TC Energy Corp (TRP) 2003 Q1 法說會逐字稿

Good afternoon Ladies and Gentlemen and welcome to the TransCanada Pipelines First Quarter Results Conference Call. I would like to turn the meeting over to Mr. David Moneta, Director of Investor Relations. Please go ahead Mr. Moneta.

Thanks very much. Good afternoon everyone. I'd like to take this opportunity to welcome you this afternoon, including those parties who are joining us through the world-wide web. We're pleased to provide the investment community, the media, and other interested parties with an opportunity to discuss our 2003 first quarter financial results and any other general issues concerning TransCanada. With me today, are Hal Kvisle, President and Chief Executive Officer, Russ Girling, Executive Vice President and Chief Financial Officer, and Lee , Vice President and Controller. Hal and Russ and going to start this afternoon with some comments on our results and other general issues pertaining to TransCanada, and then following their opening remarks, we'll turn the call over to the conference co-coordinator for questions.

During the question and answer period, we'll accept questions from the investment community first, followed by questions from the media. Before Hal begins, I'd like to remind you that certain information in this presentation is forward-looking and is subject to certain risks and uncertainties. The results or events predicted in this information may differ from actual results or events. Factors which could cause actual results or events to differ materially from current expectations include, among other things, the ability of TransCanada to successfully implement it's strategic initiative, and whether such strategic initiatives will yield the expected benefits. The availability and price of energy commodities, regulatory decisions, competitive factors in the pipeline and power industries, and the prevailing economic conditions in North America. For additional information on these and other factors, see the reports filed by TransCanada with Canadian Security's Regulators, and with the United States Securities and Exchange Commission. TransCanada disclaims any intention or obligations to update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise. With that, I'll now turn the call over to Hal.

Thank you David. Good afternoon everyone and thank you for joining us. Having discussed our 2002 end first quarter results, our strategy, and our outlook for the industry with shareholders at TransCanada's annual meeting earlier this morning, I'll keep my remarks brief. For those of you who were able to attend the meeting this morning or listen to the live web cast, the web cast will be archived at www.transcanada.com. I'm pleased to report that TransCanada is off to a good start in 2003 with increases in earnings and cash flow and a strong balance sheet. The Board today declared the company's 158th consecutive quarterly dividend on the common shares. The dividend of 27 cents per share is payable on July 31st to shareholders of record at the close of business of June 30th. I'm particularly proud of the fact that our first quarter results were achieved in a quarter marked by continuing challenges within our Canadian regulated pipeline businesses. Our net income for the first quarter was $208 million, or 43 cents per share compared to $187 million, or 39 cents per share for this time last year.

The increase of approximately 11 percent is due in large part to higher earnings from our power business and more specifically, from our investments in Bruce Power. We completed the acquisition of our interest in Bruce Power in mid February. We are very pleased with the initial results from Bruce. Working in our favor today, has been a combination of cold weather, strong power prices, and excellent operating performance with all 4 units of Bruce B running at 100 percent of rated capacity. Over the course of the year, supply and demand within Ontario will fluctuate and the facility will undergo scheduled maintenance programs later in the year. Both of these factors will have an impact on earnings going forward. In my remarks to shareholders this morning, I discussed the supply and demand fundamentals that drive our core businesses of natural gas transmission and power.

TransCanada's extremely well positioned to link existing and new sources of supply with growing demand in selective North American markets. We have premium type and power assets serving key markets. A top notch organization of highly skilled and motivated people, and the financial strength to enable us to act on quality acquisition opportunities and new developments, such as northern pipelines and liquefied natural gas. Complimenting that financial strength, is the greater flexibility we'll have to implement our strategies for growth and value creation under our new holding company's structure. We're very pleased that share holders voted in favor of the creation of TransCanada Corporation. We're scheduled to appear before the court of Queen's Bench in Alberta on Monday to seek approval of the arrangement to establish TransCanada Corporation.

With the court's approval, TransCanada Corporation will officially become the parent company of TransCanada Pipelines Limited on May 15th. In the future, we will continue to work with our customers to address the issue we face in the regulatory environment and arrive at solutions that benefit all stake holders. We will also work to ensure we receive a fair return in all aspects of our business, including our Canadian mainlines investments. Our strong financial performance this quarter continues to be a direct result of our focus and discipline in implementing our 5 key strategies. We look forward to maintaining this focus with an emphasis on well planned, well executed growth with free value for our shareholders, while preserving our financial strength. I'll now turn the call over to our CFO, Russ Girling, who will provide additional details on our financial results. Russ?

Thank you Hal, and good afternoon everyone. As Hal said, we are very pleased to report another strong quarter of operating results. We continue to generate solid earnings and cash flow growth, by executing our discipline strategy of operating, developing, and acquiring large scale energy infrastructure assets. As Hal pointed out, and as recorded earlier today, net income applicable to common shares for the first quarter of 2003, was $208 million, or 43 cents per share compared to $184 million, or 39 cents per share last year. That 11 percent increase in net income is primarily due to higher earnings from our power business, reduced net expenses in the corporate segment, partially offset by lower earnings from the transmission segment. I'll review the first quarter results for each of our segments beginning with transmission. The transmission businesses generated net earnings of $158 million in the first quarter of 2003 compared to $163 million last year.

The decrease is primarily due to a lower contribution from the Alberta system which generated net earnings of $42 million in the first quarter compared to $50 million in the same period last year. As you know, in February we reached a one year settlement for the 2003 revenue requirement for the Alberta system. That settlement establishes the Alberta's systems fixed revenue requirement for 2003 at $1.277 billion compared to $1.347 billion in 2002. As a result, we estimate that at the Alberta systems annual net earnings in 2003, will be approximately $40 million less than the 2002 net earnings of $214 million. As we had said before, the negotiations leading to that settlement were significantly influenced by last year's national energy board decision on our Canadian mainline fair return application. In our view, the NEB decision does not reflect a long term business risk of the Canadian mainline, and we believe it erred in coming to that decision.

As a result, in March, we applied to the Federal Court of Appeal for a leave to appeal the dismissal of our review of a request for a review in variance of the Fair Return Decision. As I said, while we were disappointed with the NEB's decision, it did not -- it did at that time increase the deemed quantity ratio from 30 percent to 33 percent effective January 1, 2001. The Fair Return Decision was received in June 2002 and was therefore not reflected in the first quarter 2002 earnings. As a result, the Canadian mainlines net earnings for the 3 month ended, March 31st, 2003, have increased by $3 million when compared to the corresponding period in 2002. Earnings in the first quarter of 2003 also reflect an increase in the approved rate of return on common equity from 9.53 percent in 2002 to 9.79 percent in 2003, which is partially offset by $280 million decrease in the average investment phase. And finally, with respect to the transmission segment, our share of earnings in the first quarter from investments in North American pipeline ventures, was $43 million, the same as it was last year. Net earnings for the 3 months ended, March 31st, 2002 included TransCanada's $7 million share of a favorable ruling for the Great Lakes related to Minnesota used tax paid in prior years.

