually all hedged with hedges that are rolling on a 12 month basis. So on a fourth quarter going forward basis. And therefore, for right now, we've pretty much totally covered that exposure.

As we go out looking forward of course we're rolling these hedges forward and we're really deferring the impact of the change in the exchange rate. Now that impact all shows up in corporate; the operating units are taking their hit as we go along when you look at the numbers from the operating units. And then the hedge benefit shows up on the corporate side.

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

Yes.

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

Okay. I will tackle the first question. We haven't capitalized any cost for [Cacoona]. And then Broadwater --

We are still waiting for our FERC environmental impact assessment which we expect word that right now we're expecting towards the end of the year. I don't think we have communicated any different date for the in-service.

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

It's Hal. It is interesting that we've got two challenges on almost all of these LNG projects; we and everybody else in the industry. First is getting regulatory approval to build a facility. And the second is securing the supply of LNG. Our two projects are quite different in that regard. At [Cacoona] we are working to bring down capital costs and to finalize LNG supply. And in the current supply/demand environment, that is a major task. And we are working hard on that.

At Broadwater, our partner of course is Shell and the Shell has more options for LNG supply I believe than any other company. So the issue at Broadwater, clearly there is a great market there. There's great market demand for that LNG coming in. And we've aligned ourselves with what I consider to be the best possible supplier. So the issue at Broadwater is really one of getting environmental approvals and other approvals from the state of New York. The major approval is the environmental impact statement from FERC. And that we hope to get within the next few months and then we go onto secure whatever approvals we need from the state.

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

Sorry. Has the state given us clearance on --?

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

No. They don't address that question until they get the finding from FERC.

Andrew Kuske, Credit Suisse.

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

Well, I'll provide a quick comment and let Alex add to it.

First of all, our PPAs do run off in that 2017/2020 timeframe. And we acknowledge that. And we also acknowledge your point about the long leadtimes. And not a week goes by that Alex or I don't speak to the Alberta government about the need to work now on plans to replace this generation when it reaches end of life.

And not only do our PPAs run out in that timeframe, but it's not too long after that, that quite a number of the coal units in Alberta start to reach the end of their useful life. And in fact, some of them will be coming off-line before 2017; not our units but some of the others in the overall Alberta coal fleet.

So we look at a number of different opportunities here in Alberta. Certainly coal gasification is one of them. We would be quite nervous as a Company about proceeding with a simple coal-fired generation facility and we think you have to look at other technologies that enable the capture of CO2 if you are going to be using coal as the generation.

We also are looking at -- we have obviously taken steps to develop our own gas-fired fleet. And that is a great way to generate electricity in Alberta other than we are not sure how expensive gas is going to be. And that's obviously something we worry about.

We've looked at a number of large-scale hydro projects. And I'd underscore a comment that Alex made earlier. That really for people to invest significant money in merchant generation in Alberta, we need better connectedness with major U.S. markets. You can't bring on 2,000 or 3,000 megawatts in a new project and have that output stranded in Alberta. During the early years of a new plant you've got to have a safety valve to release that output into the larger Western North American market. So that's where we think transmission is a big part of it.

We're aware that other people have looked at nuclear opportunities in Alberta. And with our partners at Bruce, we also look at those things. But obviously, that is a complex step. There is a lot of technical issues. The building of a nuclear plant is not a simple thing. And we are doing our homework on that before we decide whether or not we would want to engage in that kind of generation build here in Alberta.

So there's many opportunities but you're right, the planning horizon is long and we need to deal with this early on if we're going to keep the lights on in this province 10 years from now.

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

I think that's a fairly valid point. I guess I'd have a couple of responses to it. That from our perspective in the short term, I mean we have to be worried about things like our market concentration. We're already at about 20% of this market. But long-term, we absolutely consider one of our core competencies and competitive advantages our knowledge of and our position in the Alberta power market. So I think you can take it as a given that we are very active right now on assessing development opportunities and those range, as Hal said, from things as small as 100 megawatt wind farms up to 1,500 megawatt major hydro projects in northern Alberta. So, I don't foresee a situation over the next 10 or 15 years where we don't continue to maintain a very significant power generation position in Alberta.

