TC Energy Corp (TRP) 2008 Q2 法說會逐字稿

Good day ladies and gentlemen. Welcome to the TransCanada Corporation 2008 Second 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 and good afternoon, everyone. I'd like to take the opportunity to welcome you today. We're pleased to provide the investment community, the media and other interested parties with an opportunity to discuss our 2008 second quarter financial results and other general issues concerning TransCanada.

With me today are Hal Kvisle, President and Chief Executive Officer; Greg Lohnes, Executive Vice President and Chief Financial Officer; Russ Girling, President of Pipelines; Alex Pourbaix, President of Energy; and our Vice President and Controller, Glenn Menuz. Hal, Russ and Greg will begin today with some opening comments on our financial results and other general issues pertaining to TransCanada. Please note that a slide presentation will accompany their remarks, a copy of that presentation is available on our website at transcanada.com. You can find it in the Investor section under the heading Conference Calls and Presentations.

Following our 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 participant, we ask that you limit yourself to two questions. If you have any additional questions, please reenter the queue. Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations or your detailed financial models, Terry 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 US Securities and Exchange Commission.

Finally, I'd also like to point out that during this presentation, we will refer to measures such as comparable earnings, comparable earnings per share and funds generated from operations. These measures do not have any standardized meaning prescribed by generally accepted accounting principles, and are therefore considered to be non-GAAP measures. As a result, these measures are unlikely to be comparable to similar measures presented by other entities. These measures have been used to provide interested parties with additional information on the Company's operating performance, liquidity and its ability to generate funds to finance its operations.

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

Thank you, David. Good afternoon everyone and thank all for joining us this today. I'd like to take a few minutes to highlight our second quarter results and recent developments in our business, following that; Russ Girling, President of Pipelines, will provide more information on the significant developments recently announced on the Keystone crude oil system; our Chief Financial Officer, Greg Lohnes, will then review our second quarter results in more detail.

As many of you know, I have often referred to three key value creation themes at TransCanada. Our first theme, maximizing and sustaining the long-term cash flow and value of our growing asset base; secondly, completing greenfield projects on time and on budget; thirdly, creating a cultivating a high quality portfolio of future growth opportunities.

During the second quarter of 2008, I'm pleased to report we have made significant progress in each of these three strategic areas. The first value creation theme is about maximizing and sustaining both earnings and cash flow from what we consider to be an exceptional suite of blue chip assets. On that front, I'm pleased to report strong second quarter results.

For the second quarter of 2008, TransCanada's net income was CAD 324 million or CAD 0.58 per share, an increase of 21% on a per share basis compared to the same period of 2007. Comparable earnings for the second quarter of 2008 of CAD 316 million or CAD 0.57 per share, increased by approximately 27% on a per share basis compared to the second quarter of 2007.

Funds generated from operations for second quarter 2008 of CAD 676 million, increased by CAD 80 million or 13% compared to the same period of 2007.

TransCanada's Board of Directors today declared a quarterly dividend of CAD 0.36 per share for the quarter ended September 30, 2008 on the outstanding common shares. Shareholders that reinvest their dividends in additional common shares of the Company through our dividend reinvestment and share purchase plan, will continue to receive common shares of Treasury at a 2% discount to the average market price.

Moving on to our second theme, our second theme is about securing and executing on greenfield projects and selected acquisition opportunities in the short to medium term. Once again, we continued to make significant progress during the second quarter by advancing our Keystone Gulf Coast expansion project as well as the Coolidge and Kibby Power-generation projects.

Today, we are in the midst of executing on a CAD 17 billion capital program that is expected to deliver significant value for our shareholders over the next five years. The slide showcases our extensive list of secured pipeline and energy opportunities that will be completed over the 2008 to 2012 timeframe. These are real projects, most of which are underway today.

In addition to our active projects, we continue to expand and enhance our portfolio of large-scale energy infrastructure projects including oil and gas pipelines, power-generating facilities, and natural gas storage facilities.

I'd now like to expand on a few of the key initiatives.

Firstly Keystone; as you know, there were significant developments on Keystone during the second quarter, the largest of which was the announcement of our expansion to the Gulf Coast. Our decision to proceed with the Keystone expansion followed successful negotiations with perspective shippers who have agreed to make significant shipping commitments to Keystone during a binding open season which commenced in mid July.

Today, Keystone has secured total commitments of 830,000 barrels per day for an average term of 18 years. These binding contractual commitments represent approximately 75% of the commercial design of the expanded Keystone system.

When completed, Keystone will be capable of moving approximately 1.1 million barrels per day of Canadian crude oil to key markets in the US Midwest and to the US Gulf Coast, making Keystone one of the largest crude oil delivery systems in North America. Russ Girling, President of Pipelines, will talk more about the exciting developments on Keystone in a few minutes.

I'd like to now comment on our Rockies Gas Pipeline proposals. We continue to work on opportunities to move an increasing supply of natural gas from the US Rocky Mountains to growing markets through proposals like Sunstone, Pathfinder and Northern Border's proposed Bison project. Each of these projects would connect to our existing pipeline network and provide customers with access to diverse markets.

Turning now to other recent developments, in the north on the Alaska front, the Alaska House of Representatives voted in favor of granting TransCanada a license to build the Alaska Pipeline. While this is an important step, we still require a positive decision from the Alaskan Senate on our proposal in order to move forward. The Alaska Senate decision is anticipated by August 2nd. If approved, it would be an important step in advancing this major natural gas pipeline project which would connect stranded US natural gas reserves in Alaska to markets in both Alaska and the lower 48.

In another move to address customer needs, we recently held a non-binding open season to gauge interest for new natural gas transportation service, connecting the very promising Horn River and Montney/Groundbirch areas of Northeastern BC, to TransCanada's Alberta system. In those non-binding open seasons, TransCanada received requests for gas transmission service exceeding 1 bcf a day from each area by 2012. Based on these expressions of interest, we expect to complete a binding open season in the next several months.

We believe TransCanada is very well positioned to move new gas supply from these regions to premium North American markets. As highlighted on the map, our existing pipeline network can move this incremental supply to markets in California, the US Midwest, Eastern Canada and the Northeastern United States. And we can do that more cost -effectively than the competition.

In order to further position ourselves to serve customer needs, TransCanada filed an application with the NEB to establish federal jurisdiction over the Alberta system. This would enable the Alberta system to extend across provincial boundaries, providing integrated natural gas service to Alberta and British Columbia customers and eventually to northern gas producers.