Excluding the impact of Great Lakes favorable ruling in 2002, net earnings for the North American pipeline ventures for the 3 months ended March 31st, 2003 increased by $7 million mainly due to higher earnings from the Courtland Pipeline as a result of it's rate settlement. Under the terms of the settlement, there are higher tolls in the first quarter of 2003, and Portland's depreciation rate declined from 4 percent to 2 percent, resulting in a one time positive adjustment to income of approximately $3 million after tax. Next, I'll talk about the power segment. The power business contributed net earnings of $63 million in the first quarter, an increase of 54 percent compared to the $41 million reported in the same period last year. Total volumes sold in the first quarter were 5,935 gigawatt hours compared to 4,550 giga-watt hours in 2002. The increase in net earnings was primarily driven by the strong results from the recently acquired interest in the Bruce Power , and the addition of the ManChief Power plant in late 2002, power completed, the acquisition of a 31.6 percent interest in Bruce on February 14th, 2003. Bruce consists of 2 nuclear plants.

Bruce B has 4 reactors currently generating a total of 3,140 megawatts. Bruce A consists of 4, 769 megawatt reactors, which are not currently operating, however, 2 units are currently undergoing restart activities. Bruce contributed $38 million of equity income, or $27 million after tax in the first quarter of 2003 from the date of acquisition with an achieved average electricity selling price of $63 per megawatt hour. Before Bruce B units ran a hundred percent availability during the entire first quarter of 2003, which is the best performance in the plant's history. Approximately 45 percent of that output was sold into Ontario's wholesale power market. $38 million contribution reflects the strong plant performance and higher than expected wholesale spot prices as a result of colder than normal weather temperatures and increased demand for electricity.

Given the expected demand for power in Ontario this summer, Bruce has accelerated it's 3 start activities to insure that the 2 Bruce A units at 1500 megawatts of power for the Ontario market during this critical period. Having received formal approval, or formal regulatory approval from the Canadian Nuclear Safety Commission, Bruce has committed more than 1100 employees and contractors to work on the final stages of the project and our expectation is that the facility should have full production from the 2 Bruce A units by the end of June, 2003. Commissioning activities at Bruce A are well advanced on unit 4 with approximately 90 percent of the systems now in service. Refueling on unit 3 began on April 20th, and is expected to take approximately 45 days to complete. As a result of these additional efforts, the total restart costs are expected to be approximately 20 percent higher, and previous estimates of $450 million, which included $400 million for Bruce A restart project costs, and $50 million of deferred startup costs. Deferred startup costs include direct project support in a number of areas, including project management, waste management, training, procurement security, and information technology. Approximately $100 million of the Bruce A total restruct cost is expected to be spent in 2003, and will be funded by Bruce Power cash flow.

Looking forward, equity income from Bruce will be impacted by fluctuations in spot market prices for electricity, as well as overall plant availability, which in turn, is impacted by scheduled and unscheduled maintenance. To reduce this exposure to spot market prices, Bruce has entered into fixed price sales contracts for approximately 1,600 megawatts of output for the remainder of 2003. There's a planned maintenance outage at one of the 4 Bruce B units for most of the second quarter, which will reduce quarterly output accordingly. Similarly, there's an approximately one month planned outage at Bruce B unit and a Bruce A unit in the third quarter and fourth quarter of 2003 respectively. Now turning to our western operations, operating, and other income of $43 million in the first quarter of 2003 was $9 million higher compared to the same period last year. The increase was mainly due to the acquisition of the Man Chief facility in November of 2002 and lower transmission electricity tariffs.

TransCanada Power LP contributed $11 million in operating and other income in the first quarter, an amount that is comparable to a $10 million reported last year. The quarter over quarter increases from Bruce, western operations, and the Power LP, were partially offset by a lower contribution from our northeast U.S. operations, and higher general and administrative costs. Operating and other income from our northeast U.S. operations at $25 million in the first quarter, was $16 million lower compared to the same period last year. Two thirds of the decrease is due to higher costs of fuel gas at the Ocean State Power Plant, which significantly limited gas arbitrage opportunities as compared to the first quarter of 2002. And 2 million dollars of the decline was due to lower water flows from the Curtis Palmer Hydro-Electric Facility.

In December of 2002, Ocean State Power concluded an arbitration process with respect to the cost of it's fuel, which substantially increased the cost of fuel for the December, 2002 through to March, 2003 period. A decision was received on a second arbitration in late March, 2003 which is affective April, 2003. The decision was not materially different from the December, 2002 decision. General administrative and support costs of $21 million for the 3 month ended March 31st, 2003 were $4 million higher than the same period last year. The variance is due to increased business activity in the power segment. Going forward, our objective continues to be to grow, our asset based power business in a manner that contributes to long term earnings and cash flow growth.

We'll continue to pursue projects and manage our power portfolio in a manner that fits our desired risk profile with a combination of low costs, based load supply, and long term contracts with strong counter parties. We will leverage our extensive market knowledge, strong technical expertise, deregulation experience, and risk management skills to grow our power business in the same manner that has led to a success today. Next, I'll talk about the corporate segment. Net expenses were $13 million and $17 million for the 3 month ended March 31st, 2003 and 2002 respectively. The $4 million improvement is primarily due to positive impact of lower interest costs compared to the same period last year. Now turning to cash flow in our balance sheet, funds generated from continuing operations for the first quarter were $457 million compared to $455 million last year.

Capital expenditures, excluding acquisitions for the 3 month ended, March 31st, were $76 million and were related primarily to Iroquois and to the ongoing East Chester expansion project, maintenance and capacity capital in the wholly owned pipelines and the ongoing construction of the MacKay River Power Plant in Alberta. Acquisitions in the first quarter totaled $409 million and reflect the acquisition of our 31.6 percent interest in Bruce Power, or $376 million plus post closing adjustments. Our balance sheet also remains strong and I can report that it is stronger than it's been in the last 15 years. It consists of 57 percent term debt, 6 percent preferred securities, 2 percent preferred shares, and 35 percent common equity. The company's discretionary cash position also remains strong as we expect to generate substantial operating cash flow and aside from ongoing maintenance requirements and ongoing construction of the MacKay River, we have limited Capital commitments at this time.

