TC Energy Corp (TRP) 2008 Q1 法說會逐字稿

Good day, ladies and gentlemen and welcome to the TransCanada Corporation 2008 first 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 are pleased to provide the investment community, the media and other interested parties with an opportunity to discuss our 2008 first quarter financial results and general issues concerning TransCanada. With me today are Hal Kvisle, President and Chief Executive Officer. Greg Lohnes, Executive Vice President and Chief Financial Officer, Russ Girling, President of Pipelines, Alex Pourbaix , President of Energy, and our Vice President and Controller Glenn Menuz. Hal and Greg will begin today with some opening comments on our financial results and other general issues pertaining to TransCanada. Please note that a slide presentation will accompany their remarks, a copy of that presentation is available on our web site at TransCanada.com. It can be found in the investor section under the heading conference calls and presentations.

Following Hal's and Greg's remarks, we will turn the call other 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 reenter the queue. Also, we ask that you focus your questions on the 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 those risks and uncertainties, please see the reports filed by TransCanada with the Canadian securities regulators and with the Securities and Exchange Commission. Finally, I'd 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 thanks for joining us this afternoon. I will keep my remarks brief, as many of you may have participated at the TransCanada annual meeting this morning either in person or via web cast. As David mentioned, our annual meeting web cast is now archived on the web at TransCanada.com. At our annual meeting, I detailed our strong financial performance and shared the significant project milestones we have achieved in our pipeline and energy businesses that have set the stage for continued growth and value creation in the years ahead. Our strategic focus remains clear as we pursue our goal to become the leading energy infrastructure company in North America. I will now take a few minutes to talk first quarter financial highlights as well as three notable developments, and then I will turn the call over to Chief Financial Officer, Greg Lohnes, who will review our financial results for you in more detail.

For the first quarter of 2006, TransCanada's net income was $449 million, or $0.83 per share, compared to $265 million or $0.52 per share in the first quarter 2007. Net income included a number of one-time items, including $152 million from Calpine bankruptcy settlements. Comparable earnings were $326 million, $0.60 per share for the first quarter of 2008 versus $250 million or $0.49 per share in the first quarter of last year, an increase of approximately 22% on a per share basis. Funds generated from operations in the first quarter of 2008 were 58% higher at $922 million, compared with $582 million for the same period last year. TransCanada's board of directors declared a quarterly dividend of $0.36 per share for the quarter ending June 30th, 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 from treasury at a 2% discount to the average market price.

I will now expand on three recent developments from the first quarter. Firstly, Keystone, the U.S. $5.2 billion keystone oil pipeline project achieved a major milestone after receiving the U.S. Department of State Presidential Permit, authorizing construction maintenance and operations of the facility at the U.S. Canada border to transport a growing supply of Canadian crude oil to key markets in the U.S. Midwest. Actual field construction will commence in the next few months. We will have Keystone up and running by the end of the 2009 construction season, establishing TransCanada as a major player in the oil pipeline business. We also continued to explore options to transport a growing supply of Canadian crude oil to the U.S. Gulf Coast refining market. We have made excellent progress in negotiations with both Alberta producers and gulf coast refiners on a major expansion of the keystone system. We are proposing a 36-inch diameter pipeline running from Alberta to northern Nebraska,and then south to the Gulf Coast, just east of Houston. The proposed routing is shown as the dotted line on the map. This would not be a modest expansion of Keystone, it would in fact be a larger project than the original Keystone. More importantly, it would provide a direct pipeline connection from Alberta to the largest crude oil refining center in the world, the U.S. Gulf Coast.

Turning now to Ravenswood. In March 2008, we announced an agreement to acquire the 2480 megawatt Ravenswood generating facility in New York City for $2.8 billion. This acquisition is subject to various State and Federal Government approvals, which are expected in the third quarter. This acquisition is a strong fit with TransCanada's strategy to grow our power business in markets where our assets, expertise, and financial strength enable us to be a strong competitor and a reliable energy provider. The Ravenswood facility is a high quality asset that is an excellent fit with TransCanada's existing generating assets and power marketing capabilities in the U.S. northeast, which includes the Ocean State Power Complex, a 560 megawatt gas-fired combined cycle power plant in Rhode Island, TransCanada Hydro, 567 megawatts of hydroelectric generation on the Connecticut and Deerfield rivers in new England, a significant power marketing and commercial office in Westblack, Massachusetts and the Kidney Wind Power Project, a proposed 132 megawatt wind energy project in western Maine.

The New York City power market is a capacity market that offers excellent long-term economic fundamentals for Ravenswood and the Ravenswood facility has a highly favorable position in that New York City market. Ravenswood is an absolutely critical asset for the New York City power market and represents nearly 25% of installed capacity. We believe additional generation will be required in the region and Ravenswood also has significant potential for repowering an expansion investment opportunities in the years ahead. We are very pleased that we have acquired 2480 megawatts of combined baseload and peaking capacity in this critical market at a capital cost of $1,130 per kilowatt of capacity. Estimates by numerous industry consultants placed the capital cost of new base load generation in New York City at more than $2,000 per kilowatt for base load and the capital cost of new peaking generation at more than $1,500 per kilowatt in the New York City marketplace. In summary, Ravenswood represents excellent long-term value for our shareholders. Its strategic location right in the attractive New York City market along with its revenue diversity coming from energy capacity and ancillary services makes Ravenswood a great addition to TransCanada's growing North American power generation portfolio.

And now, Bruce. Last week we provided an update on the comprehensive review of costs for the Bruce A units one and two restart project. The review, which was completed by Bruce Power, its owners and independent experts with significant experience in energy infrastructure megaprojects, included a thorough assessment of costs incurred to date together with a complete review of the remaining work and the cost of that remaining work. The project has generally gone well, both phases of the rebuild have been on time and within budget. Our reactor rebuild contractor, Atomic Energy Canada, Limited did experience difficulty and delay in the reactor rebuild work and that has caused the entire project to suffer a certain amount of delay and some extra costs.

I am pleased today to report that AECL has now resolved those difficulties and the pace of the reactor rebuild work has picked up considerably, however due to the delays already occurred, we will not achieve Bruce's original target price of $2.75 billion, nor will we earn the stretch target internal rate of return of 13.5% aftertax on total capital employed. We will, however, earn an excellent return ranging from 11.5 to 9.5% depending on the final cost outcome. The Bruce team, with considerable help from TransCanada negotiated a very sound agreement with the Ontario Power Authority. That agreement has assured us of an adequate return even in the event of delays and cost overruns. We would not have proceeded with the Bruce refurbishment without that sort of cost and and risk sharing arrangement. The wisdom of that agreement should now be evident, TransCanada is comfortable that we will achieve an excellent project outcome and a strong financial return from the Bruce A 1, A 2 refurbishment project.

In summary, it is opportunities such as these and the many others I highlighted earlier today at our annual meeting of shareholders that will continue to build long-term value for our shareholders. I will now turn the call over to Greg Lohnes, who will provide additional details on our first quarter financial results. Greg?

Thanks Hal, good afternoon, everyone. As Hal mentioned earlier today we released our first quarter results. Net income for the first quarter was $449 million or $0.83 per share, compared to $265 million or $0.52 per share for the same period last year. First quarter 2008 net income included the positive impact of both the CalPine bankruptcy settlements and a GTN lawsuit settlement offset by a write down of Broadwater LNG project costs and fair value adjustments of natural gas storage inventory and forward contracts. First quarter 2007 net income included positive income tax reassessments and adjustments of $15 million. Excluding these items, comparable earnings were $326 million or $0.60 per share in the first quarter 2008, compared to $250 million or $0.49 per share for the same period last year, an increase of approximately 22% on a per share basis. The quarter-over-quarter increase is due to increased contributions from both the pipeline and energy businesses.