Turning now to our Energy portfolio, we recently announced that the Salt River Project signed a 20-year power purchase agreement to secure 100% of the output from TransCanada's planned 575 megawatt Coolidge generating station in Coolidge, Arizona. Pending appropriate permits, construction is scheduled to begin in late 2009. The simple-cycle natural gas-fired peaking power facility is expected to be in service in May of 2011.

On the wind front, the 132 megawatt Kibby Wind Power project received unanimous final development plan approval from the state of Maine's Land Use Regulatory Commission. Pending all remaining approvals, construction is expected to begin in third quarter of this year and the project is expected to be fully commissioned in the year 2010.

The Portlands Energy Center in Toronto went into simple-cycle service on time and on budget. It is currently able to provide 340 megawatts of electricity to the Toronto market. It's anticipated that the Portlands Energy Center will be fully commissioned in second quarter 2009 and will be capable of providing 550 megawatts of power at that time.

And finally, an update on Ravenswood; the US Federal Energy Regulatory Commission has issued an order authorizing our acquisition of the 2,480 megawatt Ravenswood facility in New York City. This acquisition remains subject to New York Public Service Commission approval and is expected to close in the third quarter of 2008.

With that, I'd now like to turn the call over to Russ Girling, our President of Pipelines, who will provide you with more details on Keystone developments. Russ-?

Thanks Hal and good afternoon, everyone. As Hal mentioned, in mid July we were very pleased to announce that we had sufficient shipper commitments to move forward with a 500,000 barrels per day expansion of Keystone to the US Gulf Coast.

With that expansion, the commercial design of Keystone will increase from 590,000 barrels per day to approximately 1.1 million barrels per day. The US $7 billion expansion will run from Hardisty, Alberta to northern Nebraska and then south to the Gulf Coast, just east of Houston. The proposed routing shown as the yellow line on the map; this is not a modest expansion as you can see. In fact, it's larger than the initial phase. Targeted completion is in 2012 and the expansion will provide a direct bullet line connection to the largest and most complex crude oil refining center in North America, representing the largest untapped market for Western Canadian crude oil for Western Canadian producers.

Traditionally, US refiners have depended upon supply primarily from the US Gulf Coast, as well as Mexican and Venezuelan supplies. US refiners are looking to diversity their crude oil supplies and Keystone will provide the link to connect growing Alberta oil sands production with markets on the Gulf Coast.

Following successful negotiation with prospective shippers to the Gulf Coast, Keystone has now secured long-term commitments for approximately 830,000 barrels per day; representing about 75% of the commercial design of the total system. As evidenced by these commitments at an average term of 18 years, we have received strong support from producers and refiners. We expect support to continue to grow during our binding open season which runs through September 4th of this year.

In addition, construction began on the initial US $5.2 billion phase of the Keystone project, including facilities in Canada and in the United States; which will transport, as I said, 590,000 barrels of day of crude oil from Hardisty, Alberta to US Midwest markets. Deliveries to Wood River and Patoka, Illinois are expected to commence in late 2009 and deliveries to Cushing, Oklahoma will begin in late 2010.

The Keystone Pipeline will be constructed and operated as one integrated system. Full cycle returns for the entire US $12.2 billion estimated cost of the project are expected to provide a target unlevered after-tax IRR in the range of 7.5% to 9%.

The competitive advantages of the Keystone extension are extensive and provide potential shippers with a number of important and very unique offerings. First of all, we have a competitive toll resulting from Keystone's direct route, which is about 25% shorter than other routes through Chicago and on to the Gulf Coast. In addition, we also utilize a 480 kilometer section of the initial phase of the Keystone Pipeline from a place called Steele City to Cushing, Oklahoma.

Second, there is toll certainty with a fixed variable toll design that we put in place. There is no increase in the fixed portion for the term of the contract and the smaller variable portion is strictly on a flow-through on an actual cost basis.

Third, Keystone's physical advantages are also unique. Its direct route and single bullet line configuration result in short transit times of about 20 days and significantly reduced batch contamination and degradation. There is no breakout tankage and the volumes will be shipped in large batches or batch trains with a minimum size of about 100,000 barrels. This results in fewer and smaller interfaces between products, and therefore better product quality.

And last, subject to regulatory approvals, Keystone will provide firm transportation service using capacity that is reserved for and committed to term shippers for the priority transportation of their committed volumes.

Next I'd like to review with you our cost mitigation strategies for the procurement and construction of the full CAD 12 billion Keystone project. As one large integrated project, we were able to offer up to the construction marketplace a continuous build that will last four to five years, and similarly for steel we will keep mill space busy for about four to five years. These longer term arrangements are very attractive for these suppliers and at the same time helps in mitigating of cost of supply risks.

We've tried to lock down as much of our construction costs as possible at this stage in the project. On the initial phase of the Keystone project, approximately 60% or US $3 billion of the US $5.2 billion, are currently fixed and locked in. This includes about 80% of the line pipe and 95% of the valves and pump costs. All the required mill space has been secured for the pipe and Keystone construction cost risks-- cost risk sharing is in place between Keystone and its shippers, and on the initial system, any cost variances are shared on an average of about 50% to TransCanada and 50% to the shippers.

On the Keystone expansion, we have good visibility of costs based on our experience with the initial phase of Keystone. We have positioned ourselves well by leveraging off existing contracts and suppliers to obtain execution and cost synergies. We are well advanced in locking up pipe mill space and pricing for the higher cost items such as pipe, pumps and construction costs.

Having secured commitments from shippers, we anticipate locking in approximately 40% of the direct capital costs by the end of this year. Any cost variances on the Keystone expansions are shared 75% to the shippers and 25% to TransCanada. Keystone will assume a level of construction risk to achieve greater toll certainty for the shippers and as well to align with the shippers' interests in minimizing those construction costs.

For the purpose of providing sensitivity on a magnitude of cost overrun on the entire project, a CAD 1 billion cost escalation, after cost sharing, reduces the IRR by approximate 0.3% over the life of the project.

I want to take a moment to review the key dates for the Keystone expansion. The binding open season, which began on July 16th, runs through September 4th of 2008. Following that open season, we will proceed expeditiously with obtaining the necessary regulatory approvals in both Canada and in the United States, starting in the fourth quarter of this year. Final approvals are expected to be in place by the second quarter of 2010, with construction activities commencing shortly thereafter. The target in-service date is in 2012.