To summarize, the company's earnings and cash flow, combined with a strong balance sheet provides TransCanada with the financial flexibility to continue to make discipline investments in our core businesses. As we have said previously, we will continue to make profitable investments in natural gas transmission and power, but be assured that our evaluation approach will remain disciplined and focused to ensure we continue to enhance shareholder value. We'll continue to work on establishing a new regulated business model that provides value to our customers, reduces the long term risks of our Canadian long haul pipelines and allows us to earn competitive returns. We will continue to focus on operations excellence with a focus on providing low cost reliable service to our customers and we will continue to maintain a strong financial position and will not compromise our credit ratings. Successful execution of these strategies will result in continued earnings and cash flow growth in the years ahead and build value for our shareholders. That concludes my prepared remarks and I'll turn the call back to David.

Thanks very much Russ. Just before I turn the talk to the conference coordinator, just a reminder, we will accept questions from the investment community first, followed by questions from the media. With that, I'll turn it back to the conference coordinator.

Thank you. We will now take questions from the phone line. If you have a question, please press one on your telephone keypad. If you are using a speaker phone, please lift the handset and then press one. If at anytime you wish to cancel your question, please press the pound sign. Please press one at this time if you have a question. Our first question is from Karen Taylor from BMO Nesbitt Burns. Please go ahead.

Thank you. I've got a couple of questions if I may, very quickly on cross sell to, there was a very small reduction in contribution, does that relate to higher gas costs year-over-year?

Karen, it's Hal here, it would partly relate to the way in which our customers would be using cross sell to during a period of very high gas prices. I don't more than that, but that's what I suggest.

OK, now I have a series of questions on Bruce. So they're sort of sequential, so I'll try and deal with them really quick, and get through them. I just need to confirm with you that Bruce A Unit Four will be in service on schedule by April 29th of '03?

No. That, Unit Four is looking like, I'm not sure that we ever put out that schedule.

That came out of the stuff, so.

OK, our, we've always said I think one unit. I think our last disclosure was one unit in June and one unit in August. I think what we're looking at right now is one unit up by the end of May at full production, Unit Four and Unit Three up as full production by the end of June. That's the current forecast from the people at the plant.

OK, so you're accelerating third unit, I believe July was at one point bantered around, so now we're looking at June?

Yes.

OK.

Barring, you know, it's a big project so.

Oh, I understand that. And there have been numerous comments coming out of the hearings in the press from Bruce Power itself about the project being on time and on budget, and what I'd like to understand is how an acceleration of the Bruce A Unit Three and perhaps pushing back Bruce A Unit Four will increase the budget by 40 percent or rather 20 percent, or $90 million. Can you just take me through how that is going to work, and when you become aware of this?

I think that those are, you know, the continuing you know, projects, and we disclose I guess increases as we become aware of them and then over the last couple months, as we've you know, got more involved and they have been, you know, at accelerating and moving people across to make sure that these projects get done on time. The current estimate has increased by you know, that 20 percent. So it's an ongoing thing, and can't say that you know, one day we woke up and said, ah-ha the costs are up by 20 percent. It's a continuous process. As you learn things and uncover things as you go through the process of bringing these units back on, it's not a process that's been done before, and so you know, estimates do change as you move through it.

OK, but, you know, keep in mind that there have been two hearings in the first quarter of 2003, where we've talked about cost budgets and so on. So I guess that I can accept these things run over, I mean lord knows there are others in this market with over just on nuclear power, which I supposed is the point.

What is the nature of the overrun? Where does it come from? Is it more people, higher capital costs, higher financing costs, what's the 90 million on the 450?

I think it's combination of all the things required to do it, and I don't have a breakdown for you Karen of exactly what the overrun costs are. But you know, they're generally in all areas of the restart. There's a number of different buckets of costs and we're incurring higher costs in a lot of those buckets. taylor: So will this materially affect the cost of production on per megawatt hour basis ...

No.

Shifting it from the 30 to $35 range that you have talked about in the previous calls.

No the cost overrun is not material to the overall cost per unit on a go-forward basis.

OK, the 1600 megawatt of forward sales as it reflects, I'm assuming it reflects the in-service schedule for Bruce A as it's now set out, is that correct?

That 1600 megawatts is the same 1600 megawatts we talked about before. It might be in a different format. We just believe 1600 megawatts was easier to understand. I think we used a percentage term when we actually made our disclosure in February when we announced the project or in December when we announced the project. So it's exactly the same. We haven't increased our forward sales at this time as a result of Bruce A coming on.

OK, the Bruce B availability, you changed a little bit versus the press release with regard to your comments in the call. From the press release I took one unit of Bruce B off for full quarter, roughly 90 days. Another unit of Bruce B down for 30 days in the third quarter and then in the press release it implied a further unit of Bruce B, 30 days, fourth quarter, you indicated that may then be Bruce A Unit for 30 days.

I thought the press release said Bruce A as well, but yes, there's one Bruce A Unit down for 30 days, and one Bruce B unit down for 30 days in the third and fourth quarter, and just checking our disclosers.

Yes, what it says, it similarly there's an approximate one-month plan outage at one Bruce B unit and one Bruce A Unit in the third and fourth quarter 2003, respectively.

OK.

That's in the quarterly report.

OK. The availability numbers that were given at the time of the acquisition for Bruce B, about 88 percent, does that still hold, because we have to make certain availability assumptions about the remaining units that are not mentioned in the press release.

I think that what we tried to do was is if the 88 percent in the original disclosure was sort of an overall high-level assessment including outages, what we've tried to do in this quarter is be more specific in the outages. So I think I would leave it to you to calculate the availability amount. Those are out scheduled outages that we have planned.

So for everything that you do not mention, I should be assuming a 100 percent availability?

Well I think that's a bit extreme, because there is, you know, unplanned outages as well, but ...

OK, so what's the target on planned outage ...

Well Karen it's hard to tell here, I mean, you're asking us to tell you what the modeling assumption should be around variables that we don't know. You know, we certainly don't plan that we're going to have outages, unexpected outages.

Statistically I suppose there is a distribution that you've seen on these units, at least from a historical perspective or that you would have had in the initial, so ...

And I t, no, but it varies from 75 to 95 percent ...

Right, and so you just said you'll leave it to me to calculate the total production number, you've given me certain planned outages and then I know there's this very wide range, so I'm just trying to narrow that range very quickly, so ...

We appreciate that, but we don't think it's appropriate for us to speculate on what it might be and then convey that to you. It's better that you just use your own good judgment, recognizing what's happened historically.

OK, the power segment in the Northeast, just what happened there? I know you mentioned something about Ocean State and the purchase price variance on the GAAP. We've got volume up in the segment, 44 percent, earnings down per megawatt hour by 57, 58 percent and availability going from 99 percent in the first quarter of '02 to 84 percent. Is that all Ocean State with two million from Curtis Palmer?