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

I guess there's potentially that opportunity. At the time these PPAs were entered into, the terms were calculated for all intents and purposes to coincide with the end of life of the plants. Now I think realistically our experience with coal plants tends to be that they never go away, they just keep getting refurbished in one way or another.

So I do expect there's life in those plants longer than the PPA life. But the issue, I think the big issue in Alberta and the big issue in Canada is going to be the CO2 costs associated with continuing to run those plans. And as Hal mentioned, right now it really is -- there's a great deal of uncertainty as under the federal act, the plan is to what those costs of CO2 compliance are going to be.

I think our view is very much that right now there is no viable technology to capture CO2 off the back end of those existing and relatively late in life coal plants. So I think there is going to be challenges and life extending them if we continue under the present federal plan that we have right now. I think if there is some opportunity to do that, I mean we're obviously going to engage with the asset owners to see if there is an opportunity for us to continue with some form of entitlement under those plants.

Daniel Shteyn, Desjardins Securities.

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

On your second question, it's too early to speculate where we might land with that negotiation. That discussion has just started. Our target at the end of the day is likely a number that looks like 40% with an appropriate corresponding return on equity that would get us what we would call a fair return. And that fair return would probably be in the neighborhood of 7% on a all-in sort of return on capital basis. So you can sort of back calculate where we think the ROE needs to be.

And so that's the nature of discussions consistent with the (inaudible) that we have made in the regulatory forums and the (inaudible) that we made on main line. Now, obviously, we didn't achieve all of that on the main line in the settlement, and this settlement includes other factors like performance incentives, cost incentives and those kinds of things. But that's sort of what we'd be targeting for heading into a settlement.

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

Hey, Daniel, it's (inaudible) here. Just taking it sort of line by line, you're right that the 100% operating income is up this year, that our proportionate share is flat. What you're seeing there is just the difference of the ratio, or the proportion between Bruce A and Bruce B. As you know, we own roughly 31.6% of Bruce B and about 48% of Bruce A.

And as we mentioned in some of the narrative that Bruce did experience some planned and unplanned outages this quarter as well as costs and they were just a little higher on the A side and we own more of that. So, proportionately we'd didn't reap as much of that positive variance.

As far as the expiring of the sales contracts, where you're seeing that is in the line below that that's called adjustments. And these are just some of the historical or legacy contracts that we had acquired at the time of our original ownership and they've just rolled off. So we've handled those through our purchase price accounting, so it ends up just showing up in that adjustments line.

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

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

Robert Kwan, RBC Capital Markets.

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

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

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

Nothing in terms of concrete dates or open season. We continue after discussions with both refining community and the producing community. I would say that those discussions have been delayed as a result of the royalty discussion here in Alberta where the producers in Alberta have been focused on the impact that that's going to have on their future capital investment and their future needs for export capacity from the province.

So I would suspect once that (inaudible) and people understand what the impact on their investment profile is going to look like in timing, and then we'll be able to get back to sort of moving forward with Keystone XL discussions?.

Great. Thanks, Russ.

Shawn Burke, HSBC Securities.

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

It's Greg. I'll tackle those. Our balance sheet is in the strongest position it has never been in. When we go to the equity markets it's very rarely and it's for significant size as you saw us do in 2007. We are in a great spot right now. Moving forward, we've got lots of debt capacity. These projects come on over a period of years. And so the spend profile is spread out. We've got very strong cash flow. And as you have seen from the quarter, it is growing as we move forward. So we have got lots of capability on the debt side.

We've also have got our DRIP program operating. So as you saw, it was C$104 million for two quarters. So -- and we would expect that to stay about at that rate. So we are adding small amounts of equity at a very reasonable cost to the Company. And then we maintain our flexibility with our LT and other facilities and look at the opportunities we have around our entire asset portfolio as we always do when we prudently manage our portfolio.

