TransAlta Corp (TAC) 2005 Q2 法說會逐字稿

I will now like to turn the meeting over to Mr. Daniel Pigeon. Please go ahead Mr. Pigeon.

-- quarter 2005 conference call. Let me start off by saying that if for some reason we don't get through the call because of the labor disruption, we will schedule as quickly as possible another hour or so in the near future to get through the Q&A part.

With me are Steve Snyder, President and CEO; and Ian Bourne, Executive Vice President and CFO who will participate in the call; along with Ken Stickland, Executive Vice President Legal; and Sneh Seetal, Senior Media Relations Adviser.

We released the second-quarter results earlier this morning I hope you've had a chance to review them. After this call we will post additional operating information on our website. All information provided during this conference call is subject to the forward-looking statement qualification which is detailed in today's press release and incorporated in full for purposes of today's call.

I remind you that the amounts referenced in this review are in Canadian currency unless otherwise stated. In addition, the non-GAAP terminology used in this call is reconciled starting on page 17 of the MD&A. Per-share figures this quarter are based on an average of 195 million shares outstanding compared to 192 million shares last year.

Q2 was a good quarter with earnings from continuing operations of $25 million or $0.13 per share compared to $16 million or $0.08 per share in the same quarter last year. Cash flow was solid in the quarter with cash flow from operating activities of $104 million, up from 86 million last year.

Steve will now provide a brief overview of the quarter followed by a more detailed discussion on earnings and cash flow by Ian. We will then open the call to your questions. Steve?

Thanks Dan and good morning. As Dan mentioned, we had good performance in the quarter. Relative to the second quarter last year, revenues of $621 million were up 5%. Gross margin up 349 million was up 10% and operating expenses of 258 million or up 4%. The net effect is earnings from continuing operations of $25 million, up 60%.

Our plants operated well and on plan. The combination of good availability and successful monitoring of the market by our energy and marketing team enabled us to capture the market upside. Good cost control in our plants and execution on our major maintenance activities also supported the earnings improvement.

In terms of specific operational factors that contributed to our quarter-over-quarter performance I will comment on two important ones. First, the impact of availability. At 84.1%, it was down slightly from 85.2% last year, the result of an increase in the days required for major maintenance. We completed six major turnarounds, three coal and three gas in the quarter all on time and on budget. Last year, in the second quarter we completed three turnarounds, all coal.

This year, we had lower maintenance operating expenses, $28 million versus $33 million last year as well as lower lost revenue on the coal plant turnarounds. The latter was a result of lower prices in the Alberta market where most of the major maintenance work took place in the quarter.

While I am discussing major maintenance, let me make a few comments about the remainder of the year. We previously indicated that 70% of our annual major maintenance spend would occur in quarters two and three of this year. We are still tracking to this goal with a heavy schedule of major maintenance in quarter three. Our overall major maintenance expenditure for the year is now forecast to be in a narrower range of 205 million to 220 million with 65% of this amount being capitalized. Ian will discuss our total capital expenditures in a few minutes.

The other factor that affected the quarter was an excellent result in energy marketing where the team earned $18 million of operating income. They achieved this while continuing to operate well within our VAR or VAR limits. For the balance of the year, we will continue to maintain the disciplined approach we have consistently delivered with our train operation. That means we expect to be within our guidance range of 5 million to 10 million in operating income per quarter for the balance of the year.

I would now like to turn the call over to Ian Bourne, our CFO, to make further comments about the quarter.

Thanks Steve and good morning. We continued improving earnings in the second quarter and I would like to discuss the trends and some operating highlights followed by comments about cash flow capital expenditures and our liquidity position.

Gross margin in the quarter was $349 million an increase of $31 million or 10% over the same quarter last year. The increase is a result of higher energy trading margins and lower impact of major maintenance. As well, contribution from Genesee 3 more than offset decommissioning Wab 1 and 2 at the end of last year.

Operating expenses at $258 million were up $11 million or 4% over the second quarter last year. The addition of Genesee 3 added 6 million to operating expense and there were no other noteworthy items. The details of interest costs are shown on page 12 of the MD&A.