Yes, it's essentially all Ocean State and the bulk of it is of the change in income was related to us having a gas contract, which allowed us to basically you know, shut down the plant in certain situations and sell the gas in the marketplace and make arbitrage profits as a result of the arbitration out gas cost has increased, that opportunity isn't available to us anymore, so we saw a decline in profitability.

OK. And just lastly ...

Karen, can I just, Russ here, I'd just like to add something to your comment with regards to volumes, in the annual report, we did note that in 2002 that we were were or Northeast operations was contracting third parties for supplies when then they remarket. That continued into 2003. So your volume question as far as the increase is not really related to OSP, it's more related to those activities.

So, I'm sorry, third party marketing, is that actual physical volumes?

Yes.

Market on behalf of third parties?

Yes.

OK, and very lastly and then I'll get off the phone, I promise. Your calculated return on invested capital for the power segment, what do you calculate that to be?

Where do you see that?

I don't, so what I would do is take the segment assets as of page 15 of your report where you've got 2.7 billion invested at the end of March and 2.2 invested at the end of December so the differentiating factor's Bruce, obviously. And then I would take very simply an annualized earnings numbers and come up with theoretically anyway, a return on invested capital, and I'm just wondering what I should use for the deemed equities so I can back out a return. I've done all of that and it appears to be lower than some of the returns that you talk about in, for instance a regulated pipeline setting. So I'm jus wondering what you believe that is as opposed to what I think it is.

Well I guess, I think first of all, we don't have a deemed capital structure. We don't allocate interest to the, so I'm surprised that you would get a number that would be less than our regulated business as something that maybe we could talk to you, you know, offline on how you're doing your calculation. But I wouldn't expect that our returns on total capital would be something less than our regulated pipeline business.

I think Karen also, it's Hal, if you're using net income as the return, you don't ever get the same answer as if you're looking at cash flow internal rates of return, which is the way we actually you know, track performance of the individual businesses.

OK, I'll follow up with you off line.

OK.

Thank you. Our next question. The next question is from Matthew Akman from CIBC World Markets. Please go ahead.

Thanks. Just to follow-up on the Bruce. I just want to make sure I understand this correctly. Are the Bruce A Units completely on contract? In other words, do you plan to sell all of that capacity in the back half of this year into the spot market?

No, what we do is we look at it as a portfolio. And at this point in time, we haven't increased our amount of contracted power till we have some operating experience with the Bruce A Units, so that will be sold spot until such time as we have, you know, comfort that that power is available for us to sell on a term basis.

And if I can just follow-up then on your strategy on contracting or philosophy, what would it be, you know, what kind of percent on those new plants at Bruce A Units would you look for to be contracted and why, what's your rationale around that?

All right, I think that your contracting strategy is something that we discussed with our partners at the Bruce facility, but I can tell you some of the drivers behind it. Obviously we're all interested in stability of revenue over the long haul, but some of those, the risk factors that you need to consider is unit contingency is having a unit outage, and if you've sold the power, all of your power, and you have a unit outage, usually what that means is the power, prices are going up if we have a unit outage, and we've caught buying market price power at higher than we've sold it at, and then a number of companies have got themselves into the situation where, you know, that is, that's been very detrimental to them.

So, you know, that's a large consideration in terms of the percentage that we sell forward, another consideration is obviously where the power prices are at the current time and where the forward market is, is your tendency to sell forward when you're at the bottom of the cycle is not as great as it would be as when you're at the top of the cycle. So a number of those factors go into it. And you know, we're working through right now, what our actual policies are going to be, but generally speaking they follow the guideline of looking for stability. It's a high fixed cost operation.

So you know, we look to generate stable revenues to offset that, and that's, you know, consistent amount the partnerships, but we have to consider the marketplace risks when we're making those decisions.

So you know, I think the philosophy's very similar to the one at TransCanada employs on all of its other power assets.

OK, thanks. And just continuing on with Bruce. Are you able to tell us anything about what the operating costs, not the fuel costs, but the sort of the including the lease payments, even if you want to lump all that together, whether you want to express it per megawatt hour or just as a number. Are you able to tell us anything about that for the quarter?

Yes, for the quarter?

Yes.

girling No, I don't have those number available for you for the quarter, but generally speaking, our thoughts for 2003 on an average basis are probably you know, with just fuel and operating costs, less, you know, including capital we'd probably be somewhere in the $35 range, something like that. That's with our expected output at Bruce for the year, Bruce A for the year. As you move forward, and we see more production, sort of 2005ish being, sort of what we call a full production year of having all of our units up and operating, we'd see that number declining into the low 30's as we move forward.

Including fuel, operating and depreciation?

Yes.

All of those things? OK. Thanks and just then moving on to Ocean State, I wanted to clean up a little bit on that one too. The new contract or settlement on the natural gas, is that a long-term deal now then, or how far out does that extend?

We have another opportunity to re-arbitrate that for the next gas year. So we'll, that's one of our options, we're looking at a number of different options. So I'd say that's not, it's not a permanent structure for sure.

Can things get worse?

Things can always get worse, but I, you know, I think our perspective would be, is that's, that's as based as we think the arbitration language in the contract could take us. But again, we're not the arbitrators, so.

So, well, and Matthew I'd add to that, you know, Ocean State is no different than another plant where if the input costs get a whole lot higher and the value of the output plummets, as you might find in a very high gas price market with low power prices, then you know, that should be a short-term operation that shouldn't continue forever, but that would be the circumstance where it, in fact, could get worse.

OK.

While I'm not predicting that it will, but to be very direct in answering your question, you know, we are running a operation.

OK, thanks and then just one last question. On Northern Gas, I'm wondering if you could give us an update on where you are, what can you say about that?

Well I think I'll just say very quickly, first on the Alaska project, that there are many big wheels in motion in Washington DC right now, and the producers are working hard to get the stabilization, the volatility stabilization and security they need to enable them to go ahead with project. It's unusual situation that they find themselves in where if you roll back the clock 20 years ago, you would have had major utilities that would have taken out long-term contracts under project like this. And at this particular point in time, utilities can't do that really anymore. So everybody looks to the producers to do it, but the producers aren't actually inclined to take on that kind of a risk. So if the American marketplace needs this gas, something else has to be done.