I will briefly review the first quarter results for each of our segments beginning with pipeline. The pipelines business general drafted comparable earnings of $199 million during the first quarter, an increase of $44 million over the same period in 2007. The increase was primarily due to a whole quarter of earnings from ANR and higher earnings from the Canadian mainline and GTN. TransCanada completed the acquisition of ANR on February 22nd, 2007 and included net earnings from that day. The Canadian main line's net income increase was primarily related to the higher dean common equity ratio and certain performance based incentive arrangements. GTN's comparable earnings for the first quarter increased primarily due to the positive impact of a rate case settlement in January 2008 and lower OM&A expenses.

Now some comments on energy. 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 $149 million in the first quarter 2008 compared to $106 million in the same period last year. The increase was due to higher contributions from Western Power, Eastern Power, Bruce power and Natural Gas Storage. These increases were partially offset by higher general administrative and support costs. Western Power's operating income was $78 million in the first quarter, compared to $73 million last year. The $5 million increase was primarily due to increased margins from the Alberta power purchase agreements resulting from higher overall realized power prices. Eastern Power's operating income in the first quarter was $85 million, an increase of $18 million compared to the first quarter last year. The increase was primarily due to the impact of increased generation from the TC hydro facilities in combination with higher realized power pool prices in New England. Also contributing to the increase were increased sales volumes to wholesale, commercial, and industrial customers.

Finally in power, Bruce power contributed $37 million of operating income in the first quarter compared to $29 million last year. $8 million increase was primarily due to higher output and higher realized prices at Bruce A. Bruce A prices were slightly in the first quarter of 2008 compared to the same period in 2007 due to the April 1, 2007 inflation adjustment to the contracted fixed price. The output from Bruce A in the first quarter 2008 was sold at a fixed price of $59.69 per megawatt hour, before recovery of fuel costs from the Ontario Power Authority, compared to $58.63 per megawatt hour in the first quarter 2007. Effective April 1, 2008, the Bruce A fixed price is $63 per megawatt hour. Pursuant to the 2007 amendment to the contract with the Ontario Power Authority, the fixed price for output from Bruce A increased by $2.11 per megawatt hour, subject to inflation adjustments from October 31, 2005. Looking forward, the overall plant availability percentage in 2008 is expected to be in the low 80s for the two Bruce A operating units and low 90s for the four Bruce Bs. As Hal stated, the capital cost of the Bruce A restart and refurbishment of unites one and two expected to total approximately 3.1 to $3.4 billion with TransCanada's share being approximately 1.55 to $1.7 billion. As of March 31, 2008, Bruce A has incurred capital costs of $2 billion on the restart and refurbishment projects.

Finally on the Energy segment, natural gas storage operating income of $48 million in the first quarter increased $18 million-dollar compared to the same period last year. The increase was primarily due to incremental income earned from the start up of the Edson facility which was fully operational the in the first quarter 2008, but only in the commissioning phase in the first quarter of 2007. Partially offsetting the increase in earnings from the Edson facility was a decrease in earnings from the Cross Ulta facility as a result of lower realized seasonal natural gas price spreads in the first quarter 2008, compared to the same period last year.

Turning now to corporate. Net expenses from corporate in the first quarter 2008 were $22 million compared to net income of $4 million in the same period last year. Excluding favorable income tax adjustments in the first quarter 2007, corporate's comparable expenses were $22 million compared to $11 million the first quarter last year. Higher financing charges, primarily as a result of financing the A&R and Great Lakes acquisitions and losses on derivatives used to manage the companies exposure to foreign exchange rate fluctuations were the primary reasons for the increase in comparable expenses.

Turning to the cash flow statement, funds generated from operations were $922 million in the first quarter, an increase of $340 million or 58% when compared to the same period in 2007. This increase was primarily due to gains from the CalPine bankruptcy settlements and higher earnings. Capital expenditures in the first quarter were approximately $460 million related primarily to the on going development of green field projects such as the Bruce A restart, Portland's Energy Center, Halton Hills, and Wind, 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 March, our balance sheet consisted of 53% debt which included our proportionate share of joint venture debt, 4% junior subordinated notes, 1% preferred shares and 42% common equity. In the first quarter 2008 TransCanada issued common shares from treasury under its dividend reinvestment and share purchase plan totaling $54 million. TransCanada Pipelines Limited A rating is valuable to us. We intend to finance both acquisitions and major projects in a manner that maintains our A credit. As we highlighted previously, we will highlight the Ravenswood acquisition by issuing new debt and equity in a manner that allows us to maintain our current balance sheet capitalization structure of approximately 60% debt and preferreds and 40% equity.

TransCanada's existing free cash flow and debt capacity is sufficient to meet the committed $3 billion annual green field spending profile we have in place for 2008 and 2009. As we grow our assets, we also grow our operating cash flows and our debt capacity. As our green field project portfolio grows beyond the current $3 billion per year, we have a number of options to fund our capital program including asset monetization. We have divested a number of blue chip matured gas pipelines to our TC pipelines LP and that remains a very attractive option for both TransCanada and the LP. In this way we can maximize the strategic and operational advantages of our pipeline portfolio while continuing to grow our asset base for long term benefit of our shareholders. That concludes my prepared remarks. Now I will turn it back to David for the question-and-answer period.

Thanks very much, 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 have completed at that, we will then turn the call over to the media. With that, I will turn it back to the conference coordinator.

Thank you. (OPERATOR INSTRUCTIONS). Our first question is from Linda Ezergailis from TD Newcrest. Please go ahead.

Thank you. It is great to see that Edson's contributing so much in the quarter. But I guess as you can appreciate one of our challenges is visibility going forward. Can you just give us a sense of what your outlook is for your natural gas storage business for the balance of 2008 including any seasonality you might expect and then how much in terms of contracting you have locked in for 2009?

Sure. Linda, as you know, as you referenced there, there is a fair bit of seasonality in this business, particularly on the business that we -- our proprietary business where we buy and we inject our own gas. We, for earnings purposes, we recognize those earnings only when the gas comes out and obviously the gas is usually coming out during Q1 and Q4. So I think it is very fair to expect that generally there will definitely be a bias in earnings in Q4 and even more particularly in Q1. That being said, just where the basis went in the market gave us an opportunity to profitably accelerate the removal of gas that would have probably come out later in the year otherwise. So I think, I think you what I would say is generally a fair rule of thumb that we are, we probably experience relatively close to around half of the contribution we would expect to get from the storage business in Q1 this year.

Half of the full year?

Yes.

And what proportion in Q1 was your prop business versus your I guess fee for service business?

I am going to say it was probably -- 30. Do you have that number right in front of you?

Yes, from our storage business, our proprietary gas was obviously majority of the storage business coming out of the Edson facility.

I think that just to answer your question, we are about 87%, 90% sold for '08 and we are around 60% and 35%, 40% for the next two succeeding years.

60% for '09 and 35, 40 for 2010. Is that calendar or gas seasons.

Calendar.

That's great and my follow up question, maybe we can move to another part of your business. It is good to see that the Governments option to elect not to refurbish the fourth unit at Bruce A has expired. Now at what point would you expect that they might turn their attention to negotiating a refurbishment program for the B units?

Well, there's still a fair number of years left in the life of those units. That being said, I would think it is something that will probably begin discussions some time in the next sort of three to four year range.

Would you expect to have some sort of an agreement structure similar to the A units?