Over the longer term, the Keystone Pipeline system could be further expanded from 1.1 million barrels a day to 1.5 million barrels per day at a relatively low cost. Through the addition of pumping facilities, the capacity in the system could be increased in 25,000 barrels per day increments, up to 200,000 barrels a day. We estimate the total cost to expand the system by 200,000 barrels a day with additional pumps to be about US $300 million, in today's dollars.

We could add a further 200,000 barrels per day of expansion to the US Gulf Coast through the looping of the section of pipe from Steele City to Cushing.

In summary, we have made significant progress in advancing the Keystone crude oil pipeline project. When complete, Keystone will become one of the largest crude oil pipeline systems in North America, taking crude oil production from Western Canada to important refining markets in the US Midwest and the Gulf Coast regions.

I'll now turn the call back over Greg Lohnes, our Chief Financial Officer, who will provide some additional details on our second quarter financial results.

Thanks, Russ and good afternoon, everyone. As Hal mentioned, earlier today we released our second quarter results. Net income for the second quarter was CAD 324 million or CAD 0.58 per share, compared to CAD 257 million or CAD 0.48 per share for the same period last year.

Second quarter 2008 net income included CAD 8 million of net unrealized gains resulting from the changes in fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts.

Second quarter 2007 net income included positive income tax adjustments of CAD 16 million. Excluding these items, comparable earnings were CAD 316 million or CAD 0.57 per share in the second quarter 2008, compared to CAD 241 million or CAD 0.45 per share for the same period of last year; an increase of approximately 27% on a per-share basis.

The quarter-over-quarter increase is primarily due to increased contributions from both the Energy business and Corporate, partially offset by a slight decrease in earnings from Pipelines business.

I will briefly review the second quarter results for each of our segments, beginning with Pipelines. The Pipelines business generated net income and comparable earnings of CAD 158 million during the second quarter, a decrease of CAD 8 million over the same period in 2007. Of note, GTN's net income for the second quarter increased CAD 10 million, primarily due to the positive impact of a rate case settlement in January 2008 and lower [OMNA] expenses.

TransCanada's proportionate share of net income from other Pipelines decreased CAD 6 million, primarily due to increased project development costs and the negative impact on earnings on a stronger Canadian dollar.

Next some comments on Energy; Energy generated comparable earnings of CAD 143 million in the second quarter 2008, compared to CAD 90 million in the same period last year. Western Power's operating income was CAD 116 million in the second quarter, compared to CAD 57 million last year. Higher realized power prices in Alberta were the primary reasons for the significant increase in earnings in energy's Western Power business.

Also contributing to the increased earnings were higher realized power prices in New England and increased sales volumes to wholesale industrial and commercial customers in our Eastern Power business. Eastern Power's operating income in the second quarter was CAD 80 million, an increase of CAD 10 million compared to the second quarter of last year.

Finally in Power, TransCanada's combined operating income from its investment in Bruce Power was CAD 31 million in the second quarter, which was consistent with the same period in 2007. Details of the proportionate share of operating income in Bruce A and Bruce B can be found in the Energy portion of our second quarter report.

Looking forward, the overall plant availability percentage in 2008 is expected to be in the mid 80s for the two Bruce A operating units and in the high 80s for the four Bruce B units.

Finally with Bruce Power, at June 30th, 2008, Bruce A had incurred CAD 2.2 billion for the refurbishment of units 1 and 2 and approximately CAD 200 million for the refurbishment of units 3 and 4.

Turning now to Corporate; net income from Corporate in the second quarter 2008 was CAD 15 million, compared to net expense of CAD 3 million in the same period last year. Excluding favorable income-tax adjustments in the second quarter 2007, Corporate's comparable income of CAD 15 million increased CAD 30 million, compared to CAD 15 million of comparable expenses in the second quarter last year.

Corporate costs were lower in the second quarter 2008 due to a reduction in various financial charges. Details can be found on pages 14 and 15 of the second quarter report to shareholders.

Turning to the cash flow statement; funds generated from operations were CAD 676 million in the second quarter, an increase of CAD 80 million or 13% when compared to the same period in 2007. This increase was primarily due to the higher earnings from our Western and Eastern Power businesses.

Capital expenditures in the second quarter were approximately CAD 635 million and related primarily to the ongoing development of greenfield projects such as the Bruce A restart, Portlands Energy Center, Halton Hills and Cartier Wing, as well as an expansion of the Alberta system and construction of the Keystone Oil Pipeline.

Finally, our financial position remains strong. At the end of June, our balance sheet consisted of 48% debt, which included our proportionate share of joint venture debt, 4% junior subordinated notes, 1% preferred shares, and 47% common equity. I would note that our debt on this slide is calculated net of cash.

Cash balances are higher than normal, due to a common share offering completed on May 13th. The offering resulted in gross proceeds of CAD 1.27 billion that will be used by TransCanada to partially fund acquisitions and capital projects of the corporation, including amongst others, the acquisition of the Ravenswood generating facility, the construction of the Keystone Oil Pipeline and for general corporate purposes.

After completion of the common share offering, TransCanada filed a preliminary short form shell prospectus with the Securities Regulatory Authorities in Canada and with the Securities and Exchange Commission in the United States, under the multi-jurisdictional disclosure system. The short-form shell prospectus will allow for the offering of up to CAD 3 billion of common shares, first-preferred shares, second-preferred shares, and/or subscription receipts in Canada and in the United States.

As with our existing Canadian and US debt shelf, TransCanada intends to maintain an equity shelf in the normal course of business. Additionally, on June 27th, TCPL entered into a bridged credit agreement with a syndicate of three banks for US $1.5 billion. This facility was put in place for the additional financing required to close the Ravenswood acquisition.

Also of note, in the second quarter 2008, TransCanada issued common shares from Treasury under the dividend reinvestment and share purchase plan, totaling CAD 58 million. Following TransCanada's announcement that it had agreed to acquire Ravenswood from National Grid, all three rating agencies placed the rating of TransCanada under review for possible downgrade.

Subsequently, S&P and DBRS conducted their reviews and reaffirmed the Company's ratings on April 18th and May 5th, respectively. On June 24th, Moody's lowered the long-term debt rating of TCPL to a 3 and the issuer rating of TransCanada Corporation to BAA-1; both with a stable outlook.