Let me summarize. While gross interest charges declined 8 million quarter-over-quarter due to lower overall debt and lower interest rates, interest expense on the income statement declined by 3 million. The $5 million difference represents interest that was capitalized in the second quarter last year. We expect to continue our trend of reducing interest cost in the second half of this year compared to the second half of last year.

I will now move to income taxes. The effective tax rate of 26.8% was in line with our guidance of 25 to 30%. You may recall that last year the tax provision reflected a $7 million tax recovery from our New Zealand operations. Net of the recovery last year, the effective tax rate was 26.3%.

I would now like to discuss cash flow, CapEx and liquidity. First, cash flow from operating activities at $104 million was up 21% from last year when it was $86 million. The major difference is the improved operating earnings.

Capital expenditures in the quarter were $105 million compared to 80 million for the second quarter last year. The $105 million was related to major maintenance and mining equipment. The capital expenditure forecast for the year continues to be in the range of 360 to $375 million including 130 to 140 for major maintenance, about 45 for growth initiatives, the remainder for mining equipment CE Gen (ph) and productivity initiatives.

I will now describe progress on our credit metrics. As we have indicated in the past, we are working to achieve BBB+ credit metrics by 2007. Cash flow to interest for the rolling 12 months ended June 30 was 4.4 times versus 4.1 times at December 31 '04. Cash flow to debt also improved from 19% at December 31 to 20.6% at June 30. Our debt to total capital ratio of 46.1% was within our target range and was essentially flat with year end.

In February, we redeemed $300 million of preferred securities using short-term debt. Year-to-date we have paid down $36 million of debt and we expect to pay down more debt using operating cash flow in the second half of 2005.

We have $330 million of long-term debt with a weighted average interest rate of 6.6% coming due around year end. We are considering a debt issue before year end to roll the majority of it over at less than the 6.6%. The result of reducing debt, redeeming the preferreds and rolling over some debt at a lower rate will be to improve our coverage ratios and reduce interest expense.

As well during the quarter, we met with our three credit rating agencies for the annual review of strategy and our five-year plan and we renewed our $1.5 billion credit facility for a committed three-year term.

On another subject, please refer to page five of the MD&A where we have described the treatment of our Mexico plants with respect to the variable interest entity accounting standard.

I will now turn the call back to Steve.

I would like to just make some brief comments on two items of interest and with that we will open up the call to questions. Let me start with our Centralia coal plant. Our plans to recontract Centralia at prices higher than the original contracts as they roll off are advancing steadily. We are receiving increased interest among potential customers.

You will recall that we have 400 megawatts expiring at the end of this year, 100 at the end of next year, and 400 at the end of June 2007. As you know the pricing on the legacy contracts is in the U.S. $30 per megawatt hour range. In our investor presentation last week, we showed the Mid-C forward curve for the year 2008 with power prices in the U.S. dollars $50 to $55 per megawatt hour range.

As we renew or enter new negotiations, we want to blend contract length, terms and conditions and price to balance our total portfolio of contracts. This will take some time and planning but we are on track to achieve these goals.

As we have discussed on previous occasions there are industry driven inflationary pressures on coal mining costs such as fuel and large truck tire availability issues. With their Alberta PPA plants the increasing costs are borne by the offtaker through the PPA mechanics. At Centralia, we must count on improving operational efficiencies in our mine operations. Although these new external pressures are eating into the savings achieved over the last four years, we are making good progress on finding offsets.

As indicated in our investor presentation of July 12, our goal is to keep our long-term per ton costs at or below the cost level when we purchased the mine. Meanwhile, pricing levels in the Pacific Northwest are reducing the impact of mining costs.

The other item of interest is Sarnia and further to our press release of June 15, I am pleased to report that TransAlta has begun negotiations with the Ontario Power Authority on a contract for Sarnia. Once the contract has been completed, it will be submitted to the Ontario Energy Board for approval. The Ontario Energy Minister, the Honorable Dwight Duncan, has demonstrated a strong commitment to develop a balanced solution for early mover generators like TransAlta and for the Ontario ratepayers. There is still much work to be done in the Ontario electricity market but it is a market that needs new generation and I believe it is moving in the right direction to encourage investment.