I think we would require an agreement structured similar to the A units. In terms of we are certainly not going to take any merchant risk and we would certainly expect to see similar provisions with respect to risk sharing on capital costs and so forth.

Great. And what sort of probability would you assign as to not having those conversations or that sort of an outcome?

I think the fundamental attractiveness of the refurbishment of the B units is at any range of expected capital costs, the cost, the price of power coming out of refurbished B units in our view will be very significantly below any of the other competitive supply options for Ontario. So we, we think that there is a, we would be surprised if at some point in the relatively near future we were not engaging in those discussions.

Great. Thanks so much. Alex.

Thanks.

Our next question is from Bob Hastings with Canaccord Adams. Please go ahead, sir.

Hi. Thank you very much. Just on the gas pipeline you mentioned that there was some total increase and there's some volumes and decontracting shorter hauls. Can you give us a little more color what's going on there and what you look for going forward, particularly with, the some of the other supply auction that is are coming out and goal gas et cetera.

Start with the first question in terms of what's happening on the main line with respect to tolls. Year-over-year volumes are down, you know, probably in the, in that sort of 10% kind of range. That in addition to sort of market changes which is pushing gas in different directions the demand in California has been stronger and even in the Midwest on the northern border pipelines. So we have seen a reduction in flows on our main line system and if the cost of service tolling structure so the tolls have gone up. The map would probably take you to a number that looks like about a, you know, 20 or $0.25 increase in the toll. Offset by a fuel decrease by you know, $0.02, $0.03 something like that, sort of in the $0.20 kind of range is the overall increase on the main line.

Going forward, there's positive news around new discoveries, which could help offset that decline in volumes. And we would expect sort of I guess our views leveling off of production the western sedimentary basin if the other factor that impacts exports is in Alberta demand. As we know that continues to increase as well so decreasing volumes available for exports. So I guess this is -- it isn't something we expected, we expected the volumes to decline. The market will dictate though where those volumes actually go in the future. So if, you know, if the weather is cold in the northeast United States, it will continue to draw gas through our main line pipeline system because on the margin, it is one of the only conduits that is left to fill the pipeline demand tor gas demand on a peak day. On other days, the has will flow down our other pipeline systems into California or into the Northwest. So we monitor it on a continuous basis but those are some of the reasons that we have been very active in trying to attract new supply. Alberta British Columbia into our pipeline system in order to offset declines elsewhere.

So pricing signals worked, gas was low, we didn't see much expiration now starting to pick up a little bit.

Yep.

Now other thing is I wonder how that would play in some of the other pipeline developments that you are, that you are pushing for or suggesting.

I think it is, the key for producers is they want to get gas to market and the most, the largest increase in production in North America right now is the growth in production in the Rockies and there has been periods over the last couple of years where the price has disconnected from NYMEX pricing, we have seen differentials of $2, $3, $4 back to the Rockies. Obviously that's very difficult for producers that are trying to continue drilling programs so they want more capacity out of the Rockies. And they would like to I guess take their gas to the closest liquid market that they can, making the least possible commitments that they can as well. We don't know exactly which direction the gas or which direction the market will want to move so we have made proposals to move the gas both east and west. The eastern proposals, the first one goes from the Tahoe river basin to our northern border pipeline.

So it can basically fill some of that capacity that is left open by declining export volumes out of the western sedimentary basin then we have a pathfinder project which would go deeper into the Rockies basins in Colorado and Wyoming, and then further on to interconnect at Emerson, which is the connection of the main line to the great lake system, which would offer those producers several market options both in eastern Canada, the Midwest, storage in the midwest, and ultimately moving the gas through our system to maybe east coast where the prices are the highest. So those are the drivers behind the new projects, and obviously, if we can take the gas, the new gas that is being developed in North America and put it into existing pipe, that is the cheapest and lowest cost alternative for both us and the producers and if we can make that work obviously it is a good solution for declining volumes in the western sedimentary basin as well.

So the pipeline is going to become a growth area again?

I think that over the last couple of years we have seen the investment opportunities in the pipeline business grow. As you know, we are probably sitting right now with about $5 billion of projects under way and with projects like those Rockies projects and some of the potential expansion at Keystone, we see pretty healthy outlook for the next few years in terms of growth opportunities for the pipe business.

And I listened to the annual meeting. Is there some magnitude of ballpark range you could give for the Keystone new project that you are looking at?

I think it is you can just sort of look at you know, the distance on the map, how much you know, pipe we need to build. I think that the, as Hal mentioned at the annual meeting our current design that would look at a 36-inch pipe opposed to a 30-inch pipe so again a bit thicker pipe that's a little more extensive and we have got you know, 20 to 30% more distance to go. So, it would be a project that would be that sort of order of magnitude larger than the base Keystone project.

Okay. Thank you very much.

Thank you.

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

Thank you very much. Just continuing on that theme on Keystone. Is is more economic now in your mind to build a brand new pipe than it is to try and extend the existing or first Keystone line and also how does it compete or stack up against other proposals that would simply extend off of the current system opposed to building new pipe?

That was the first one is that the original keystone design was 435,000-barrels a day to Potoka and Wood River. We ultimately thought we could probably push about 3 or about 600,000 barrels a day through that system with added horsepower. Through our Cushing open season, we essentially moved to a level of contracting about 500,000 barrels a day a firm, and we're 100,000 barrels a day soft. So that pretty much fills that capacity and adding more horsepower if you will doesn't really economically give us anymore capacity. So the next logical answer is to twin the system in the most efficient way that we can. That's the design that you saw on the slide that Hal walked through at the beginning of the conference call. You can see where it does connect with the existing system at place called Steel City which is sort of the elbow going to Wood River and then further to Cushing we can share that piece of pipe so as part of the design that would be one of the advantages that we can bring to the table as we a segment of the pipe that is similar but that sort of leads to your second question in terms of competitive advantage and how it stacks up to others is when you're building new pipe, obviously at about $3 million in the current marketplace the shortest distance is going to gif you the lowest capital cost and while we see that, the competition is , adding to existing systems, there does require sort of new build right from the Gulf Coast, right through the system right to Alberta. So that distance is probably 20 or 30% longer than the distance we have got proposed directly from Hardesty. The directest route we can take from Hardesty through Gulf Coast, taking up the synergies as I said from Steel City to Cushing, But we try to go the least distance possible. And that's sort of I guess what I would say is our competitive advantage in the marketplace. Currently over existing systems.

I see. So your view is that, I mean just to get real specific here, that Enbridge, you're not competing just against the Enbridge Exxon line that really is less that half the distance of the pipeline you are building. You are thinking you are competing against all the back back to Alberta.

I don't speak to their exact plans but our conversations with the refining and producing community, that's the sense we get is that they're mindful they need to move in increments of probably 500,000 barrels a day up to probably a number of 2 to 3 million-barrels a day over the next say four or five years and they recognize that ultimately you have to build new pipe right from A to B to move that incremental volume. So that is the sense that we have is the incumbent system has to go a lot further distance to get to the gulf coast.

And you are hopeful that you can get your hurdle returns right off the hop when you build that.

Yes. Obviously we move, we try to secure a sufficient barrels in open season that would underpin base economics for that pipeline.

Okay. Thanks very much. I will move on.

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

You mentioned on the Ravenswood financing you would like existing similar capital structure, and you also made the statement that you want to maintain the A credit rating, can you comment on discussions you have had with the other ratings agencies, S&P is out of the way here. But what have those discussions been and what would you do if they asked you for a higher equity component?