Following the downgrade from Moody's, TCPL's senior unsecured ratings assigned by Moody's and S&P became effectively aligned at A3 and A minus, respectively. As such, the Company does not anticipate any material change in its debt funding costs.

As Hal mentioned, we have CAD 17 billion capital program currently underway. This slide provides an update on our committed spending profile for the next several years. Our continued large capital program will add significant and growing cash flow over the next several years which will be available to fund future growth.

The ongoing dividend reinvestment plan will provide TransCanada with approximately CAD 250 million annually. Combining that with our growing cash flow, strong balance sheet, our liquidity and access to capital markets, we are well-positioned to finance our future growth program going forward.

We would not expect to issue common equity to fund our greenfield program. As we add new projects to our existing growth program, we will look at portfolio management and continue to monitor the capital markets for alternative financing options.

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

Thanks very much, Greg. Just as a reminder, before I turn the call 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. And with that, I'll turn it back to the conference coordinator.

Thank you. (OPERATOR INSTRUCTIONS). The first question will be from Carl Kirst from BMO Capital. Please go ahead. Your line is now open.

Good afternoon, everybody and congratulations on a good quarter. Russ or Hal, the first question on Keystone here; to the extent we're looking at a range of 7.5% to 9% on levered returns on the project as a whole. Can you say whether or not the bottom end of that range, the 7.5%, can be met with just what is under contract today, i.e. that 75%?

It can be met with minimal spot volumes; that's one of the major reasons for the range. The range sort of represents uncertainty around spot volumes and at the bottom of the range our spot volume assumptions are pretty minimal. As well, capital costs would be the other major variable that would be in that range.

Okay, but the key there is on minimal spot volumes. With just what we have committed, we can get roughly to that 7.5% range?

At the most, 75% of the revenues are underpinned by the contracts. So that gets it to the low end of the range.

Okay. And then just the second question here; really looking at Bruce-- with respect to-- I think it was page seven where we have the CapEx kind of broken down by project-- CAD 3 billion for Bruce. I assume that's net to you guys. Now that we're kind of closing in on Units 1 and 2 I guess being roughly 68% done; what is that implying for Units 3 and 4 as far as the spend. I mean I can kind of do the quick math but it's coming out to a fairly high number. And I just want to clarify that.

And where are we with the OPA as far moving forward with the additional contracts?

Sorry; additional contracts?

Well, I mean if I remember correctly there was-- we were looking to extend the fixed price out on to 4 as well, or was 4 covered under-- is Unit 4 covered under the original?

Under the amended agreement, all four units are covered.

But as far as capital spend for units 3 and 4?

Pursuant to the deal we did and I'm sorry, I don't have the contract in front of me; but, basically how the deal worked is we agreed on a range of capital outcomes and it's now up to Bruce and its partners to go through all the work to prepare a capital estimate and if get that capital estimate approved by Bruce and its partners falls within the range we had agreed upon, then the project will go ahead.

In the event that our capital estimate were to fall outside the top end of that range, the option would either be to not proceed with the project or to reenter into negotiations with the OPA to see if there's a deal to be done at the higher capital cost.

So we're right now just really starting to engage in that budgeting process. So it's going to be probably a good year or so before we're through that process.

Great. I appreciate the color. I'll get back in queue.

Thanks Carl.

The next question will be from Sam Kanes from Scotia Capital. Please go ahead. Your line is now open.

Thank you. I guess I have to go to Western Power results because they were spectacular, up double year over year with frankly doesn't look like much change in your contract spot mix of 80-20. The sustainability of that; anything on the [forward strip] you could give us color on? One of your suppliers, I guess this morning, said that the spot average was $108. That's extraordinary for a Q2. What are your thoughts about sustainability here on a go forward?

Well Sam, it's kind of interesting. Q2 has historically in the Alberta market always been kind of a weak quarter, pricing wise. Usually demand is not very high. You are correct. We had an average of about $107-$108 for the quarter. I don't think it would be reasonable to expect that kind of pricing to sustain, but I think we're looking at sort for the balance of the probably something getting towards the mid 80s all hours, something in that range.

Okay. A follow up question; it gets much broader; Saskatchewan has now joined the nuclear study party in Canada, along with New Brunswick and Alberta. I imagine you're involved in some fashion in those three provinces, particularly Alberta. Is there anything to say on any progress there whatsoever at this stage?

I think it would be fair to describe all of those jurisdictions as in the sort of very, very earliest stages of contemplating nuclear power. Saskatchewan is an interesting one for us because it is such a large producer of uranium and the people in the province have that much more experience with nuclear industry in that regard. It has a number of positives that I think potentially would even outweigh what regions outside of Ontario would have.

But once again, we're in really early days and I think there's going to be a fairly extensive period before those provinces even develop a position on nuclear generation.

And Sam, it's Hal. I'd just add to that, that on many of these complicated development projects, we're really pressing for some sort of regulatory clarity, some sort of clarity around the government approval process, before we get too far into them. You could say we've learned something in the Mackenzie, but I think particularly with nuclear plants in Alberta or Saskatchewan or the Slave River hydro project, all of these kinds of things; we want to see a clear roadmap as to how we're going to get through it before we get too far into it.

And the governments are generally supportive of the plans we've put out. And we now need to work with those host governments and the regulatory authorities to figure out how do we get through what has become quite difficult regulatory water on many fronts.

Thanks Hal.

Thank you Sam.

Your next question will be from Faisel Khan from Citigroup. Please go ahead. Your line is now open.

Good afternoon. In terms of funding all the projects, you talked about having -- having future offerings of up to $3 billion; (inaudible) talked about possible asset portfolio divestitures. Is there a particular part of your portfolio that would be susceptible to sales or are you looking at-- is everything on the table?

I think the broad comment I'd make on that would be that we would make decisions to hold or divest of an asset based on its remaining potential for value creation. If an asset is mature and we don't see significant strategic value in retaining it to pursue other objectives, and we think we can get pretty full value in the market, then that would certainly be a candidate.

But we don't have a lot in our portfolio right now that would fall into that category. We're pretty comfortable with the assets that we hold on the pipe side. Our different pipelines give us great strategic advantage in pursuing everything from crude oil conversions through US Rockies gas to Mackenzie in Alaska and connecting LNG in the East.

On the pipe side, we're comfortable on the power side. We've been pretty disciplined about sticking to our Western region and our Eastern region and Bruce. And so we don't have a lot of scattered-- what I might call non-core assets. The suite we've got right now is pretty good.