In summary, I expect the business drivers we saw in the first half to continue in the second half. These are good plant performance and cost control, on time and on budget execution of long-cycle maintenance work, steady progress on contracting Sarnia, and recontracting Centralia and good market conditions.

We will not turn the call over to Dan and we will move to the question-and-answer period.

As we open the call for your questions we will take one question with a follow-up at a time and rotate through the callers. We will answer questions from the investment community first and then open the call to the media. We will then respond to Web based and individual investors so please identify yourself when asking a question.

I will remind you that we do not provide guidance and that we will answer your model-related questions off line after the call. Maggie, we can now take questions.

(OPERATOR INSTRUCTIONS). Maureen Howe, RBC Capital Markets.

The first question I have relates to -- I'm just seeing which page it is here. I think it is on page nine -- page ten, sorry. It talks about these real-time purchases in energy marketing and that there is a $9.7 million decline I think it is on the power purchase side because of the termination of this service agreement. Can you give us a little more insight into that?

Maureen, it's Ian. We had a contract with a customer whereby we were scheduling some power for that customer. We physically took title to the power and then on sold it. And that contract expired at the end of April this year.

So it declined or it decreased -- I'm just looking for -- it decreased -- the purchase power I believe, but was there not an offset on the revenue side?

Yes, there would have been and in effect what you are seeing in the margins in the second quarter this year is a higher margin from the straight trading operations because both the sales and the cost of sales on that other contract are not in the numbers in the second quarter this year.

So there wasn't (multiple speakers).

It was a pretty thin margin piece of business.

So there wasn't really an operating margin impact then?

Nothing of consequence.

And then just my follow-up question, Centralia you talk about a $4.1 million increase in the coal costs. Can you tell us what that was on a per megawatt basis?

Maureen, can I get back to with that one later?

Sure. I'll get back in the queue.

Matthew Akman, CIBC World Markets.

Just staying with energy marketing -- good results in the quarter. I'm just wondering how much of this is a marked-to-market and I guess does that I guess should be realized short-term but do you expect that mark to sort of move around over the course of the year?

Matthew, it's Ian. If you look at the MD&A on page 10, we have got some marked-to-market information. It's about $20 million in the quarter and yes, you are right, that does move around from quarter to quarter to quarter. But recognizing that we do continue to have very short-term on most of our trading activities, the likelihood of a major discontinuity is not very high.

Can you just maybe expand on what those are? Are those sort of transmission contracts for the most part that are just sort of one year or shorter deals?

No, they are really a variety of trading positions, as I say in relatively short duration. So their market moves during the quarter.

I guess just one follow-up on this is a quick one on Australia. There is a reference on page 16 to expanding Australia. Is that something that's significant or very small or can you give us any more details on that?

Matthew, it's Steve. It's relatively small. It's really in response to two things. Our customers are increasing the size of their business in the mining operations obviously for sales to Asia and it also gives an opportunity to replace a diesel fuel source with a natural gas fuel source for a potential longer-term cost savings.

I'd like to make one comment here just for the callers. I understand -- I got a note during the call that some of our callers may have had a bit difficulty getting into the call maybe a bit late. We apologize for that and hopefully you haven't missed too much of the conversation. Does that answer your question?

Sam Kanes, Scotia Capital.

It's an accounting question about the 14.2 million of prepaid expenditures you have taken during the first six months. I'm just curious if this is to do with equipment I guess preordered in the future? Have you capitalized your expense that -- what is the split between Q1 and Q2?

Which page are you looking at Sam?

I'm looking at 14.2 million. I'm not sure which page that is but you reference that have prepaid 14.2 million for the first six months of '05 for future maintenance expenditures.

That would be in fixed assets.

It would be. So it's 100% fixed assets?

Yes.

Just the way it was read, I was kind of confused.

In effect Sam, it's the sort of long lead time items where you have to buy -- either buy them or put the order and some payment down in advance of taking delivery of the equipment itself.

My brief follow-up has to do with the Sarnia plant. Is there anything fundamentally different so far as to what the government would want with that plant relative to the new plant proposals that they approved for Mitsui/Calpine in the same area?