Sure. Well, we have on going discussions with the rating agencies. Obviously we have been having lots of discussions with them around Ravenswood and significant work is being done by the rating agencies to understand Ravenswood and to understand the capacity market and all the factors that have implications to that. I think we are comfortable that the proposal we have to maintain our capital structure is sufficient to maintain our A credit ratings, and I would say overall we were very pleased with S&P and their ability to reaffirm our rating and their confidence in management and in our track record to maintain our rating and to do what we said we will do and to issue the necessary equity.

Okay. But if the other agencies ask you to put more equity in, what wins the day here?

Ultimately we will do what is necessary to maintain our credit rating. We do have other options, other than common equity as you are aware that get us equity. We have options as you saw us do last year in the hybrid market which got us 50% equity treatment. The preferred share market in Canada is open to us. That market has mostly been a bank market recently and there's certainly demand for industrial, industrial issuer to step in. So there are a number of options, but I would say that we are committed to the A credit rating and as we have said many times, we will do what is necessary to maintain it.

And just last here, do you expect a decision from the other ratings agencies prior to your equity, similar to the movement from S&P.

I think it is possible, and we would certainly hope that that is the case.

Okay. Great. Thanks.

Thanks, Robert.

Our next question is from Andrew Kuske from Credit Suisse. Please go ahead, sir.

Thank you, good afternoon. If we can just get a little bit more sense on directionally where you want your power business to be, if we think about the Ravenswood deal, there is some logic on the northeast and where you have already had exposure, but then when we look at potentially a project in Arizona, and some of the past initiatives we have in the Pac Northwest and I am just curious as to where you look your focus to be in the near term and over say a three to five year time frame.

Hal I will start and then I will let Alex add to it. First we have to look for markets that have attractive market fundamentals. In other words, where we can either acquire things or build things under some kind of an economic model that makes sense. And there isn't just one economic model. You see many different ones, the energy only markets of Alberta are much different than the energy and capacity markets of New York and New England. I would describe Ontario as the ultimate capacity market where they just pay you for the capacity, we don't take any energy cost or revenue exposure at all on projects like Portlands and Halton Hills. So first of all we screen markets by looking for good supply-demand fundamentals. There are some markets in North America where the supply demand fundamentals aren't very good.

There's other markets where perhaps state controlled entities control the market and there's no reasonable opportunity for a corporate player to enter and there's other markets where the preponderance of very low cost coal fire generation is so overwhelming that even in the greenhouse gas era we don't think there will be a lot of opportunity for new entrants. So if we find a market that has attractive supply demand fundamentals we ask the question and what competitive advantage might we have in that market. If it is a market that has got huge barrier of entry we will go somewhere else. If it's got a lot of other players that one way or another constitute a barrier to entry then we probably pounce on that market.

The Southwest U.S. is very attractive to us fundamentally. We are very, very cautious. I think you would see us continue to be very cautious on California given some of the history there. But those markets that are near California are attractive to us and certainly the Nevada and Arizona markets are ones where we think we could build a substantial business over time. I would sort of describe the size of our current position in Alberta as indicative of the size of position we would like to have in a market. If we are unable to get an asset base that is worth several billion dollars in any particular market, it is not going to be very appealing to us.

Alex, do you have anything to add to that?

No I think that covered it quite well. I guess the only other comment I would say is that as you have seen, I mean, we have really focused over the last several years on, we basically describe them as two markets although I appreciate the eastern business the central Canada, Quebec, northeast U.S. businesses, obviously there's a number of markets, but we certainly think we have been consistent in that market, and one issue with Alberta, we obviously have a very significant position in Alberta, and I would argue that absent significant growth of intertie connection with the Northwest U.S. markets, it is hard to see us really significantly increase our percentage ownership in that market over the next years. So we have been as you mentioned and as Hal referred to, we have been focusing for several years on the U.S. southwest, and particularly excluding California, but really being focused on Arizona and Nevada. And we really, we really like the fundamentals of that market and we certainly wouldn't consider our with foray with Coolidge as the end of our aspirations there. We think there's an opportunity to build quite a significant business over a number of years.

Then just when you look at markets in general, do you have a preference and inclination towards really a capacity driven market on really a rate based concept, or do you really want to have more pure merchant exposure in markets that have favorable supply-demand fundamentals?

Certainly from our perspective on what I would call the new build side of the business, the green field side of the business, the vast majority of that business is obviously being pursued under a sort of tolling TPA type arrangement that in fact as you would know, the vast majority of the capital expenditures and power over the last several years have been in that kind of business, but we will always keep our eyes open for merchant opportunities where we think those assets have a very strategic fence to them and I think an example of that would be the coal PTAs in Alberta, the hydro in New England and we obviously feel that that way about Ravenswood and certainly once we get those assets in our portfolio, we, even if they are a merchant usually go down a path quite quickly putting some revenue stability around those assets by a portfolio of off take agreements and we will continue to do that.

All right. Thank you.

Okay thanks, Andrew.

Thank you. Our next question is Daniel Shteyn of Desjardins Securities. Please go ahead, sir.

Yes. Hello, everyone. I guess I would like to ask a question with regards to the route of the Keystone future expansion, future opportunity. I guess what I don't understand is why were you not able to take advantage of the existing Keystone projects, rights of way, even should you wish to have laid new pipe as opposed to simply extending and expanding the existing system?

We definitely could have done that if we followed the existing route. So one advantage is if you have been in the right of way before you still have to go through the permitting process, it really is one of efficiency, is one of our largest costs of constructing these is the steel in the pipe itself and per mile construction, as I mentioned, we are looking at about $3 million a mile currently. So if we can shave off 100 miles by going the direct route, that's $300 million. Those kinds of efficiencies more than offset the synergies you get by being in the same right of way. It does increase our work load in terms of gaining right of way but if you look at the direction of that line we try to stay away from areas where right of way will be difficult and that line is on there is really just a straight line but it will have wiggles and we will move around sensitive areas. But the real driver is to be competitive you need to have the lowest possible cost that you can and that is having the most direct route you possibly can have.

Daniel, it's Hal. I'd add to that that if you look at the map, the logical route to get from Alberta to Houston is something like the expansion route that we are proposing. The route that we followed with the original Keystone was a very unusual route, and was only followed because we had the ability to convert that gas pipeline to get from Alberta to Winnipeg at a very, very low cost. Now, we would be quite interested if the possibility came up in the future of converting another line along that same route. I would point out that we have two 34-inch lines there, one which we are converting and one which remains. In addition to those two 34s, we have five other pipelines that are larger diameters that are probably more than adequate to carry the amount of gas we have to move from Alberta to Winnipeg on the main line.

So we do have optionality there for the future, but it was our assessment that given the current demand for oil transport service, from Alberta to the Gulf Coast, we could not realistically hope to get that other 34-inch line converted in time to meet the market demand. So rather than see that market demand go by, we came up with a new build alternative. As Russ said, if you can save $300 million for example by adopting the most direct possible route, that is to the benefit of both TransCanada and also to our shippers in the form of lower tolls. So that's the logic we have followed in selecting this route. The last comment I would make is many people have asked me why we don't just move the gas over to a new vic on the gas side, and send it down the same pipeline, and the reality is these pipelines are designed to run very close to full capacity. That is the way you make them as economic as possible, and just using the Northern Gas as an analogy you couldn't run all of that gas down one pipeline, you would need two in any event and that of course is the same on Keystone. There's no realistic way of moving more than 590,000-barrels a day through Keystone phase I. Anything beyond that you are putting new pipe in the ground anyway.