So I wouldn't see a lot of strategically-driven divestments. We may from time to time have a financial reason why we may want to sell something to raise money. But as Greg pointed out, that's a near-term priority. Greg, would you add to that?

I'd just say that portfolio management includes the wide suite of things that we could undertake. We mentioned before that we monitor the potential from drop downs into our LP where we would maintain control of the assets. And we also from time to time talk about partnering with strategic partners who an interest in assets that have a very long life and very stable cash flow. So I'd take that in the broad context.

Okay. With regards to the Keystone Pipeline, is there a particular grade of crude that the producers are looking to bring down to the Gulf Coast or is it kind of a mix of everything?

I would say that it's mostly heavy at the current time, but there is some interested in moving lighter grades of crude oil and certainly through Keystone to the Midwest, it has been lighter grades of crude oil. So in total, the system will move a mix of various types of crude. But to the Gulf Coast, initially out of the gate, the most part has been [Dutchman].

And to start with, most of the excess supply in Western Canada is Dutchman and diluted Dutchman. And most of the market for demand for it in Houston I think Russ would be for Dutchman because they have the refining complexity to process that.

But I always like to add that the Keystone system would be quite happy moving lighter grades of crude and the lighter the crude the better. Frankly, we can move more of it that way. And so for some concerned parties that keep emphasizing that this project is just exporting jobs out of Alberta, we don't agree with that. It's very important that crude oil not be bottlenecked in Alberta and Keystone provides a very high volume outlet to really high quality markets. And if the producers decide over time to upgrade more of that crude in Alberta, we're just fine with that.

Okay. And are there any issues with the amount of supply of diluent to be able to transport that heavy crude down to the Gulf Coast?

There can be, but there are a number of projects underway-- one of the interesting things is you can synthetic crude from operations like Suncor and [Syncrude] as a diluent, and so that of course is called [syn-bit] as opposed to [dil-bit].

Got you. And on the Power side of the equation, what were the observed market [heath] rates for you guys in Alberta?

I don't have that in front of me, but I would guess it would probably be about 10.5; something like that. It might be a little higher than that even.

Okay. And would you say that certainly higher gas prices played a part in kind of expanding those margins in the quarter?

Yes, I think that's right. But one of the-- particularly in Q2, a really big impact in Q2 in addition to that there were a fair degree of unplanned outages in the Alberta fleet which also had some impact in that.

Okay. And then just on the Bruce reference prices that were reset on April 1st, the inflation adjustment; is that observed from kind of the floor prices that we see for Bruce B or is that also observed in the prices for Bruce A?

Both.

Okay, because there's a difference in magnitude I guess with the price change from this quarter this year versus the quarter last year.

Part of that I think Alex, is the extra capital for Unit 4?

Yes.

Okay, understood. Thank you, guys.

Okay, thanks Faisel.

Thank you. The next question will be from Bob Hasting with from Canaccord. Please go ahead. Your line is now open.

Thanks; just a couple of clarifications on some of your G&A; from the Energy side, I see that G&A dropped CAD 6 million in the quarter from the first quarter level. And I was just wondering sort of why that would be and what expectations for the rest of the year might be there?

I think that was primarily related to some just generally reduced BD costs, is primarily what it was, and I think we are overall generally tracking a little lower on BD costs than we probably had anticipated at the first part of the year.

So that second quarter level might be a reasonable level going forward?

Probably, plus or minus 20%; it'll move around about that much, Bob.

And on the Pipeline side I noticed there was quite an increase there and the Northern Pipeline seemed to come in with an expense again, even though it wasn't there in the first quarter. What's going on there?

I think generally it's our BD expenses again would be up, just due to level of activity that we're undertaking right now as we kind of outlined in the overview. As far as the Northern development numbers go, I'll have to get back to you on that.

Bob, are you just looking at the $1 million a quarter?

Well yes, the $1 million in the quarter; there was nothing there before; I assume you maybe you were capitalizing it before and so I was a little surprised there. And I would have thought maybe you would have started capitalizing some of the Keystone costs as well, so I'm surprised to see it maybe rise up like it did in this quarter.

So the Northern development, the Alaska costs we haven't started to capitalize yet. As you know the Mackenzie APG advances are capitalized. The amount is $1 million. Yes, it was zero last quarter. I think you're looking at rounding in there, quite frankly.

Okay. Okay, one last question on the Portlands- just accounting for that again. How do you expect that sort of to come through? You were starting to run that this summer, then you closed it down again. We will you capitalize any of the costs between the periods it's running if it comes up again next year?

Yes, basically. The plant is meant to be a (inaudible)-cycle plant; that's the intended use of it, so we will continue to capitalize costs.

Okay, so you report the earnings as they come through here in the quarter and then capitalize--

There are effectively no earnings to date on Portlands Energy Center.

But there will be for the summer; in the third quarter, though. Right?

Only to the extent that it's dispatched.

There could be some but it wouldn't be a lot.

Okay, good. Thank you very much.

Thank you Bob.

Thank you. Your next question will be from Stephen Paget from FirstEnergy. Please go ahead. Your line is now open.

Good afternoon. Just on the-- from the Rockies westward--does Palomar depend on Sunstone to any extent or are they two completely independent projects? I remember that Palomar was proposed first so I'm assuming there isn't much of a connection, that either one could go ahead no matter what happens with the other?

They are independent projects. I think Palomar could be larger to the extent that Sunstone moves forward and we move more volumes into that region, and one way to access the markets for Sunstone is to use Palomar, but they are independent projects and I'd expect them to move forward on an independent basis. They have different groups of shippers that have indicated interest for both of those pipes.

Okay. Thank you. And when should we look for more clarity on the Rockies pipelines in both directions out of the Rockies; whether it's Pathfinder or Bison or Sunstone?

I think you'll see that the next couple of quarters are critical. The producers in the Rockies are getting nervous as you can see sort of by where market differentials are going that they could see a very large widening of the differential unless we bring on some new capacity in that sort of late 2010or early 2011 timeframe. In order to hit that timeframe, some decisions have to be made in the next one to two quarters as to which pipelines are going to move forward. So I would say that you could look for that kind of timeframe for some decisions to be made by the various proponents.

Okay; thank you gentlemen.

Thank you Stephen.

Thank you. The next question will be from Robert Kwan from RBC Capital Markets. Please go ahead. Your line is now open.