Sam, it's Steve. No, essentially the way the OPA is looking at this is they asked us to take a look at how the contracts were structured for the new generation; take that as a basis; adapted it for an existing plant which is already partially contracted but use that as a basis. That is still the basis for the current discussions going on with the OPA.

Andrew Kuske, UBS.

I was just wondering on your success and hitting some of the intraday volatility in certain markets in particular Ontario, if we do look at the spark spreads really on average basis or just average power pricing, it looks relatively weak. But if we look at some of the intraday volatility, prices have been robust at times. So I'm just wondering what success you've had in hitting those peak prices?

That was a contributor to what we did in the quarter, Andrew. We don't go sort of that deep into the detail in terms of our disclosure but yes, that was a factor in the mix and we were successful in doing some of that.

Is that mainly what you booked through energy marketing or did that come through the generation side?

That would come for energy marketing to the extent that it wasn't directly related to Sarnia. Anything that was directly related to the plant would show up in generation.

So effectively, you're just turning around the asset itself and taking separate positions?

Yes.

And then if I just may with one extension question. If we look at the Ontario market and just natural gas supply into that market, especially with your Sarnia facility, what is your outlook on natural gas coming into the market in supply sources?

Sorry Andrew. Say that again please?

What is really your outlook on your natural gas supply into the Ontario market? Especially if you look at the life of the plant, what is remaining and you look at the proposed build with it in the province. How do you see your sources of natural gas? Where is it going to be coming from? Who would you like to lock in long-term contracts with?

It's Steve here. We don't see quite frankly any supply issues, certainly for the Sarnia plant for the current customers we have that gas contracted from to match (ph) our obligations to them. And then once we sort out the Ontario situation, the rest of it will balance out at the same time. So we don't think supply will be an issue. Price will always be an issue, but not supply.

Winfried Fruehauf, National Bank Financial.

Thank you. Would you have an overall availability number for both the first quarter and the six months if you exclude the Poplar Creek and Sarnia plants?

I think Winfried, we can get you that. That is not something I have off the top of my head but we can certainly get you that separately.

It would certainly go up.

That's what we would expect. Now with respect to major turnarounds the capitalized portion of major turnarounds, are you in the habit of recording an allowance for funds used during construction?

No, we do not capitalize any interest on those, Winfried. We do -- we capitalize interest if we are building a new plant, but on major projects like turnarounds and so forth, we don't capitalize any interest.

Linda Ezergailis, TD NewCrest.

This is a follow-up question to Andrew's with respect to natural gas supply in Ontario. My understanding of the RFP winners in Ontario is that there is a little to the disconnect between the dispatching on the electricity side and the procurement of natural gas on the fuel side which could in some situations result in substantial call it spark spread risk for want of a better term. But there is certainly an asymmetry there. Is -- now you have mentioned that you're adapting the contract from RFP to your existing plant. Is that a topic of discussion or will you be assuming that risk as well?

Linda, it's Steve Snyder. The specific discussion with the OPA will be how to manage the gas risk and how to share that between the two parties. And that is in the process of discussion. I would not necessarily assume that what was -- not everything that was in the original RFP are going to be applied to our plant but the structural -- the structure is. So we will deal with the gas issue separately with OPA and that is an ongoing discussion as we sit here today.

So what I'm hearing you say then, substantially the main risk that you might be taking on in this contract would be operating risk and nothing else?

That is the intent is that essentially we assume operating risk on the plant.

Juan Plessis, Canaccord Capital.

At your investor’s day last week, you gave guidance of about $0.70 to $0.80 in EPS in 2005 based on assumed spot price of $47 per megawatt in Alberta and 39 in the Pacific Northwest. You also mentioned that for a $1 increase in the average spot price annually, you could increase your after-tax earnings by about $0.05 per share. Given where prices average in the first half of the year, this is up about $1.50 from your assumption in Alberta and about $4.5 from your assumption for Mitsui. If these average prices continue through the year at these levels, would this then imply about $0.15 in earnings above this $0.70 to $0.80 guidance?