And as to what the right answer is, I don't know. I mean we have some thoughts of our own, but we understand what the producers are trying to accomplish. If that doesn't make it through in the current round of Congress, then I think that project will probably go into a period of delay that could be a couple of years while we get through the next presidential election, but I don't know that either. What I'm trying to illustrate that to you is that it is the whole Washington government process that is the major uncertain timing thing related to Alaska. What is not uncertain to us is the need for the gas. To us, it's fairly clear that the United States is in a very tight - extremely tight - supply and demand situation with respect to gas. That bodes well for the Alberta producing industry and if they're able to add to their gas volumes, then we think that's good for us. We'll have more volume to move. So I'd still put Alaska in the sort of no new news category - a very long-term project.

In terms of the Mackenzie, I would be quite a bit more optimistic. Firstly, because it's a much more straightforward project, much shorter and less technically difficult. The major issues revolve around the regulatory process in Canada, which is unnecessarily long and painful, in my view. And we need to do something to improve that. But secondly, the Aboriginal issues have yet to be resolved. And until they are, that project is moving slowly.

But the Mackenzie is a fundamentally attractive, relatively cost effective, desirable project from every perspective. Certainly very important to the Northwest Territories and a value adding project for those producers. So we would like to see it go ahead quickly because, among other things, it does add a Bcf a day of long-life gas coming into the north end of our Alberta system and that's a great outcome for us.

Well, how would you look at this from an investment standpoint. How, I mean, does it have to stand on its own if you guys invest in the Mackenzie pipeline or would you actually include potential benefits like the filling up of your pipelines and, therefore, maybe take a lower return on any direct investments because you see some spillover benefits somewhere else? How do you guys look at this project?

Well, if those spillover benefits were quantifiable financial cash benefits, then you might look at them in a combined way, but really, when you think about what I've describe, the Mackenzie primarily serves to stabilize the flow of gas through our Canadian mainline and Alberta system for the long-term and that doesn't put any more money in our pocket. It just reduces the long-term stranded asset risk. So it's kind of difficult for us to subsidize the construction of a Mackenzie pipe just in order to get it done when any benefit that accrues on the southern system basically gets transferred to our shippers by the regulator. So, in a nutshell, no, we would not contemplate that at this time.

Thank you. Those are all my questions.

Thanks, Matthew.

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

I'll kind of mirror Matthew and delve a little further into Bruce, if I may. And then, back to Frontier Pipelines, but I'll be brief. Exports - were there any exports of power out of Ontario through Bruce and if you did want to export, has that clarified any yet in terms of your ability to do so?

I didn't catch the last part of the question, Sam.

Is it any clearer on how you can export going forward? We now have a new OEB chairperson, but I'm just curious as to where the issue stands from your capability or desire to export, say, on fixed contract or spot basis to, say, Detroit.

OK. Currently, there isn't any exports from Bruce. And I - it's an opportunity that we're looking into. I don't think that there's any sort of major changes that, you know, at this point in time. There's some export permitting issues and that sort of stuff that we need to get through at Bruce that are being introduced currently. TransCanada currently has some of those capabilities, but we need to make sure that Bruce has those capabilities and flexibilities going forward. I'm not aware of any sort of major impediments at this point in time, except for the fact of us having to get through those processes.

OK. Let me shift back to the Mackenzie. The 's CEO was front page news this week, earlier on, that the Aboriginal Pipeline Group did apparently finalize some financing deal with somebody. Obviously, speculated you. But, hypothetically, looking at that pipeline, the interest available, of course, operatorship, I guess, construction like an EPC contract and/or ownership - has the ownership already been pre-concluded between the producers and the Aboriginal Pipeline Group? So it's the operatorship in the construction EPC contract that is up for grabs? Or how do you look at it as a bidder, if you may, on those pieces?

You know, Sam, I'd love to get into that in detail, but I can't. We're, obviously, involved in discussions with the Mackenzie producers and with the Aboriginal groups. And we have been for a long time. In the greatest extreme, for 30 years we've been talking to people about this. But we are trying to work out some issues that will help the project go ahead right now. And all parties are committed to confidentiality around that. So I know what you're interested in and I, unfortunately, can't answer it.

OK. I had to try that question on. Last question - Pickering. Are you hearing anything about Pickering at this stage? They seem to be slipping yet again on their . Is that why you're accelerating on Bruce?

That's not why we're accelerating. You know, we read the same things as you do in the press on Pickering, but we would have no better information than what you're reading.

OK. Thanks, Russ.

Thank you. The next question is from Andrew Kuske from UBS Warburg. Please go ahead.

Thank you. Just, if I could ask a question on a bit of a different vein. In regards to capital structure, there has been some concern by the debt raiders of the Canadian utilities and if you could just address that issue. Your capital structure has risen quite dramatically over the last few years. Where is your zone of comfort with your capital structure and, you know, if you could elaborate on any conversations you've had with the debt raiders about the target ranges.

First, I - it's Hal. I think the comment that TransCanada would always be more comfortable with less debt and more equity than the other way around. And the stress that we're under is, in our Canadian mainline regulated business, we have a very high degree of leverage imposed upon us by the regulator and we pretty much have to go with that degree of leverage, otherwise earnings and return on equity would be even more miserable than the 9.9 percent than we're at right now. So that's the major concern that we have with respect to debt leverage. In our businesses that are not governed by regulators we, in fact, carry more equity and less debt than what we do in our regulated mainline and that results in the corporate average that you see.

So, directionally, we are always in favor of less debt. It's a stability and a risk mitigation situation. I mean, I'm not suggesting we would want to run any of our businesses with zero percent debt and we do look at everything that we potentially invest in to make sure that it would be a sound investment somewhere between 50-50 and one-third, two-thirds equity debt. So that's kind of the range of comfort that we have, depending on the particular business. But we do feel, to some extent, that some of our more attractive non-pipeline businesses are subsidizing or carrying the debt structure for the Canadian mainline right now. Beyond that, in terms of specifics, Russ, I don't know if you'd add anymore to that.

No, I think that's, you know, our focus is on being - is insuring that we have a solid balance sheet, as Hal pointed out. If you were to take our consolidated balance sheet and deduct out the deemed capital structure of our wholly owned Canadian pipeline systems, you'd see that we have a very strong balance sheet. What the rating agencies are concerned about is, on a consolidated basis, that our credit statistics are weak relative to their global matrixes.

The primary reason for that is, obviously, as Hal pointed out, is our regulated business. We are tied to those capital structures by our regulator currently and, as you've seen by our actions in the past, is that we've taken that on as one of our core strategies to ensure that we seek a, you know, a fair balance of risk and return in that business on a go-forward basis.

So, I think they've keyed in on a - you know, on a - on an - on a issue that's dear to our hearts and something that we monitor very closely, but aren't waiting on them to help alleviate our problems. We are - we're definitely working that subject with the regulators, specifically, the National Energy Board and some of the actions that you've seen us take to date.