Okay. Well, conversion of existing pipe was my follow up question. Thank you for read answering that and reading my mind in advance. For my follow up question, I would like to talk quickly about the Alberta power market. Now, the Alberta emission intensity rules are now reality, and I was actually interested to see that you managed to squeeze out margin expansion on your power sales in Alberta. Presuming, so that presumably implies that you have been able to pass through the payments you must now make on TransAl BPAs that you hold in the form of higher market prices. So is your expectation essentially going forward in the near term and then the long term that you will be, that higher power prices in the market will reflect the higher cost you are now faced with on those BPAs due to both provincial and federal intensity limits.

I think, obviously we have seen prices expand in Alberta a little bit. I think there's probably some debate as to how much of that is market fundamentals and how much is passing through of CO2 costs. I think what I would say, our general view on that is particularly with our coal entitlements, I mean we definitely are pursuing the strategy and we believe the other coal owners are pursuing a similar strategy of passing these costs through, dollar for dollar, at times when coal is on the margin in Alberta, which is, and in those periods when coal isn't on the margin, the gas producers will be passing through their CO2 cost but obviously on a per megawatt hour basis, they obviously are incurring less costs. So our view has always been that at a minimum we are going to collect a relatively significant amount of that cost back in Alberta. And we would expect that to continue.

Okay. Thank you.

Okay.

Thank you. Our next question is from Faisel Khan of Citigroup. Please go ahead, sir.

Good afternoon.

Hi.

In your prepared remarks toward the end you mentioned the possibility of being able to drop additional pipeline assets down into your MLP. Could that be used as a source of equity for your acquisition of Ravenswood?

It could be used as a source of equity going forward, it would take some time to accomplish those transactions. So our current intention is to finance ravenswood with new equity as we have indicated. Going forward though, and funding our green field portfolio, we do not intend to issue additional equity. We intend to focus on our portfolio optimization and that is around potentially dropping down assets that include partnering on certain assets or outright sale of certain assets that are matured in our portfolio where we think there's high value.

Okay.

And from the MLP perspective, we do have a vehicle there and we would look at our asset portfolio, we would look at potential step transactions as we, as we move assets potentially into that vehicle over time similar to the way we use our drip program to fund what are longer dated capital spend programs for some of these large greenfield projects.

Okay. On your Eastern Power results, the up tick, a lot of that came from TC Hydro and higher realized power prices. Can you give us a little more detail on how much incremental generation you were able to produce above kind of your plans at TC Hydro and the sustainability of that going forward?

I don't have that in front of me. Glenn, do you have that?

I would say on a year-over-year basis, the increased volumes and prices from the TC Hydro assets probably in the range of a couple of cents per share and then as far as whether this will continue going forward, I will leave that one to Alex.

I think obviously, Q2 it would be fair to presume is eastern business is going to have a pretty robust quarter. There is a very significant amount of water trapped behind those dams in the form of snow, but it's starting melt, so I would expect you would see that. We have also seen relatively significant run up in power prices in the region over the last little while. In some cases we are probably in the range of $10 or $15 a megawatt hour higher than we probably were three or four months ago.

In terms of the materials that have been procured for Keystone, how much of the pipe and steel and piping equipment has been procured and locked in?

For phase one that we are starting construction on? Yes, please.

I think we are probably somewhere around 60% in sort of the order of magnitude of $5.2 billion I think was our estimate that's out in the marketplace right now. So about $3 billion of that between the pipe and material and contractors has been locked in.

But as far as pipe and pumping equipment, we would have procured most of it. Pumping equipment, we have all of that, and most of the pipe. There's some amount of price risk on some of the pipe, but a very small amount of price exposure left on pipe.

Okay. Great. Thanks for the time, guys.

Okay. Thanks.

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

Thank you. I would like to go to Ravenswood, Alex, and your thoughts about once we get your asset in control kind of creating a contract portfolio mix, that makes sense to you, trimming out but wasn't that the essence of why National Grid sold Ravenswood? They couldn't find a long-term contract portfolio mix because they have given that choice either you do or you sell?

Well, I think, yes I think it was even more extreme than that. I mean certainly how I understood it was there were, they were given a very strong incentive from their regulator, in fact a penalty to the extent that they didn't divest of Ravenswood and I do think, if you think about it from their perspective, they would be looking at a long-term very long term contract, whereas we are talking about pursuing a portfolio of contracts, some long, some short and I don't think that would have satisfied their regulator.

So the mix you think you can get from New York, can you paint a picture of what you think you might get, I mean one, three, five mix something like that.

Yes, I would say I guess it is pretty early days for that, but I mean certainly there are buyers out in this market and there, we think we will be able to pursue a portfolio of sales not unlike the kind of sales you see in our western or eastern business.

Okay. And with respect to replacement cost which sounds like you have a very good deal in replacement costs, you never earn that replacement cost when you are earning on existing capacity in the regulated market, which is why there's mild dilution here. Is it fair to say that the delta to your goodwill, which you will recognize over time because you have the best location to put in new capital, that will have to obviously attract a fair return at that new capital level, it will take a while to chew up your existing premium you're paying over the previous guy's ownership of a semiregulated asset.

First of all, Sam, it is Hal. Your statement is true with respect to the Canadian main line for example wherein that regulated world, the replacement line of the main line would be maybe $20 billion compared to the $8 billion of rate base that we don't have the opportunity to earn on the real economic value. In other words, the replacement cost of the main line. But in the case of Ravenswood I don't think it is really correct to describe this as a regulated asset. And this is effectively a merchant asset in a partial capacity market and we will sale both capacity and energy at fair market value, not at any kind of regulated value so we think what will the fair market value for capacity be?

It will be driven by the cost of new capacity in a market that generally needs more capacity. If the market never needed any new capacity I could understand maybe we couldn't get fair market value for our capacity or certainly wouldn't get a premium to what we pay. But in this particular case I think we would foresee a future in which additional capacity in New York will cost quite a bit more than what we paid for Ravenswood and we think that a typical marginal price setting market, those new plants will set the marginal price of both capacity and energy.

And Sam, it is Alex. In fact, the way the various orders in the New York capacity market work and the design of it, capacity is in fact, the price of capacity is ultimately derived from the cost of new entry, not the embedded cost of existing generators and I think I said this earlier, but we made an assumption we are going to get something less than the true cost of new entry, somewhere in the range of 75% of that.

I see. A follow up just with Ravenswood, obviously S&P used the qualitative term risk year asset relative to your mix and you have already given us I guess the consolidated 60/40 debt equity frame work target. If this was to be a stand alone asset, which it won't, would it be more like 50/50 in the eyes of S&P and/or yourselves and what do you think is appropriate for this quasi-regulated how ever you want to call it --

We look at our power business as a portfolio of assets, and I think we can reasonably argue that assets like Becancour and Portland and Halton that are covered by 20 year no commodity price risk contracts many of your competitors would be financing those with for example 75% debt. And when we acquired our Alberta coal PPAs there were people that observed this as quite a bit riskier than our existing business, and I think that we've demonstrated that the risk-reward character of our Alberta coal PPA business is good not bad and has served our shareholders well.

Similarly when we got into Bruce, there was quite a bit of concern that it is a riskier thing for TransCanada to do and we felt that we could manage that risk and I think that the earnings that we have been able to generate from Bruce, even though occasionally they have disappointed us as well as they have disappointed you, at all times they have been economically attractive, and have been a good return on the investment we made there. So, every asset has its own quirks and we do a loft work on these things before we buy them. We are comfortable with Ravenswood as an asset that is going to fit very well with our particular expertise and capabilities in the northeast. It gives us many levers that we can pull to generate earnings for TransCanada. I really don't know how you would finance Ravenswood as a stand alone asset, a single plant asset like that trying to maintain an A grade credit would have to have an extremely thick equity component if it was a single, a single purpose company. So the fact is that by making a part of a portfolio, we are not subsidizing it with other assets, it is just that restructure our capital over the whole portfolio. We have some very stable assets and some that have a little more volatility. In almost every case, the one with more volatility that also give us the significant earnings upside which we think may not be important to the credit agencies but it is to the shareholders.