Juan, I think you are connecting a couple of dots that shouldn't be connected. The $0.70 to $0.80 in that chart while it was characterized as '04, '05 was really intended to show where we were in the cycle as opposed to a point in time. And the guidance on sensitivities was relative to sort of base running rates of the business. So you can't draw that connection as it relates to 2004, 2005. That's more intended for the medium- to longer-term part of the cycle that we're going into.

Okay. And as a follow-up staying with power, in the current outage environment and high-priced environment in Ontario, is Sarnia being fully utilized?

All I can say -- there is -- we're going to post that production summary on the website afterwards as you know so you'll have that information. I would say, Juan, that it is increasingly being utilized and particularly during the summer months.

Karen Taylor, Equity Analysis (ph).

Just a couple of questions on the Mexican facilities. I just want to make sure that I am looking at this. How much was the debt because I think you restated the '04 numbers. Is that right?

Yes.

How much was the debt that we pulled off the balance sheet? I just didn't have a chance to check it.

Let me check, Karen. I think it's about 145 U.S.

And that was Chihuahua not Campeche?

That's in Campeche. All of the debt on Chihuahua is intercompany. So it would have been eliminated on consolidation. I think I misspoke when I said 145 U.S. -- that's 145 Canadian.

So when you do your little chart in the release that shows the debt and the economic asset that is still at risk and I apologize, I don't have the release open to the page -- it does show that substantially all of the asset value is still in the sense on book. Is that fair because the debt --?

I think if you look, it's on page five on the MD&A. If you look at Campeche, the ownership interest is $93 million give or take $0.05 and Chihuahua is 326. So yes to the extent that the non-recourse debt in Campeche comes off our investment but the intercompany debt in Chihuahua stays on our balance sheet -- in effect stays on our exposure.

So when I'm looking at these performance metrics and everything because in the generation segment we are showing a $3.8 million contribution from now these two plants, right? They are no longer included in the total production numbers or anything else? And the cost of the intercompany debt, is that in or out of your total interest cost?

That would be consolidated out. In other words there would be an intercompany elimination on that so it wouldn't show.

So it's completely sanitized then for these two plants? Is that right? If that is the right word? Meaning it is just completely not in there.

Right.

Okay. Now you own 100% of those plants, right?

Correct.

Can you just explain to me why we're not accounting for CE Gen the same way given the structural similarities?

I would argue, I guess, Karen, that they are not similar. I think the rules around variable interest entities are sufficiently sort of specific and we went through a fair amount of debate with Ernst & Young over the quarter and concluded what we concluded. Whereas in the case of CE Gen, it's a 50-50 venture. We own clearly half of it. It does not get into the variable interest entity considerations because of the way the contracts are structured and so forth and so on. So they are not the same kind of problem as it relates to the interpretation of the accounting standards.

So the tolling agreements that exist on the assets in CE Gen, how do they differ from those on Campeche? Just break it down to the simplest concepts that would make one inappropriate variable interest treatment and the other that wouldn't. I (multiple speakers).

I think Karen, the other big issue here is that in fact within CE Gen, there are a number of facilities, a number of entities and a number of tolling agreements. In Mexico they are dedicated. That is part of the issue around variable interest entities. So we can go through more of that detail off line if you want but that is the essence of the difference.

May I ask just a quick follow-up?

No, I think Karen -- sorry, Karen, that's two questions. We'll have to ask you to get back in the queue.

Linda Ezergailis, TD NewCrest.

Thank you. Looking further to the Mexican plant equity income, the year-over-year $4.2 million difference is that all foreign exchange related which is fully offset somewhere else at the corporate level? Because that's all -- you've hedged all of that exposure, right?

Yes.

At a consolidated level. So is there anything else going on in terms of improved availability or something driving the year-over-year increase or is it all foreign exchange which is offset somewhere else?

No, there is some benefit from operations. You may recall there were some startup issues on availability in Mexico last year and because of the nature of that contract where it's a rolling twelve-month availability, we are in a stronger position on that this year than we were this time last year.

So would it be half and half or is it the majority foreign exchange a little bit less availability?

I don't have that off the top of my head, Linda.

I guess what I am asking is, looking forward, how might that trend based on the movements in the peso versus Canadian dollar versus changes in (multiple speakers).

The peso is not a factor, Linda. We're paid in U.S. dollars.