It is a bit of a regulatory prisoner's dilemna if I might call it that. Just in the sense that you do have the fairly low deemed equity structures. Is there any point in effectively, preemptively infusing capital into some of those regulated business, knowing that you might not get paid for it, at least directly in a short period of time, in the hope of the regulator becoming somewhat cognizant to the need of thicker equity structures as really required by the debt raters.

Well, you know, that's, in effect, what we do when we run our other non-regulated pipes with thicker equity than you normally would. In aggregate, overall at the corporate level, that's where we're at. But I don't think we would necessarily do that. A more appropriate, I think, way to proceed with this is to continue the dialog with our customers and with the regulator. This equity fitness is a very complicated issue. I might suggest that when pipelines are being developed before they've commenced operation, you might go towards 100 equity during the planning stage. Once the pipeline commences operation with long-term contracts, initially, it's perfectly appropriate in R&D to run with 70 percent debt in that kind of a pipe.

But as your long-term contracts mature and increasingly you move gas under short-term contracting arrangements and the supply basin become more mature, I think it becomes appropriate to run with thicker and thicker equity. Until, I suppose, the day before you abandon the pipe, you should have 100 percent equity and no debt. So it kind of varies over the life cycle of a pipe. And I would observe that the regulatory model doesn't really recognize that, but it seems to be more along the lines that pipelines that don't have a lot of capital employed are given a lot of equity. Whereas pipelines that have a lot of capital, the totals are controlled by relying more on debt.

Similarly, local distribution companies, even though they're very nice natural franchises end up with quite a bit thicker equity than long-haul pipelines. So, obviously, those are my opinions with respect to this whole matter, but I think there's a lot of work and a lot of thinking that needs to be done in the Canadian-regulated arena to try to get to the right answer on some of these complicated issues.

That was good. Thank you.

Thank you. The next question is from Maureen Howe from RBC Capital Markets. Please go ahead.

Thank you. Good afternoon. I just want to pursue a little bit the Ocean State situation. You've set out, in your annual report, that the gas contract was being arbitrated. And then, in the outlook for power you do say in here that the net earnings for 2003 are expected to be slightly higher than 2002. I guess that was before, you know, you got the results from the Bruce power plant.

But I'm just wondering if we could sort of back Bruce out of that and then look at that statement, would you still be consistent in that statement today, given the advantage of, you know, more time having passed and, I guess, getting the second arbitration opinion on Ocean State - the gas contract?

I think we'd still be in that sort of same kind of range that we were before.

So it is to say that nothing else really material has changed, other than the better-than-expected performance from Bruce?

Yes. And the rest was, you know, to be expected, as we pointed out. I mean, we know the OSP arbitration was coming up and we knew what impact it would have if we landed on the wrong side of that. And unfortunately, we did. And so it wasn't unexpected as to where we landed.

And just with respect to that, in terms of the gas contract, in your report, your first quarter report this past quarter, you said that you had limited opportunity to resell gas at a profit because of the renegotiation or the arbitration. Gas prices were very high. What should we have - infer then, regarding the price of gas following this arbitration decision? Is it essentially fought so that - so that there's no ability to arbitrage that any more? Or is it really high and are you stuck with that or ...

Arbitrage would be very limited. It's closer linked to market than it was previously. It's linked more to the power market in New England than it was before. But the linkage between the power market and the gas market in New England is stronger than it's even been. So there is a strong linkage to spot market prices at the current time. As the generation mix changes and spot electricity prices diverge from spot gas prices, there could be arbitrage opportunities in the future. But that hasn't been the case in the first quarter.

OK. And let's say that linkage continues. Is the Ocean State plant profitable?

Well, I think as you pointed out, I mean, it's still - it's still a very profitable business for us. It was anomalous in that we had - we had a gas contract that was priced differently than the marketplace. But what you can see today is that the linkage between sort of plant dispatch and gas prices are linked closer together in this settlement. So the facility is going to continue to operate on a profitable basis, but we've lost that opportunity.

OK. And this is a question - I mean, it's one that - I know people have asked in the past similar questions - anyways, and you always say, you know, go ask chemical. But chemical has come up with a different average price of power over the first quarter than your price. In your press release, you say it's $63 per megawatt hour. In theirs, they say it's 57. That's a pretty big difference. I'm wondering, are you each calculating it yourself or are you getting it from Bruce?

I think the difference is the difference in period. We only owned the facility for six weeks and they owned it for the whole quarter.

OK. OK. Yes.

You won't see that again and we did check that with them before we sent this out and that's the difference.

Ok. That's ...

Maureen, we do say, and quote on quote, that it is, in first quarter 2003 from the date of acquisition ...

Ok. That's great. Thank you very much for clarifying that, and I think that's it.

Thanks.

Thanks Maureen.

Thank you.

Thank you, the next question is from Linda Ezergailis from TD Newcrest. Please go ahead.

Good afternoon. I was wondering if I could get some more color on the rate settlement for the Portland pipe line? Just wondering as well how settlement will manifest itself quarter over quarter in terms of seasonality. For example, can I just back out the one time depreciation impact and flat line that for the year? And another, I guess final question with respect to that is, what was the equity component within the settlement?

Linda, it's here, I'll try to answer that. And the first point of , when you take out the depreciation and then flat line it, the answer to that is that you cannot -- as we've noted in the quarterly report, what the rate settlement did was to increase the rates for Portland commencing -- actually, they will commence April 1st of last year, so for quarter one this year compared to quarter one last year, we did have higher rates this year, so you did have that fault in the quarter for this year. That lumped on a quarterly basis will not be there because beginning April of last year, they were actually working at a higher rate number anyways, so you won't have that. The depreciation adjustment is through a one time event in the first quarter. With regards to your question on the equity percentage, I actually don't have that in front of me, we'd have to ...

I'm thinking and we'll get back to you but I suspect that it's a rate settlement and the equity components would be silent in the settlement.

Ok, I need a sort of color that you could give me in additional would be appreciated.

We'll get there.

Thank you.

Thank you, the next question is from Nick from Merrill Lynch. Please go ahead.

Hello. I've got a couple more fixed income orientated questions. My first question was on the deemed equity structure. I'll leave it at that, but concerning you're A-minus rating with SMP which is on review for downgrade. I know you have a desire and you've mentioned it repeatedly to maintain a single A-rating. What is management doing to prevent a downgrade from Triple-B Plus?