Thanks, Alex.

Thanks, Sam.

Thank you, our next question is from Mark Caruso from Millennium Partners.

I wanted to circle back on the financing side you had mentioned the 60/40 split and the S&P release they were saying a considerable amount of equity. I just wanted to circle back on that as well as I am here in the U.S. And you are saying the preferred market is still open in Canada but how is the hybrid market because I have heard here in the States it isn't as strong. i just wanted to get your thoughts on that as well.

Yes. I think the hybrid market has certainly weakened off since we issued last October and the agencies are looking for a different language or stronger language than what we have seen in the past. I think we are starting to see the market turn around a little bit, certainly on the debt side in the U.S. we are seeing transactions get done in the oversubscribed several times oversubscribed. There's a lot of money sitting on the sidelines right now just because of the market volatility. So I think we will start to see some of those markets turn around and then as I say, we are also looking at the LT markets which we can do tranches of both $250 million on a consolidated basis, that is considered equity for TransCanada when we do an issue like that. We certainly have assets which we would be able to send in over time to that vehicle. So we have lots of flexibility at TransCanada on both the debt and the alternatives to equity.

As far as that debt goes, do you, the market I guess is strong enough to take a full 60 or do you think you will be able to split that 60 between straight debt and some of the sort of hybrid components?

We don't think that any problem placing significant debt in the U.S. market particularly. So we don't see that we would need on purely on the debt side of the financing to do anything other than we would normally do with term debt and I would say that we will have a significant bridge facility in place, which will cover the entire acquisition amount and we will have a debt tranch to it such that we will have flexibility for a period of time, at least one year in which to go to the market from a term debt perspective. So we have lots of flexibility in order to watch the market. And as you've seen in the past, our issue last October take advantage of windows in the market to get the best pricing. We are seeing pricing tightening up right now and we continue to --

Great. Thank you very much.

Thanks, Mark.

Thank you. Our next question is from Brian Berge from Legal & General Investors. Please go ahead.

Questions already been answered. Thanks.

Thank you.

Next question is from Harry Mateer from Lehman Brothers. Please go ahead.

Hi, guys. I was just wondering if we strip out Ravenswood from your financing plans this year and just look at your CapEx budget, what are you thinking right in terms of financing needs just for capital spending ex-Ravenswood, are you going to need something from the markets be it asset drop downs or debt or equity.

Right now based on the committed portfolio, we have about $3 billion a year we can spend and we are right on top of that number without Ravenswood right now. So there really isn't anything we would need to do. When we move beyond the $3 billion and look at incremental spend for new green field projects, first of all, when we announce things, those capital costs are not immediate, they're out in the future, sometimes two or three years out so you wouldn't have significant additional short term costs, and then as we look at that portfolio, going out forward, that is then when we look at asset monetizations and other vehicles in order to fund that long-term growth.

And at Keystone are you planning to finance that at the project level?

No. We are not. We are looking initially to a bank facility that would be supported by TransCanada.

Okay. The bank facility, would it be for Keystone and 50/50 TransCanada, Conoco.

It would be for Keystone and we are working with Conoco as to the best way to approach the debt market for that particular piece of credit.

Okay. And then, in terms of asset monetizations down to the MLP. In terms of size, what you see out there right now, presumably the MLP equity market will improve at some point but it still remains a little bit weak but the size of potential drop downs in a given year, what are you thinking about?

I think we can initially look at something in that, 250 to $300 million range. The market should be able to accept that in one tranch, and then whether or not you can do more than one in a year would depend on market conditions going forward.

Okay. Thanks very much.

Thank you.

Thank you. Our next question is from Steven from first energy. Please go ahead,

Good afternoon. Just a couple of questions on Keystone. Looking at what is the cost for the total line fill and capitalized interest and are those part of the $3 billion in locked-in costs?

There really, at the end of the day there isn't line fill per se. We filled the pipeline with the initial barrels but the first batch is the way I kind of look at it, those aren't cost that is are borne by the pipeline, the shipper supply, if you want to call it that, that first batch probably takes somewhere in the neighborhood of 60 to 90 days to move through the pipe, but then it comes out the other end and the shipper gets their crude back to sell and from that point the time frame can move from Alberta to Cushing in that 25 kind of day range. So, that is a carrying cost that the producers have. We don't have any line fill per se. And then I didn't hear your second question.

The capitalized interest for Keystone.

Yes, capitalized interest or AFTDC under construction if you will is a cost that becomes part of the rate base which goes into the calculation of the tolls that we charge the shippers.

And how much are you estimating that will be?

That's not a number that we share publicly. But I mean you can give your best shot using 40 debt equity structure and some assumption around what interest costs are, and in our construction spend over the construction period, it sort of ramps up. But we haven't talked about that number would be. That would give you a range.

But Steven you can think about one of the good things about Keystone is that it is roughly to 20 month construction period, in '08 and '09, so things are happening fairly quickly relative to say McKenzie Dali pipeline, where you might be accumulating interest on development costs for ten years.

Right. Great. Thank you.

Thank you. Our next question is from Matthew Akman from Aquarius. Please go ahead, sir.

Thank you. I just wanted to clarify your intention on asset sales because there has been a lot of talk on it in the conference call and you have done a good job building a portfolio of asset that is seem to fit very well within your stated strategy, many frankly better than Ravenswood, so is it your intention to sell a lot of your, or significant amounts of existing power or pipeline assets to pay for Ravenswood?

I would ask first whether that's a statement about fact or an opinion about Ravenswood. We think Ravenswood fits very well, otherwise we couldn't have bought it. We have assets like the GTM system that had some significant value creation opportunities after we acquired it, and also had some real strategic value in TransCanada long term. So part of the attraction of our MLP is that it allows us to recoup significant capital investments while maintaining strategic control over the asset, and so on a case like GTM, we can accomplish that objective without having all of our e money tied up in it. In the case of GTM for example we have successfully gotten through a difficult rate case and added value to the pipeline system by doing that.

So we don't have a whole lot of pipelines that we are contemplating rolling into the right now, but that would be one, an example not of a pipeline we intend to roll in but I am trying to give you some sense of the kind of pipes we would look at that we could roll in. Obviously any of our mature pipelines would be candidates for that sort of thing meant our entire interest in northern border which we rate is held in the MLP and our interest in northern border is held indirectly as a result of our 32% ownership in the MLP. So that's the third variable. If we did those kinds of f deals you know, what would our ownership level in the MLP be and could we insure ourselves we would maintain control over the asset one way or another in terms of what happens to it in the future.

So most of our focus I think I can say to you would be on, on U.S. pipes that would fit well from an investor point of view from the MLP. On the power side of things, again, my own criteria for rolling assets into MLPs or other partnership structures or selling them outright revolves around fully developed value. If we have done everything we can to fully develop the value of an asset and it is a good point in the market cycle then we would consider selling it. If the asset has a lot of optionality or a lot of opportunity for us to add value in the future, then we probably wouldn't sell it. So it is kind of in that transition from a rising star asset to a fully developed cash cow, that's why we think about divesting assets whether they're pipe or power.

Okay. Thanks for that answer, Hal.