I'm sorry, U.S. dollars.

We're paid in U.S. dollars. So to the extent you know there is any issues on foreign exchange it's essentially Canadian/U.S. dollars (multiple speakers).

So how much of that year-over-year variability I guess prospectively would change with changes in currency versus availability? Like is there further upside with more availability because we're not getting those operating statistics anymore for those Mexican plants, are we?

You'll see those operating statistics on the website in terms of the plant by plant stuff that that we --

Okay and how much variability in earnings would there be?

Linda, I think that's getting closer to the guidance than I want to get. So I'd rather not go down that path.

Okay.

Winfried Fruehauf, National Bank Financial.

It's on page 20 of the release and the question relates to the dividends on common shares and I am wondering what caused the large reduction quarter-over -- or year-over-year from 33.5 million to 2.6 million in the last quarter?

It's a function of when the cash moved, Winfried. We will end up with two dividends in the third quarter because the payment date was July 1, July 1 being a Friday, the money actually moved on Monday instead of Thursday. So it's really just a timing of when the cash flows.

So you earned a little bit of interest for a couple of days?

Yes.

Yes. That will make a major contribution to our third-quarter earnings I'm sure.

Hopefully save my earnings estimate for this year. Thank you.

Maureen Howe, RBC Capital Markets.

With respect to interest expense, there was an increase -- and this is really more to do with debt I suppose -- there was increase in short-term debt from 34 million last year to the current balance of 275 million. I'm just wondering in total what is the floating or variable rate debt that you currently have?

We keep it in the sort of 30% range.

Are you comfortable with that in light of what appears to be pressures on short-term interest rates going forward from here?

We look at that sort of very regularly. We've got a range within which we operate. Right now we're kind of a little bit beyond the midpoint on that range and we look at what we think is going to happen on interest rates and make those calls from time to time.

Okay. So I'll take that as a yes. And did Big Hanaford run? I mean, not even so much during the quarter but is it running now? Because it looks like we're looking at some pretty robust spark spreads down in the Pacific Northwest.

It is running, Maureen. It's Steve. And it did run a small amount in the second quarter.

Winfried Fruehauf, National Bank Financial.

In the second quarter in terms of a little bit of complicated with respect to the dividend question I just asked, but what was the amount of dividend reinvestment?

Well I guess it doesn't -- I mean it's in that 40% range still, Winfried.

Do you expect 40% to change in the second quarter upward?

Not materially. I mean that number stayed pretty constant.

But it seems to be a little bit higher than sort of what we had seen in more recent years like on 35%.

Winfried, it's Dan. Can I get back to you on that? Just so we get the right number there. You are right. We average or range sort of between 30 and 35, so let me get the actual number for you. Okay?

Thank you. That's all.

Maureen Howe, RPC Capital Markets.

Now this is just clarification on what is going on on the maintenance side. For the three-month period, there was lost production of 1444 gigawatt hours and that is up last year. The expense maintenance was actually down by about 4.8 million I believe but on page 9, we talk about the contribution to gross margin from reduced maintenance and lost production of 16.8 million. So presumably the difference between the 4.8 and the 16.8 is lower lost production costs although lost production was actually up. Is that just the difference between lost production on coal plants versus lost production on merchant gas plants in Alberta?

Let me try to answer the question a little differently, Maureen. If you look at that page 9, what you will see is that the lost production in the coal plants was actually lower than it was last year and the lost production in the gas plants was higher. The impact on revenues on the gas plants is usually pretty modest because of the way we structure the contract. It is in the coal plants and it is particularly in Alberta where we have to buy the replacement power that that becomes a factor. So the second quarter this year had lower lost hours in coal and the cost per replacement hour was actually down a little bit.

And in terms of the marked-to-market earnings, is it correct to say that there was 20 million in marked-to-market earnings and all but 7.2 million were based on quota prices, the 7.2 was based on models and they represent the financial transmission contracts in the gas power spread option contracts?

Yes that's correct.

Linda Ezergailis, TD NewCrest.

This is maybe a bit of a detailed modeling question, but is it still reasonable to use 25 to 30% income tax rate long term?

Yes.