I think that we reacted by insuring that the rating agency, in this case, specifically understands why it is that we have critic statistics that are weaker than their global matrix, and as I pointed out in the earlier questions, that is a hundred percent due to a regulated business, at the same time, we have led, not to a substantial amount because that's detrimental to our equity holders, but obviously, we have led with by having more equity than is required in our regulated business or the deems regulated structure today to insure that we are ahead of the curve, and we've been diligently working with the regulators to try to see change before we see a downgrade. We don't want to see that, but at the same time, if at the end of the day, the national energy board decides that a Triple-B rating is sufficient for a Canadian regulated company, there's not really much we can do about that. If the National Energy Board deems that that's appropriate, we would obviously argue that, that doesn't make any sense, but again, that's a little bit out of our hands. In terms of what we're doing, what we can assure you is that, it is one of top 5 strategies in the company to insure that the regulator understands the issue. We've led with greater equity thickness than is required in our regulated business and we're working very hard to bring the understanding of the rating agencies and the marketplace to a place where we can convince people that it's not in anybody's best interest for that to happen, so it is a huge concern to us and we're working very hard to insure that doesn't happen.

Yes, if you're -- I can humbly say that if you're speaking to a regulator and the understand that the thickness of investor base in Canada typically has requirements to hold only a small percentage of the portfolio in Triple-Bs and with the amount of debt, it turns out that TransCanada and have, outstanding this market could make it extremely difficult for the thickness of the investor base, which would result in a widening of spreads in a sort of painful environment, so maybe it would be good to get that across to the regulators.

I would agree, and that is the education process that we're going through as we would concur with your comments.

Just lastly. Do you -- regarding the holding company structure, any intention to issue debt at that level and/or hold non-regulated assets at the , do you expect any actual notching in the rating?

We're not expecting actually to use that entity or to have that entity rated at the current time. All things will remain as they are today. The only function that company is to do is to act as the parent right now with TransCanada Pipeline. We'll still continue to issue out of TransCanada Pipelines and TransCanada Pipelines will be the only rated entity at this time.

Just finally one last question. , which is the ratio we ratio we looked at for leverages has come down to 3.8 times from 5, 6 times a few years ago. Do you have any dated or preferred target for this ratio? I know your not the regulators that impact that ratio but for an example, your peer has ratios of about 6 times.

We don't have a target for that ratio. It's one that I would my list after this conversation but usually we looked at cash flow total debt which I guess is just potentially to be the inverse of what you're talking about, but we don't have that stated goal on those except for to stay within what the rate agencies will deem to be an A-Grade structure. So, if we fall outside of what an A-Grade structure according to matrix do, then you need to sort of -- they've got the subjectivity of telling you what kind of business risk you have and where you fit in the matrix, but certainly our objective would be to fit in the matrix in the A-Grade category.

Thanks very much.

Thank you. The next question is from from Baker & . Please go ahead.

Good afternoon Gentlemen. Just asking some of the comments which made. Do you have some of the capital structure given that you are forming out holding company basically. What's your target capital structure at the holding company level?

It's a hundred percent equity I guess.

How much, I'm sorry?

It's 100 percent equity. There will be no debt at the holding company level at the current time. All the debt will be in TransCanada Pipelines.

Right, and in terms of Russ, given that you said all the debt will be issued at TransCanada pipeline, given that they are already non-recourse debt, which is just part of the current structure, now I mean, is it feasible going forward that you're going to remove that basically and get joint ventures and move it up basically at the holding company level to free the mainline basically, you know, basically structured itself on however the debt equity levels are?

That's not the intent at the current time. The intent isn't to move anything currently. The current plan is just to leave it as is. We have no pans to rearrange either the assets or liabilities that are held inside Trans pipelines today. As we pointed out there was some convenience reasons for reorganizing like this. Certainly gives us the flexibly to consider you know, all kinds of different organizations down the road, but currently those aren't part of our plan. This isn't to create acute structure by which we can rearrange our assets to make you know, one part less attractive than the other part at the expense of any stakeholder. That's not our current plan at all.

Right, OK, and the background is basically that if you want to sort of notching exercise where not everybody does it, you know, probably that will help your main line basically credit will be separated from, so-called other, you know, joint ventures of other stuff, you know.

Right.

And I think that that will still be in the interest of the debt holders like me.

Right.

You know, anyway, thanks very much for letting us basically, and congratulations on getting that holding company by shareholders today.

Thanks .

Thank you.

Thank you. The next question is from Karen Taylor from BMO Nesbitt Burns. Please go ahead.

Thanks, my follow-up was asked and answered, thank you.

Thank you. The next question is from Bob Hastings from Raymond James. Please go ahead.

Yes, just hate to talk about Bruce anymore, but just out of curiosity, two things on the Bruce, the $63, what proportion of your sales run are contracted for that period?

I think that it was about 60 percent was under contract. I'll get the actual number, 45 percent of the output was sold to the Ontario spot market.

Fifty-five under contract, 45 on the spot.

Would it be fair to say that the contract prices are realized in that period for continuing on at that level, whatever that might have been for the rest of the year?

Yes, and around that same level we disclosed in December. I think it's around $42 or something like that.

Yes, OK, and just given the high gains and again this is not a regulated operation, the accounting treatment for the overage, the $90 million overage, would you be looking at all trying to maybe expense some of that or is this just all going to be capitalized in?

That will all be capitalized. The right accounted, I mean we've had significant discussions about that and that the absolute right accounting treatment is to capitalize it.

So we've been through every bucket and every expense item to make sure that we're not capitalizing things that we shouldn't be, is something that we've take very, very seriously, obviously, and so it will all 90 million will be capitalized.

OK, and then the last thing on the Northern pipeline, given that you have to really on the national energy board at the end of the day for that as well. Are you satisfied that you're protecting your capital structure and whatever you might be doing there, and your appropriate rate of return so they can't give you substandard rates again.

Well I think Bob the plan we would have in the current environment would be to enter into long-term contracts with the producers who, pretty much have high quality credit ratings, similar to long-term contracts that exist on alliance. I guess it's always possible that you can enter into those long-term commercial agreements and then someone could apply to the national energy board to have them overturned, but they're legal agreements, not regulatory approvals. And so we would be looking for you know, contractual arrangements, rather than just regulatory arrangement going forward.

Right, OK, thank you and by the way, I do remember prior to TransCanada's capital structure was 40 percent.

What was it 40 percent debt or equity?

So 40 percent equity prior to.

Yes, yes.

So hopefully get back. Thanks.

Thank you. The next question is a follow-up question from Maureen Howe from RBC Capital. Please go ahead.

Thank you very much. I just wanted perhaps a little more color on the reduction in the interest expense perhaps, Russ. It looks like the debt balances were pretty much the same, maybe even a little tiny bit less this past quarter than a year ago. So was that all due to refinancing or lower interest rates, or what contributed to the reduction?

We're just getting the number for you. Go ahead .