Thanks, Matthew.

Thank you. Our next question is from Daniel Shteyn from Desjardins securities. Please go ahead, sir.

Thank you. So my questions are more to do now with your organic growth projects. There has been a whole whack of pipeline projects announced recently by including the Sunstone and the Pathfinder project that are I guess still I little bit in the conceptual stage because there has been no new capital or haven't been capital cost estimates announced. So just as an order of magnitude, how big do you believe those capital expenditures could possibly be in the future should the open seasons actually be successful? And what would be the timing?

I think the rockies look -- start with market demand first in terms of how much capacity will be built up. It is our view that we will need to, the Rockies is sort of forecast to grow by between 1.5 and 3 billion cubic feet a day over the next say five to seven years. Our view is that they will need one new pipe with the capacity of about 1 billion cubic feet a day by somewhere in the 2011-12 range to make sure they don't have dislocation and differentials. If things continue another one sort of in that 2013-14 range in that same sort of size of about a billion feet a day. The cost of constructing a pipeline. All of these pipelines are say between 700 and 1,000 miles. I think I gave you a rough rule of thumb somewhere around $3 million a mile. So it is between 2 and $3 billion for a billion cubic feet a day pipeline to one of these markets and I said I believe that only one of these pipelines will probably be built in the sort of 2011-12 range and maybe another one in the 2013-14 range.

Okay. And of the kind of the ball park of pipe construction cost estimate you have provided, that's I believe you were referring to an oil pipeline there. Are the pipeline costs for natural gas and oil pretty much the same?

They're pretty much the same. We are talking about the pipe running from 36 to 42-inch similar to what we are using for Keystone pipeline. It is very similar cost and I know your lay costs are very similar. So there's some differences but I think you can still use the rough rule of thumb for both kinds of pipeline.

Okay. And my other question has to do with everybody's favorite plant, Ravenswood, just wondering if you were able to provide a sense of what sort of sparks spreads Ravenswood can, has, is, and will be able to generate for your account going forward and I know this could be a competitive issue, so a range is fine or a historical amount of color is fine as well.

Yes, I mean that obviously is something that we are concerned about. I guess what I would say is that the heat rates of the units there are kind of a matter of record combined cycle plan is about 7300, 7400, and the big oil, big gas oil boilers are kind of in the range of the high 9,000s, mid to high 9,000s and I mean our view is that the market heat rates in that market are probably in the range of 10,000. But obviously there's lots of, lots of things in the winter and in the summer so it is pretty hard for us to kind of be specific about that.

And Daniel I would add of the revenue stream at ravenswood a significant part of it is capacity payments and particularly when you look at the 460 megawatts of gas-fired peakers those would have heat rates in the 17,000 range. They hardly ever run 1 or 2% of the time historically, but they do generate significant capacity payment revenue, and it is a doubling up of revenue that occurs when you are actually running the plant, you do continue to get capacity payments and in addition, you get the spark spread energy payment if there is a positive spark spread which of course in the gas of the gas turbines there isn't, so that's why they don't run. Those are the different components I think that drive it but I wanted to emphasize in addition to what Alex said that the capacity revenue is a percent of the total.

Sure. And capacity payments up a little more visibility in terms of being public. But, to come back to my question which was regarding a sort of a range of spark spreads then even given the very different nature of the different units in that plant there's still some sort of a consolidated range of numbers that maybe you can talk about.

Well, the best way for us to describe it to you is in terms of the heat rates that Alex described because to go from there to sparks spread you have to bring into account price of gas and price of power and the conversion, so we are prepared to tell you roughly what these units convert gas or oil into electricity at, but our own estimates of power price and gas price you would have those just as well as we would.

All right. Thanks.

Okay.

Thank you. There are no more questions registered at this time. I will now turn meeting back over to Mr. Moneta. Please go ahead sir. Please go ahead, sir.

Okay, just to turn it, conference coordinator turn it back to you, just in case, we would like to open it to the media now. If there are media questions we would be happy to take them.

Certainly. (OPERATOR INSTRUCTIONS). Our first question is from Ian McKinnon from the Bloomberg News. Please go ahead.

Two very short and hopefully easy questions. $3 million you have being saying, Canadian or U.S. dollars?

They're about the same today.

Can you give me an estimate in terms of length in terms of how long Keystone expansion will be or how much greater or shorter than Keystone 1?

I think it is about if I remember correctly it is about 20% longer somewhere in that kind of range.

Okay. Thanks so much .

Thank you.

Our next question is from Gordon Jaremko from the Edmonton Journal. Please go ahead, sir.

Question in the same area, last time I heard you talk about this or Hal talk about this, he had some estimates about what the advantage to oil producers would be of getting oil production all the way down to the U.S. Gulf Coast. It seems to me you were talking about reducing the discount by about 50% more. Is that still true, A, and B, it seems to me you had an estimate of even how much it will cost to get there which was around $6 a barrel. What are those current sort of projections?

Gordon, one long running debate in the oil industry here in Calgary is whether the discount is best expressed in so many dollars per barrel or as a percentage of the WTI price. And there's certain elements of both. I remember back when crude oil prices were $20. At that point a $10 discount was seen as horrific. At $100 we have seen discounts in the order of 40 to $60. At times the discount has exceeded the collar of the barrel in Alberta. So we do clearly, all we look at is what does a comparable barrel of crude oil trade for in the U.S. Gulf Coast today and Mexican Mayan and certain other Venezuela streams would be seen as the most comparable, and you can do the few quality adjustments from there to figure what you might be able to sell Alberta crude it for if you could get it down there and then offsetting that of course is the cost of moving it and that cost of moving it has got a couple of components. One is the toll that we charge and the other is the cost of diluent, and what do you have to pay for diluent in Alberta versus what you can resell it for once you get into the Gulf Coast. The real advantage to producers in going to the Gulf Coast is that there's huge liquidity in the market for both the bitumen component and the diluent component, whereas at various markets along the way, whether it is in Minnesota or Chicago or Cushing or whatever, Wood River, there's not that same liquidity in the market.

So it is really the ability to connect Alberta directly to a very large and liquid market, that is where the real benefit to all Alberta producers comes from this kind of a project, and I don't want to be speculating on what that might as an impact on the differential. We build and supply the pipeline service and it is the commercial people in the oil companies that are really the the experts as to where differentials are likely to go or probably more correctly what range differentials they're likely to be in the years ahead. All I can tell you is that when you do add significant capacity that interconnects a very liquid market with a somewhat constrained supply base, that's very good news for all of the producers in the supply basin.

You still estimate $6 a barrel?

As far as the tariff?

Yes.

No, we are a little more than that but directionally you are in the ball park there.

Okay. What's your estimate of how much added pipeline capacity in total the oil sands industry is going to need say by the time you would build this one?

The best place to go for information on that is probably Cal and look at Cap's forecast of increased production out of the oil sands. I don't know if you recall those numbers offhand.

I think this pretty much, what assuming that the projects progress along the schedule of the Cap forecast, we would be constrained somewhere around 2010, 2011 that's when we are proposed to bring this on. About 500,000 barrels a day and then what we are looking at probably is another 500,000 barrels a day every couple of years after that. I think the current projection is about 2 million barrels a day of incremental production coming out of the oil sands, our base Keystone project picks up about 600,000 barrels of that and Enbridge picks up an equivalent amount. About a million barrels over the next say five years. If we build another project equivalent to Keystone, the next couple of years after Keystone, there's room for another one in that sort of 2014-15 range as long as production continues to grow along with the current forecast.

So you don't necessarily see yourself as in competition with Enbridge then.

