TransAlta Corp (TAC) 2006 Q1 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the TransAlta first-quarter 2006 results conference call. I would now like to turn the meeting over to Ms. Jennifer Pierce. Please go ahead, Ms. Pierce.

Thank you, Aggie. Good morning, everyone. I'm Jennifer Pierce, Director of Investor Relations. Welcome to TransAlta's first-quarter 2006 conference call.

With me this morning our Steve Snyder, President and CEO; Brian Burden; Executive Vice President and CFO; Ken Stickland, Executive Vice President, Legal; Marvin Waiand, Vice President and Treasurer; and Sneh Seetal, Senior Media Relations Adviser.

The first-quarter results were released early this morning and I hope you've had the chance to review them. Additional operating information will be posted on our website after this call.

First-quarter 2005 has been restated to account for changes in policy for deferred stripping costs and to deconsolidate Campeche. All information provided during this 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 12 of the MD&A. Per-share figures this quarter are based on an average of 200 million shares outstanding compared to 195 million shares last year.

On this morning's call, Steve will provide a brief overview of the operating results in the quarter, followed by Brian, who will offer more details on operating expenses, cash flow and balance sheet items. Steve will then provide an outlook on the second quarter of 2006 and the year ahead. We shall then open the call to questions. Steve, please go ahead.

Thank you, Jennifer, and good morning everyone. I'd like to welcome Jennifer to our team and her first conference call with you. I think many of you may know Jennifer from her positions with NOVA Chemicals and Duke Energy.

I would also like to take this opportunity to thank Dan Pigeon, who did a super job during a period of great change for our industry and our company. And Dan is now heading up a new group within TransAlta responsible for overall portfolio strategy and execution.

This morning I would like to outline for you the three key items I think you should take away from the call regarding our first-quarter results. First, availability was up 3.5% over the comparable quarter due to excellent execution within our plant operations. Second, gross margins increased as a result of stronger pricing, higher availability, our contracting efforts and marketing's focus on day-to-day optimization opportunities. And third, our financial strength continued to improve as we increased cash flow and reduced our debt.

From a financial overview perspective, first-quarter net earnings increased by 40% or $20 million to $69 million from $49 million in the first quarter of 2005. On a per-share basis, earnings increased 40% or $0.10 to $0.35 per share in the first quarter of '06 versus $0.25 per share in the first quarter of 2005. On a year-over-year comparable basis, first-quarter 2006 earnings per share we $0.38, excluding the $0.03 earnings per share turbine impairment charge.

Cash flow from operations increased by 34% or $51 million to $200 million from $150 million a year ago. Brian will provide more details in his comments.

Our operations benefited from good, but not great, market conditions. Electricity prices and spark spreads, particularly in Alberta and the Pacific Northwest, were reasonably strong in January and February, but began to trend downward in March due to softer natural gas prices, fewer industry outages, lower heat rates, and of course, excellent hydro availability.

Against this backdrop, TransAlta's gross margins increased 12%, or $42 million, to $394 million in the first quarter of 2006, and that compares to $352 million in the year-ago period. Key drivers of this gross margin improvement included improved pricing and contracting across our fleet, which contributed revenue of $60 million; increased production from Alberta thermal assets contributed revenue of $17 million; and incremental production from Genessee 3 contributed revenue of $16 million.

Offsetting these improvements were, first, derates at the Centralia coal plants, which were done to build coal inventories, that reduced gross margins by $29 million. The actual derates at the Centralia coal plant were 850 gigawatt hours, in line with estimates of 650 to 950 gigawatt hours provided in our fourth-quarter call.

The other area offsetting these improvements were higher costs of coal at the Centralia plant, which reduced gross margins by $18 million. As we discussed in our fourth-quarter conference call, we anticipated Centralia coal costs would rise year-over-year due to increases in the cost of labor, diesel fuel, trucks and tires, as well as the maturity of the mine and the related levels of overburden.

We expect costs for the balance of 2006 to be similar to the first quarter. These cost considerations have already been built into our recontracting negotiations for 2007 and beyond. In the meantime, we will be driving cost reduction initiatives throughout 2006 to try and further offset these inflationary pressures.

On the whole, our first-quarter results reflect continued progress towards achieving key operating metrics. Plant availability was over 96% due to few planned and unplanned outages. Our annual target is 90% plus.