I guess you guys are trending at the lower end of that for '05? And can you give us an update as to your perception of when you will become substantially cash taxable?

We're out a few years. I'm not sure if we've actually given a year before and I don't have it off the top of my head but it is out awhile. In other words, no substantial change in the immediate term on cash taxes.

I was wondering given the robustness in the Pacific Northwest power prices or whatever. Thank you.

Karen Taylor, Equity Analysts.

Just a quick question on the EM&T. We did 18.4 million during the quarter in EBIT and on the funds flow it looks like we are deducting 4.1. So is it fair that the cash flow from that segment was 14.3 million? But the earnings contribution exclusive of that marked-to-market was in fact EBIT negative?

I don't know, Karen. That is a number -- those are a couple of numbers that need more scrutiny than I can give (multiple speakers).

Let's work off line on that one, Karen.

Can you just talk then -- so what we have recorded year-to-date -- I don't have it again open at the right page -- but obviously the sum of the two quarters is now historical and we're sticking to the 5 to 10 million in guidance for the (indiscernible) two, our estimated contribution from that segment the last two quarters of the year, is that correct?

Right.

Okay and can you -- I know you've answered the question once for Matthew, but just as a follow-up, can you just give us some light on where that 20 million came from? If you are short again, I'm assuming short means less than 18 to 24 months and it's not the transmission contracts where we have gone to 11 and change million of megawatt hours? Can you tell me where that 20 million is coming from?

It's coming from all the markets in which we are operating, Karen. We had a pretty solid and well distributed set of trading results in the quarter. Some quarters you have more success in some markets than others. It was pretty well distributed this quarter.

And that will be turned into cash. What is your definition of short-- I guess is the other answer that I'm trying to get to.

Under about 90 days. In that sort of 90 day and less period.

So the opportunity for a repeat unless you go out and sign new contracts and the market goes your way, it would be sort of an extraordinary event. I'm not going to normalize for this, but I'm just trying to get an indication of -- we have had some very large market moves with prices here in Ontario because of weather. This isn't something that you want us to factor in, I guess?

No, Karen. Steve here. My sense is that we put the quarter in perspective on trading and marketing as one of those things that happens. We're fortunate it happens every 10 quarters or something and we will take it. And you know, probably every 10 quarters we will get one that goes the other way on average. That's why we continue the use of 5 to 10 and the total year as probably the best guidance I think on that. And I would use a total year. Quarter-to-quarter can vary a bit but the total year is generally pretty tight around that 20 to 40 range.

And I just want to make sure that you're not taking bigger bets even though there is a short VAR on this thing to realize 20 million in one quarter that matures in the 90 days, you are absolutely certain there has been no change in the risk management.

Absolutely certain that just everything just worked in a market that was quite good for trading and we were fortunate and we took advantage of it. And it's simple nothing more sophisticated than that. All the VARs, everything, the disciplines remain intact and that's why we continue to give guidance in the 5 to10 range for the quarter going forward.

Winfried Fruehauf, National Bank Financial.

My question is on depreciation page 19. How much of the increase between the second quarter of last year and this second quarter is attributable to Genesee 3?

All of it.

All of it? And could you reconcile maybe the difference between the six months of depreciation and amortization of 182.3 million and the difference between the accumulated depreciation for the same period of one 139.8 million?

There's some FX stuff in there, Winfried. Maybe, again that may be something we can go into with a little more depth off line.

Sure. That's fine. That's all I have.

Sam Kanes, Scotia Capital.

Steve, back to the Sarnia plant for a second, what you stated was that you had contracted some of that plant. Is that just what you referred to the original steam contracts and no gas contracts of any kind?

Correct.

There are currently no questions holding in the queue.

Maggie, it's easier on this time that we open the call to media questions as well.

(OPERATOR INSTRUCTIONS). There are still no questions holding in the queue at this time.

Okay. We also have none on the website. So I would just like to thank everyone for joining us this morning. Of course I will be available as the others for calls after this call. Thank you.

Ladies and gentlemen, thank you for participating in the TransAlta second-quarter 2005 results conference call. On behalf of myself and the rest of my teleconference team, thank you for choosing Teles.