Good afternoon. Russ, you touched on the full-cycle IRRs for Keystone and at the 7.5%, if that's where you're current commitments are; what are the assumptions with respect to the cost overrun to be at that number?

Again, the way we run it is we don't run sort of individual scenarios for sort of worst case of every scenario; worst case spot, worst case capital cost overrun; is we run various reasonable scenarios and at the low end of all of those things we come to a number that looks like around 7.5%. I think the sensitivity we gave around capital cost was a third of a percent for every $1 billion in total overrun on the cost. That swings the IRR by about 0.3%.

Right. So (inaudible) 7.5% is no additional volumes but probably on time, on budget? Like, this isn't the worst case scenario?

No, it could definitely be worse than that.

And then on-- is it symmetric on the 9%, would that be fully contracted and under-budget or would that be fully contracted on time, on budget?

No again, that's just sort of I guess a reasonable range at the high range. It could be higher than that as well, based on a certain group of moving lots of spot volume and coming well under budget or even on budget; it could lead you to a number in excess of 9% or 9.5%.

And I guess just last question; if you're looking at the Rockies region, how many pipes do you see being needed in that 2010 say to 2011 timeframe to serve just the general Rockies region? And I don't know if you can split that between what you think might head east and west. And then with respect to Sunstone; given El Paso's announcement that [Ruby] is moving forward, is there a feeling that that's just kind of killed Sunstone at least for that 2010-2011 timeframe?

I guess our view is it would probably need somewhere between 1.5 and 2 bcf of capacity out of the region in that sort of 2011-2012 timeframe. So that would suggest that a couple of projects in the neighborhood of $1 billion could probably move forward. And with respect to whether there will be a West project or not I think is still uncertain. What we're hearing in the marketplace is that there are still people interested in both our Pathfinder project and in our Sunstone project and we haven't seen any reason not to continue forward with those projects at this point in time.

We understand that the Ruby has announced that they're moving forward for sure. But we also know that there are certain hurdles that they have to get over in the marketplace before they can actually do that. One of them obviously is their largest anchor shipper is Pacific Gas and Electric which has to run through a regulatory process in California to obtain approval for that shipping agreement and we know that that won't be approved until at least the fourth quarter of this year.

So our view is it's still an open field for competing and that's what we're doing as hard as we can.

Okay, great. Thanks, Russ.

Thank you Robert.

Thank you. The next question will be from Matthew Akman from Aquarian. Please go ahead. Your line is now open.

Thanks very much. My first question again is for Russ. Sorry not to give your voice a rest, but in terms of your Horn River and Montney pipeline; what is the construct that would be developed under? Would that be in rate base or would that be a contract-type pipeline?

It would go into rate base, is a new-build pipeline that would be National Energy Board regulated. And then if we're successful in our application to change jurisdiction--our Alberta system from an Alberta regulator to a federal regulator; we would roll those shipping commitments, if you will, and use the NGTL rate design to service those shippers. So it would become part of the NGTL rate base essentially.

In terms of timing, our understanding is that the National Energy Board is going to review our-- we had sort of a dual-pronged application for jurisdictional change. One was to determine whether the National Energy Board had jurisdiction; and the second one was, if they did have jurisdiction, then that the logistics essentially of making the transition. The National Energy Board has ruled that they will hear both of those is parallel, so what would happen is we'd get a decision at the end which would-- if approved in our favor it would be that jurisdiction would move and all of the logistics and permits would be granted at that point in time.

What they've told us is that that could occur as early as the first quarter of next year; which sort of dovetails well with sort of our planning for the Montney and Horn River plays as we'd hope that that would come together in sort of the middle part of next year.

So we're actually planning right now sort of the two scenarios; one, if the independent separately contracted pipe if we don't get jurisdictional change and to our existing rate base if we do get jurisdictional change.

Okay. And I guess then is the NGTL system still going to be reviewed by the Alberta Utility Commission in terms of its equity ratio and ROE at the same time; even though it may not be under that purview anymore?

No. At that point in time--

Because the AEC is doing a generic hearing for all the assets, so it's kind of happening at the same time.

Correct. So again, we've got a number of proceedings underway that are currently operating under AEC jurisdiction; our North Central (inaudible) application, for example, our NGL convention application as well. And we would expect business as usual at if the AUB would render a decision on those and those would be binding decisions.

The generic process in terms of timeframe; is I'm not sure that that timeframe will dovetail with the National Energy Board timeframe of Q1 of next year. If a decision is made before a jurisdictional change, obviously that would change-- if they made a change in capital return either in structure or rate of return. Those would be applicable to NGTL, but if it happened afterwards, I wouldn't think that they would be. Those would have to be determined by the National Energy Board.

And I think in a generic process, I guess in terms of outcome; I'm not sure if automatically we'd see a change in our rates anyway or whether we would have to apply for new rates. So a lot of those things haven't been sorted out yet, but that would be my view right now, Matthew.

Well let's hope the NEB comes out on top of all this anyway and we don't have to worry about it.

My next question is just a quick one for Greg. On Corporate, usually I think of Corporate as being an expense but I think it was income in this quarter. I could ask detailed questions about it, but instead I'm just ask bottom line-- what should we expect for a run rate in this segment going forward?

Glenn is just looking at that Matthew so we'll--

I think it's fair to say Matthew that you're right. Corporate is a bit of a catch all between financial charges and some other adjustments and tax adjustments and things such as that. As you see, it is positive this quarter. I don't think you'd normally see that, if I can say that.

So as far as a run rate I think something more akin to where you saw first quarter probably makes some sense-- somewhere between zero and I think we had 22 at first quarter, so somewhere in there.

Okay. I won't get into any more detail. Thanks very much for that.

Thanks Matthew.

Thank you. (OPERATOR INSTRUCTIONS). The next question will be from Andrew Kuske with Credit Suisse. Please go ahead. Your line is now open.

Thank you; good afternoon. I'm not sure if Hal or Russ you want to deal with this one, but just your outlook on crude dispersion in North America; especially Alberta production-- how much volume do you see over the next let's say five and ten years being shipped down to the Gulf and then just in other areas of North America, how do you see the market developing?

I'll start out. Russ may have a better answer than I do, but I just observed that we are going to be set up to move roughly 1,000,000 barrels today through the Keystone system and a significant portion of which may just notionally think 600,000 or 700,000 barrels would end up at the Gulf. A certain portion of that volume will diverge to other markets on the way down, but I think we would see that much and we're set up over time to have low cost expansions at Keystone.