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

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

It's Hal here. I'd just add to that, that if you go back to, say, the 1999/2000 period, we were generating something like US$700 million in cash from operations for the full year. And in this current quarter we generated something like US$700 million in one quarter. Cash flow generation has grown very significantly within TransCanada. And that has given us the ability to fund a much larger capital program. And to the extent that that larger capital program is directed at projects that bring subsequent increases in cash flow, we have a process that continues to strengthen the Company and allow us to pursue bigger projects.

So I would just point out don't overlook the internal cash flow and the growth in that when you think about how TransCanada can fund some of these significant projects.

Karen Taylor, BMO Capital Markets.

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

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

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

I'm not sure what you mean by timing. I would say that they're fairly constant through the year, Karen, if that's your question.

And then just lastly, I noticed that you filed an application on the Alberta System to recover a CO2 cost I think under Bill 2 -- or Bill 3, rather -- and in the amount of about C$3 million to C$4 million. Given that the federal government has carbon legislation on the table, does the current settlement agreement on the main line explicitly provide for carbon costs as a flowthrough? Or do we have to have a filing?

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

So you won't have to file then?

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

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

Bob Hastings, Canaccord Adams.

[Just this] topic. On the APG, you've founded a fair amount of money over to that. And I'm just wondering what circumstances would trigger you writing that down as opposed to capitalizing it?

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

I was just looking at triggering points where you might change your mind. I don't think you'd say it's economic at this point in time, would you?

Well, it depends on your outlook for gas prices. If you use today's gas price and the very highest cost estimates that have been generated for it, I think you'd have to question the economic viability. It's not clear that it would be uneconomic.

A lot of it also depends on production rates and how much other gas is available up there. But I think we look forward a little more optimistically because I don't think anybody would be more aware than us of the challenges of sustaining gas production in Alberta. We see roughly flat line production in Alberta and significant growth in demand, which sets the stage for a higher price in Alberta. We frankly see a similar scenario unfolding all the way across North America with flat production at best over time.

I see lately some people have come out with quite bullish forecasts of gas production growth in North America. I think those forecasts overlook the inexorable decline from our base producing sources in all parts of Canada and the U.S. So, our scenario would be flat production at best out of existing areas of North America setting the stage for higher prices and demand on both the LNG and northern GAAP sides. That would be the fundamental reason why we remain enthused by the project.

Certainly pricing has something to do with supply and demand over time, so I'd agree with that. Thank you.

We'll see where it goes. Thanks.

Daniel Shteyn, Desjardins Securities.

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

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

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

Yes. For this kind of project we would be looking for an unlevered aftertax return. I would argue at least somewhere at the 9% or north range. Not dissimilar from the kind of returns that we look for in our nuclear business. They're similar -- they're not dissimilar in the complexity of the projects.

We will now take questions from the media. (OPERATOR INSTRUCTIONS). John Harding, National Post.

On the cost increase for Keystone, I'm trying to find a reference point or understand how much they've gone up percentage-wise or again from what point?

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

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

Okay. And who is that, sorry?

That was Russ Girling speaking.

Okay. Can I ask one follow?

Sure.

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

We're looking at nuclear opportunities in many parts of North America, and Alberta is certainly one of them. We think Alberta is an interesting situation just because the long term supply/demand fundamentals are good in Alberta. There is certainly demand for power. We would not undertake something major like that unless Alberta was -- enjoyed much better interconnects with the bigger markets in other parts of North America. So you can't, we don't believe, drop several thousand megawatts of any kind of power, nuclear, river hydro, worldscale coal into a market like Alberta without seriously disrupting the market if you don't have the transmission connections to the bigger North America market.

But we look at nuclear power opportunities in all parts of the country. Our main focus today is at Bruce. And we've got an exceptionally competent nuclear development team at Bruce that has done a very big job of guiding the refurbishment of the Bruce A plant, which in many ways is similar to a complete new build. And we have confidence that that team would do a very good job of pursuing nuclear projects in Alberta if they make sense.