Just looking at it here Maureen. I think with regards to the interest going down as, there's a couple factors there. One is that I think we do have some slightly lower rates, but only slightly. There's also a change in the mainline pre-funded debt levels, which have an impact on the corporate on the other side of that calculation. There's also some impacts from our interest rate programs that we have in place. And we had a very small amount of some interest that we had actually capitalized in the quarter on the MacKay River project that we've discussed already.

OK, so just to touch base, the prefunded debt levels on the main line.

Yes.

Can you help me with that a bit?

If you, I think we had this conversation in one of the other quarters with somebody, was as you go through the calculations of your pre-funded and unfounded debt, as you calculate based upon the actual long-term debt you have in place, and the deans equity structure and debt structure that you have, you'll always going to end up with either pre-fund or unfund position, i.e., you either have too much or too little debt. And depending upon whether you're in a pre-fund or unfund position, there is an interest charge or income back and forth between the corporate segment, and that will move around slightly between quarters. And it's not a big impact in any given quarter.

Yes, none of these numbers are material in any way.

Yes, they're, one of each is kind of how you get there.

Because the reduction in the interest expense is like $20 million isn't it?

No.

Oh, I must. It seems ...

You looking at a consolidated basis now Maureen?

Yes.

Well some of that Maureen, I'm sorry I was actually looking at the corporate segment for you, which I thought was where the question was coming from. On the total basis, it's probably going to be somewhat related to the reductions in the debt that we had during the year, if you look at the actual debt balance in the year, most of it's probably going to be related to that. And that's basically in the home pipeline.

And I can go back and check that for you Maureen, because what I'd want to do is look at the debt balances in place through the first quarter of last year. We were paying debt down throughout the year, so I'd go back and look at the debt balances for you. I don't have them at my fingertips essentially through the first three months of last year compared to this year.

OK.

Yes. And I'll give you a really good explanation for the corporate segment on the ...

girling I apologize. That's what I thought you were referring to as well.

OK. Thanks a lot. I'll touch base with David.

Thank you.

Thank you. The next question is from from National Bank Financial. Please go ahead.

Thank you. Regarding PNGDS, what is the, what was the net income effect of the one time bump in the first quarter?

Three million, wasn't it?

Are you talking just about the depreciation one time?

Yes.

Three million.

Was there anything else that is non-recurring?

I think as I have already discussed with one of the other people on the line, we do have this difference on the first quarter in the tariffs between first quarter 2003 and first quarter of 2002, which if you want to call it a one time event, will only occur in the first quarter of this year where we have higher tariffs this quarter, this year versus the second quarter of last year. So essentially that is a one-time event as well in 2003.

Yes. I meant to ask you about adjusted net income effect of the higher tolls.

It's about three million as well.

Three million as well?

Yes.

OK. A housekeeping item, at the beginning David said that TransCanada has no obligation, undertakes no obligation to update forward-looking statements as events unfold. Is that actually consistent with the notion of current or prompt disclosure?

I would say that it is, . Obviously if there was a material event that would occur to the company, the company would be obligated to disclose that and we would do that through the correct disclosure channels.

OK. Glad you're clarifying that. Thanks.

The other question I have is where are you at now looking at the potential pipeline acquisitions? I'm not talking about northern pipelines now but Brownfield, if I may use the terms, pipelines. Where are you at in the process right now?

Well, , it's Hal here. You know, we've looked at many interesting opportunities in the U.S. And one of the unfortunate realities right now is that there's quite a few companies that you might think should be selling price and I read different commentators talking about North America being awash in pipelines that are for sale. We don't, in fact, find that's the case.

For most of the companies that are in financial distress, the pipeline assets are the best assets they have.

Right.

And if they sell them, their flirtations with bankruptcy get worse, not better.

So that's really in a nutshell where we're at. We've looked at a lot of really attractive opportunities and you know you hear different stories like some pipelines being pulled back because there were no acceptable bids received. I suggest maybe there are sometimes other reasons why people don't go ahead with those.

Yes. And in connection with pipe, potential pipeline acquisitions, I sort of saw Russ maybe wringing his hands about credit metric as he mentioned a little bit earlier. If he's worried about credit metric, how can you actually afford any pipeline acquisition, unless you use 100 percent equity?

Well it depends what the capital structure within the pipeline is that we're acquiring. If we are acquiring a pipe that's got a huge amount of depth related to it, we'd have to - we'd have to use all equity. And we'd be inclined to do that.

We have, as you know, , about a billion dollars after dividends and maintenance capital for capital spending, which we could use to, it depends how we look at that, as being, you know, pretty close to being meaning all equity as well we have insured that we have access to capital markets for the right kinds of opportunities. So, you know, to the extent that an opportunity required more equity and it was a good opportunity for TransCanada, we believe that the capital markets would be available to us.

What sort of disturbs me a little bit is if you were to use 100 percent equity, you were to purchase a pipeline that has been sort of traditionally financed, how could you ever get your cost of capital when the pipeline itself throws up a return that reflects its capital structure, not your 100 percent equity?

Well I think what we look to do is take that pipeline and its capital structure and integrate into our overall capital structure so that if it, for example, had 50, 50 debt equity and we felt that 50, 40 was the right number overall, then we would model it that way so that it would become not just an incremental thing funded totally debt or totally equity. But rather it would mirror our overall capital structure for that kind of asset.

But to the extent that such an animal is regulated, unless you can convince the regulator to move the equity to debt ratio up I still have a problem seeing that you can earn on a pre-tax basis and on an after tax basis your equity cost to capital.

We can and we do. You know we don't have any trouble getting these kinds of things through the modeling. The bigger problem that we have is convincing sellers to sell for a price that works for us.

Yes. That is really sitting on my point.

Yes. I think that's reality out there today is that, you know, people may have expectations of getting a very big multiple of book value for their book equity.

Right.

And, you know, we won't go there if it doesn't work for us from an internal rater return and a creed of earnings point of view.

Because in fact we can achieve those kinds of satisfactory outcomes in power today and as long as we're able to achieve them in our alternative businesses, we're not particularly compelled to do it there.

I'm very glad to hear that you are not discarding your conservative hat. These are all my questions. Thanks very much.

Thanks, .

Thank you. We'll now take questions from the media. If you have - if you are from the media committee and have a question, please press one on your telephone keypad. If you are using a speakerphone, please lift the handset and then press one. Please press one at this time if you have a question.

Once again, please press one if have a question.

And at this time there are no questions from the media committee. I would like to turn everything back over to you, Mr. Moneta.

OK. Thanks very much. Just like to thank everybody for participating this afternoon. We'll talk to you in the not so distant future. Bye for now.