One of the advantages of having some spot volume space available is it does give us a leg up on competitors who don't have that space available. We've learned in our Canadian gas system that having a little spare capacity is a good thing in that we can bring it on stream much cheaper than people can bring on new projects. So we would intend to stay ahead of that curve and be the preferred shipper of Western Canada crude to the Gulf Coast.

We also would recognize that the Chicago market and markets in that Chicago region are attractive to Canadian shippers. And our competitors move into that area and we would expect that to continue, but the volume there would largely be determined by demand and it'll be a market that is preferred for Western Canadian producers, but I would hazard to say that it's probably limited in terms of absolute volume growth. It's a pretty mature market.

We see some crude perhaps moving east, but the tough thing there is you get to the east coast of North America and you're competing directly against crudes that come in from Norway for example and places like that, at a relatively cheap shipping cost; much shorter distance of haul from Norway to the Northeast US or the Maritimes of Canada than it is from Norway or other places to the Gulf Coast. And so we think the Gulf Coast is actually a better market for us than the far eastern parts of Canada.

And finally, we know that there are multiple projects that people are pursuing to move crude to the Pacific Rim and we think that is a good option for Canadian crude if there is a pipeline there; that Canadian crude producers might want to use that; perhaps as a spot market or perhaps as a base market.

But it's not the market that we would consider it to be the preferred market for Western Canadian crude. We would give that to the Gulf Coast and so that's where we've chosen to focus our efforts.

Do you see any opportunities that you really have in the California market at all using some of your existing rights of ways?

Well, we do. But there are a lot of other issues there. Clearly we believe there will be crude oil supply available out of Western Canada. And we do have rights of way and we've also done extensive engineering on other routes that we could use to go down to the California market. But we'd have to see some evidence that the California market would be a stable market for Western Canada crude oil over the longer term. And I think that would be a bit of an uncertainty right now.

I think what we're dealing with is we're expecting production to grow in Alberta 2 million to 3 million barrels a day. And today, the bulk of that goes-- we service the Alberta refineries and then the bulk of it goes to the Midwest as Hal said. And pretty much, that market is saturated with Canadian crude. Canadians have a very high market percentage; probably 70% to 80% plus.

So we don't see much growth in that market, we may see a shift in quality if certain refiners add cokers and that sort of thing, but if they do that; that means we'll introduced heavier and it will push out lighter crudes. So those crudes, those 2 to 3 million barrels a day; have to find a new home, and we've looked at all the various homes that it could go to.

As Hal mentioned we can go offshore to the Pacific Rim, going to California as you mentioned, and the Gulf Coast. The Gulf Coast is currently the pocket that can absorb that amount of crude oil. Just coincidentally, their supplies are declining. The [Catheral] field is declining. The Venezuelan crude potentially moving to places like China and those sort of heavier grades moving away from the Gulf Coast, provides an opening for Canadian crude.

But I think where we have to go in terms of your question on dispersion is we have to find a market that's large enough for a couple of million barrels a day of steady sort of eating up of that crude every day. And that's why that we believe that the marketplace has jumped on the Keystone project; is it provides that link for a million or a million and half barrels. That's not to say that once we grow through that, that they might look to other markets. But what we know is that the Gulf Coast could actually absorb a few times that amount if necessary, if Canadians needed to push through and compete sort of with sort of crude on crude competition. That's a place where they can compete and push out other crudes.

You can't do that in the Midwest and it's very difficult in California. There just isn't the size of market there necessary to move a couple of million barrels a day to it. So that's how we came to the conclusion, both on our own and then the market response is that that's the logical place to move the bulk of the new production that comes on.

We are looking at projects that could both go off the West Coast and down the West Coast.

And just one final point; the look of the market size on the Gulf Coast you see growth opportunities for Keystone; but do you see growth opportunities for other pipelines within that region?

Yes, like I said, right now we have captured I think the next phase of growth of the Western Sedimentary Basin out of the oil sands. But there will be another one in 2014-2015. As we said, we're positioned with a potential for expansion of another 400,000 barrels a day in that point in time and we'll have to compete head on with others with their proposals as that new crude comes on. And then if you believe the forecasts, we're going to see even more production by sort of 2018-2019-2020; and we'll have to find new markets for those as well.

And the Gulf Coast is the likely place to absorb the lion share of that volume.

That's great. Thank you.

Thanks Andrew.

Thank you. The next question will be from Linda Ezergailis from TD Newcrest. Please go ahead. Your line is now open.

Thank you. Just a clarification on Keystone; you mentioned that you expect about 1 million barrels per day running on Keystone; maybe 600,000 or 700,000 of that to the US Gulf Coast. What timeframe are you referring to, to get to that 600,000 to 700,000 barrels a day? And I guess I'm looking for an expectation of ramp up, not just a before that point in time, but also beyond that.

That will initially come on at about-- the initial capacity of the system is about 600,000 barrels a day and it'll take the crude to Patoka and Wood River. The sort of ramp up timeframe we're kind of looking at right now-- it'll probably take us two years to ramp up, so 2009-2010 to get to that sort of level. And then for the expansion to the Gulf Coast; as we said, it's 500,000 barrels a day that we'll have available to move to the Gulf Coast. And I would expect to be pretty much the day that we're ready to start operating, we'll move 500,000 barrels a day to the Gulf Coast.

As I said, we've got 300,000 barrels a day under contract currently. We're out for an open season. Our expectation is that number will come up somewhat. But depending upon sort of the supply and demand, we'll be in the position where we could move 500,000 barrels a day in sometime sort of pick mid 2012, plus or minus a few months as our expectation of when we would be in a position to move crude to the Gulf Coast.

But once it's ready to go; once we filled it up with line fill and the pipe is ready to go; we'll be ready to move that crude to market.

And Linda, there's the Cushing destination point as well. Some of that volume, depending on what shippers want to do, could end up moving further south to the Gulf Coast. When we proposed I think Russ, the first project to Cushing; that was as far as it was going and people nominated to Cushing because that's as far as they could get. It remains to be seen as we move into the fully integrated extent of an expanded system, some of those volumes may move around a little bit.

I think Hal is absolutely correct. Potentially at the end of 2010, we might be in a position to move because we may construct both the Cushing leg from Steele City to Cushing and Cushing to the Gulf Coast, simultaneously in 2010. And if we do that, we could probably push through somewhere in the neighborhood of 200,000 to 300,000 barrels a day to the Gulf Coast in 2010, if that's how our customers wanted us to sort of ramp up the pipeline.