What we don't know is whether it would be competitive with exotic forms of coal generation. We don't think simple coal-fired generation makes sense in Alberta going forward for CO2 reasons, but there are other coal gasification and projects like that that might make sense, and that's what nuclear has to compete with.

So it's not a simple question. We're doing our detailed homework as always, and looking at that opportunity as well as many others in different parts of North America.

Ian McKinnon from Bloomberg.

I have a question for Russ Girling and it's regarding Keystone on the base cost like -- I checked some of our old stories and we talked about C$2 billion, C$2.1 billion. I'm wondering if that C$2.8 billion, C$2.9 billion figure that you're using includes the extension to Cushing?

That's correct. The original [estimate] for just the Patoka/Wood River leg was [both] C$2.1 billion in 2005 (inaudible).

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

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

Okay. And then can you clarify like if you're saying pipe and labor is going up, what are we talking about? One-third? [Of] 50%? Any sort of clarity on that?

I would say that our pipe costs are probably somewhere in the neighborhood of 50% to 60% higher than they were two years ago. And there's one other factor -- you'll notice that all of our estimates for this project are in U.S. dollars. And the most significant part of the capital cost is on the U.S. side. That's the bigger side -- half of the project.

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

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

We are and we have been for several years part of the project. We're involved in the project. We're not an outsider trying to negotiate to get in. We're in the project. And all I would say -- the partners in the project are examining every alternative to come up with a toll for the MacKenzie producers that makes it attractive for them. They've got billions of dollars that they need to spend to develop the gasfields up in the MacKenzie Delta. And sometimes as people talk about the cost of a pipeline it's overlooked that there's very significant expenditure to be made in the development of gas reserves and processing facilities and equipment up there. TransCanada is not involved in the development of gas reserves up there. So clearly the producers are in the lead on that.

I'd just say -- we're discussing a whole range of different things. TransCanada has always been willing to contribute as best we can. We have a lot of construction expertise in building pipelines. We have a lot of cold weather expertise. And we have a very good working relationship with the producers and with the APG. We're all working together to try to bring this project to fruition. And I think that's all I would say at this point.

(OPERATOR INSTRUCTIONS). Scott Haggett, Reuters.

I'm wondering if you can refresh my memory --

I'm sorry, Scott, I'm sorry, we can't hear you very well. Could you try that again?

Is that better? Sorry about that. I'm wondering if you can refresh my memory on the agreement with ConocoPhillips and what the status of that is on Keystone?

Conoco has the right to purchase a 50% equity interest in the Keystone Pipeline. They haven't exercised that option yet and we expect them to exercise it sometime probably before the first quarter of next year. Whether they exercise it or not, they're about to make a decision one way or the other. So perhaps sometime before the end of the first quarter next year.

And that will involve paying their share of costs up to that -- incurred and forward?

Exactly.

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

Well, obviously, it will proportionally increase the tolls so that the tolls will go up by exactly the amount that the capital went up. When we look at the competitiveness of the tolls relative to other options that the producers have to get to the Patoka/Wood River area and to Cushing, with the increased capital costs we're still landing at an all-in cost that's less than what we believe the competitive alternatives to be.

All alternatives are experiencing these very similar cost increases. We're all ordering steel from exactly the same manufactures and utilizing exactly the same contractors. So, across the board the costs have risen and tolls will go up.

And given that we have a significant portion of our pipeline -- it's about a 2,000 mile pipeline -- about 600 or 700 miles of that is across the prairies from Alberta to Winnipeg. That steel is already in the ground. We're converting one of our existing mainline gas pipes to crude oil. So we're not experiencing a cost increase of the same magnitude for that -- just about basically one-third of the project. So our costs escalations are less than other's costs escalations would be if you had to build sort of 100% from supply source to delivery source.

So, even with the cost increases we're still very, very competitive. And our customers agree with that and obviously are very supportive of the project.

There are no further questions registered at this time. I would now like to turn [it] back to Mr. Moneta.

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

Thank you. The conference has now ended. Please disconnect your lines at this time. That concludes our presentation. And have a nice day.