No, we don't like to characterize it that way. We think we are both doing the best job we can to come forward with projects that are appealing to the producers. As long as production continues to grow, both companies will be winning their fair share of business. We want of course to win more than we don't win and we will work hard to come up with a compelling value proposition but it is not an either or. They are continuing to add significant capacity to their system which you know, mostly goes through Chicago and heads in that direction. And we keep bringing forward expansions or variations on the Keystone theme and I think those are both pretty interesting options it just depends to which market does the producer want to go?

When we came up with the Keystone routing and the Keystone destinations, we ruled out quickly building a pipeline to serve Chicago market because Enbridge does that very well, and they have a competitive advantage there, so we thought about what other markets could we head for and where might we be able to configure a pipeline that would giver us competitive advantage and we think Keystone has got that. So that is, it will be interesting now to see how two big things, how is production going to increase at the oil sands, will it increase more or less rapidly, we know there's market demand for it, and the second question is to which markets will that production flow, including possibly the Pacific waterborne market where people do continue to propose pipelines through BC and to the water ports on the West Coast. So we are not into that game. We are very focused on the part of the United States that Keystone serves and that our expansion project would serve, namely the Gulf Coast. Thanks, Gordon.

Thank you. Our next question is from [Hung Yung Lee]. From Dow Jones. Please go ahead, sir.

Hi. I just wanted to clarify where you said the Keystone expansion down to the Gulf Coast would be 20% longer. You said earlier on also at the savings of pipelines by taking a more direct route. So I don't know if I am missing something there. How can you have a pipeline savings?

I think that there's two different questions, one was how we compare to other alternatives that haven be proposed to get to the Gulf Coast and one of those is to basically follow the existing Enbridge line and then from a place called Patoka extend through to Texas. It is kind of a round about route that kind off leaves Alberta if you will goes past Chicago into the Gulf Coast.

Right.

And our route is more direct basically from Calgary if you will to Houston if you think of that analogy. That's the direct routing that is less the distance. So that was the first comparison. The second question was a comparison to our existing Keystone build that only goes to Cushing, Oklahoma it kind of takes that job as to how you go from Alberta to Winnipeg and then from Winnipeg to Cushing, Oklahoma and then our new pipe will go from essentially from Alberta past Cushing, Oklahoma right through to the Gulf Coast. That's where the distance is about 20% greater than the existing Keystone.

Right. So you are saying with this extra distance you said that the cost will also increase by order of magnitude. That $3 million a mile number. But if you are looking at a 20% expansion on top of that the cost is at least $1 billion more than the 5.2 that you have for keystone.

Again, use a number, it is going to be that order of magnitude, 20 to 30%, 20 to 30% more steel, 20 to 30% more lay costs, 20 to 30% more expenses than the original Keystone build.

Sure. Okay. Just one final question is this new pipeline you are look at 2011 start for it?

We don't know when that will start up, we haven't even ventured into an open season yet.

Right.

We are in the process of scoping the route, the terms and conditions to ship the crude with both producers and refiners, so there's a number of things yet to be done and once we get to the open season and we are confident we will be announcing sort of the in service date would be for that project.

It Is Hal here. I would like to clarify one thing. First of all please refer to slide number eight in the set of slides, and you will see that the original Keystone follows a bit of a circuitous route and I think one of the answers to your question is the original Keystone pipe makes use of a bunch of pipe that's already there, it is the old gas pipe that we converted. That's one of the reasons why it is hard to compare the length of the two because the conversion cost on that existing pipe was very, very cheap compared to the cost of building new. The second is that you made the comment that the new Keystone would be an order of magnitude more expensive than the other one. That's not correct. It is not anywhere near an order of magnitude. It is a modest percentage more. It is a little more per while because it is 36 rather than 30, means the amount of steel cost goes up but I just wanted to make sure we didn't leave you with the impression that it is an order of magnitude, i.e., ten times the expense. That's not the case.

Okay. Great. When do you plan to do an open season on that expansion sorry.

if all of those come together we hope in the next month or two to announce an open season process.

Great. Thanks very much.

Thank you.

Thank you. The next question is from Louis Shammy from Zimmer Lucas, please go ahead.

Hi everyone. My question was regarding getting oil from Cushing to the Gulf Coast. Is there any possibilities for a potential pipeline to just a smaller scale than this Keystone expansion where you take the direct route from Cushing to the Gulf Coast?

Do you mean converting an existing line?

Either converting an existing line or building something new.

Well, we would build something new, that would be our plan from Cushing to Port Arthur would be a new pipeline that we would build. We have looked at other pipes and generally they're not big enough or they don't go to the right place or --

Getting to the Gulf Coast at least from our perspective from Cushing was to get critical mass to move from Cushing to the Gulf Coast and right now, our deliveries off the base Keystone system at Cushing are basically off spoken for by refiners in the Cushing area. So there really aren't a lot of barrels that you can convert south, so if you build a pipeline if you go south, take a volume say 300,000 barrels a day, you need to put some volume in. And then when you look at sort of filling the pipe at the top end you made the project economic, you got to come back to Alberta for 300,000 barrels a day, it doesn't, it is not an economic proposition to come back for that small of a volume back to Alberta right to the Gulf Coast. Your toll is more expensive than the other alternatives in the marketplace. So we looked a lot at, at an alternative that would just be, could you gather enough crude at Cushing to build to the Gulf Coast, and we couldn't assemble enough critical mass in our planning process to make that proposal to the marketplace.

That makes sense answers my question. The other thing I wanted to ask about was regarding the U.S. pipeline assets that you are currently holding in TransCanada, that could potentially be asset monetizations in the future. Just to take them off GLJT, GTN, the ANR system and then your Southwest assets. Any other assets that could potentially go in and what issues would surround each of those pipeline ins.

Well let me go through your list. First today we have about 46% of Great Lakes that is in our MLP so we have already taken steps there is and we have 100% of our interest in Northern Border that's in the MLP so there's not much there. No part of GTN is in the MLP, so we do think about that, but I want to clarify that it is an illustrative option. I was discussing earlier, but GTN is certainly a candidate. The southern end of GTN, serving Nevada's Cal Tuscarora and all of our interest in Tuscarora is already in the MLP, the north Baja line down in southern California, we would not anticipate that going toward the MLP in the near term. We have got a lot of work and investment to do there. And Iroquois if we owned 100% of it, we might think about putting part of it into the MLP. It is a different question when we only own roughly 44%. We would consider it, but I am just kind of running through them all for you.

My sense on ANR. We have a lot of work to do there and terrific investment opportunities on the storage side. We don't think projects that have execution risks or technical risks in a substantive way are appropriate for the MLP. Our business model is to deal with those issues, take that risk within TransCanada, create value which we would intend to capture for the TransCanada shareholder, and maybe in the future put a part of those assets into the MLP, but I would not want to leave the impression that any significant transfer of ANR assets is going anywhere anytime in the near future. That's the asset we keep within TransCanada.

Thanks, that makes sense. Being that the Great Lakes system and the GTN system have both been in TransCanada for a while, I would expect that any kind of asset sale there would produce a significant tax liability. Is that correct?

Well it would produce a taxable gain. I think. We don't always think those are such a bad thing.

All right. Well thanks a lot.

Thank you.

There are no more questions registered at this time I will now turn the meeting back over to Mr. Moneta. Please go ahead, sir.

Thanks very much and thanks to all of you for participating this afternoon. We appreciate your interest in the company. I know it has been a bit of a long day with the AGM meeting earlier today but again we appreciate your interest late on a Friday. Bye for now.

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