Okay, and then beyond the mid 2012 time period, you're assuming perhaps an extra 500,000 barrels by 2014 in your internal planning purposes or--?

Actually, our internal plan, in terms of the economics we presented; it doesn't include any of that expansion today. If the volumes grow in Western Canada and there is a desire to move that to the Gulf Coast what we're saying is that in a very short order, we could add pumps in 25,000 barrel a day increments up to that 200,000 barrel a day level and then we could loop that section from essentially Steele City to Cushing and get ourselves up to 400,000 barrels a day, if that's what the marketplace wanted us to do and it wouldn't take us very much time after 2012, if there was actually the crude volumes to move.

Okay and just a clarification on your sensitivity; that $1billion that you sited on the third of a percent of returns- was that on a 100% pipeline basis or is that net TransCanada ownership?

That's 100%, so our estimate at CAD 12 billion, if it goes to CAD 13 billion, that's the kind of sensitivity that we have.

Okay and just a follow up question on your current operations on ANR; I was a bit surprised to see earnings down CAD 4 million year over year and it appears that it's largely higher OMNA. Is that a timing issue or should we expect that sort of continued higher level of OMNA every quarter going forward?

I don't think you should expect a higher level of OMNA then we experienced in the same quarter last year. So I would suspect that there are some timing differences and those kinds of things in there. So I think run rate would be somewhere in the middle of those numbers some place if we're talking about a CAD 4 million spread there. I don't know Glenn, if you have a better view than that. But there is no reason why costs are up. Actually, costs should be down slightly because we're sort of getting through the initial phases and getting everybody in their jobs and that sort of thing, so we should see some of those-- redundancies and things that you have initially start to move away. So if anything, I would expect them to be down slightly rather than up slightly going forward.

I think that's fair.

Okay. Thank you.

Thank you. The next question will be from Daniel Shteyn from Desjardins Securities. Please go ahead. Your line is now open.

Yes, good afternoon, everyone. First, I'd just like to check something about the Keystone pipeline. Now I certainly understand the fact that it's a contracted as opposed to a regulated pipeline; but have you been able to build any sort of shipper support for your piece of the capital spend during the construction phase such as for instance, if you do see AFUDC on the regulated pipe?

I'm not sure if I understand your question. Is it-- in the contracts we get-- there's a contractual I guess return AFUDC so we get return on the pipe during the construction. From an earnings perspective, we don't actually take that into earnings. We capitalize the interest costs and that's the extent of sort of the benefit on the earnings side.

But from an economics perspective, we do get the benefit of AFUDC during construction. It's part of that capital cost estimate which goes to the calculation of the total. So for example, if the project takes longer and the AFUDC is higher, that's part of this 75-25 risk sharing that we talked about.

Okay, so there is AFUDC, but from what I understand you were saying, there's just AFUDC on the debt portion but there isn't any on the equity portion?

Just for earnings for the accounting statements; but from an economic perspective, we do collect AFUDC on total capital like on our-- it's calculated based on our weighted average cost of capital is the way we calculate AFUDC for economics. But for accounting purposes, my understanding is we only capitalize the interest portion.

Okay, so that's the difference between the regulated pipe and the contracted pipe in this case?

One of the things that that means I think Daniel is that a regulated pipe would show earnings up front even when it's not operating. But for the equivalent IRR, it would then show smaller earnings over the future life of the pipe than a regulated pipe would.

Alright, so that's the first thing. The second thing is looking at slide 25 of your slide package for this quarter, the estimated capital spend; just looking through I guess the five years there, wondering if under the Energy you've baked in any sort of CapEx for the Ravenswood expansion or that potential expansion that you talked about when you acquired the asset or is that something that is not being put in there for deliberately or what's the deal with that?

It's not in those numbers. Those numbers would correspond to the list of projects that Hal talked about on page 7. And Alex, maybe you just want to talk about timing-- looking at potential--

Just I think really the only comment I have on that is that our real ability to really roll up our sleeves and dig into the powering options that we identified will occur after the deal closes in Q4. But that we certainly-- we are staffing up and putting our best people on that so we'll be working on that over the next number of quarters after we close the deal.

It's Hal here. I'll just point out that what you see on slide 25 are only really those solid committed projects that we've got underway. In the Energy sector in particular, we always every year we have a growing portfolio of projects that we're going to invest in. This fade that you see on Energy investment from '09 from 2012; that is simply because we have not yet brought firmed up projects forward. I'm pretty comfortable that we'll be investing something like $1 billion a year and maybe a little more than that in Energy projects as we go forward. But these are the ones that we're committed and that are actually tangibly going ahead.

Okay. Finally last point on Alberta power prices which have certainly been pretty high over the last quarter; I'm just wondering what has been the earnings effect of the new emission intensity rules in Alberta on your-- has that been a net cost to you in terms of what you have to pay Transalta for instance, to make them whole under the PPAs or have you been to recover most of that in higher power prices. So that's relative to the historical and also what's your expectation for the future.

Well, my recollection is that it's probably about somewhere between CAD 15 and CAD 20 million a year would be the costs that we calculate under the Alberta program and I guess what I would say to the extent that coal-fired units are setting the price, we and I imagine every coal-fired unit that is setting the price; we would be recovering that and there's probably something less than a full recovery when the gas units are setting the price. So I would probably say that we're probably recovering somewhere in the range of probably around 35% to 40% of those costs.

Okay, very good. Thank you.

Thank you Daniel.

Thank you. We have a follow up question from Stephen Paget from FirstEnergy. Please go ahead. Your line is now open.

Good afternoon. Well, one more and we've taken up a lot of time but; the Bruce A unit 2 project; well over half way, half of the tubes removed but at this point-- how is that project looking for being on in 2009 or early 2010?

I think we're still in the ballpark on that. I think that we've sort of always said on the end of '09 the beginning of 2010 with one unit lagging the other by six months and I think we're in that range.

Okay, great. Thank you.

Thank you. There are no more analyst questions at this time, gentlemen.

Could we just turn it over to the media then to the extent that the media have questions?

(OPERATOR INSTRUCTIONS). And there does not appear to be any questions from the media at this time, gentlemen.

Okay, thank you. Just in closing then, I'd like to thank everybody for their interest in TransCanada. We thank you again for your participation and look forward to talking to you soon. Bye for now.

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