We now have contracts in place for upwards of 90% of our output in 2006 that will reduce our exposure to volatile commodity prices. Our target, of course, is to have over 75% of our output contracted.

And gross margins increased year-over-year, primarily as a result of higher prices in January and February, increased availability, enhanced pricing achieved through contracting, and continued focus on asset optimization.

While these are solid results, we remain committed to achieving the targets in all six of our key measures. These areas of focus include improving productivity per megawatt hour, achieving predictability of our capital expenditures and cash flow, and strengthening our balance sheet and financial ratios.

As you are aware, over the last several years, we have focused our conference calls on our major maintenance spending and plans. We saw this as an important area for developing a competitive advantage and for driving productivity improvement. It was important to keep you informed of our plans and progress, especially as we were increasing our spend to achieve these goals and the nature of the spends is lumpy and therefore hard to forecast externally.

We will continue to provide you with this key data. But we also indicated in our January conference call that we would provide a broader overview of our total Company capital spend on a go-forward basis. In this regard, I would like to note that our 2006 capital plan is to spend between 260 and $275 million.

It is allocated into two categories, sustaining and growth. And within sustaining capital, we have two subcategories -- the first is major maintenance. That is the cyclical turnaround expenditures we've spent a lot of time talking about the last conference calls. For 2006, our estimate remains at 100 to $110 million.

The second area is routine maintenance and systems. These are the regular expenditures on plant equipment, minor repairs in infrastructure, as well as investments in information systems in our mine. In 2006, we estimate these expenditures to be 140 to $150 million. Of this amount, approximately $45 million is allocated to our mines in Alberto and Centralia.

The profile of our mining investments is more variable, as expenditures for items such as trucks and shovels differ year-to-year. When it is significant, as it is in 2006, we will identify that for you separately. At this point in time, we've only set aside 15 to $20 million for growth initiatives. Increased focus in this area will come in future years.

I would like to note that these estimates exclude our Mexican plants and we anticipate capitalizing approximately $15 million for major maintenance in Mexico this year. And the gigawatt hours of lost production is estimated at 300.

I will now turn the call over to Brian for his comments. Following that, I will provide comments on our views on the industry trends for the second quarter as well as for the year.

Thank you, Steve. As Steve has said, in addition to the operational targets he discussed, we are determined to deliver against specific financial objectives, such as improving productivity, achieving cash flow targets and improving the financial strength of the Company.

In the first quarter of 2006 compared to the year-ago period, our total operating expense increased 10%, or $22 million, to $240 million from $218 million last year. The key drivers of this increase were depreciation of $12 million and OM&A of $10 million. The majority of the increase in depreciation was due to a close to $10 million impairment charge to write down two turbines held in inventory.

OM&A increased $10 million compared to the first quarter of 2005. Of this amount, generation OM&A was $7 million higher and primarily attributed to incremental expenses from Genessee 3, increased general operating expenses, and salary and wages. Interest expense was reduced $7 million to $41 million in the first quarter of 2006 compared to $47 million in the same period of 2005. The reduction was primarily due to a gain on the unwinding of a net investment hedge, lower debt levels, and the redemption of preferred securities in 2005. Debt reduction was $134 million in the first quarter of 2006 compared to $53 million in the first quarter of 2005.

Income tax expense was $24 million, or approximately $3 million higher this quarter compared to the first quarter a year ago due to higher net earnings. The effective tax rate for the quarter expressed as a percentage of earnings before taxes was 26%. Over the year, we expect our tax rate to remain within the 25 to 30% range that we've talked about previously.

Building on what Steve said about cash flow, the $51 million year-over-year improvement is primarily due to a $34 million increase in cash earnings and the realization of $20 million on settled energy marketing contracts. Our current target is to maintain annual cash flow levels of 550 to $650 million, and we expect to be at the higher end of this range this year.

Capital expenditures in the quarter of $29 million were $8.5 million lower compared to the year-ago period, primarily due to capital spending on Genessee 3 in 2005. During the first quarter of 2006 we spent approximately $8 million of capital on planned major maintenance, basically flat year-over-year. The majority of remaining capital was spent on routine maintenance.

During the first quarter, S&P upgraded TransAlta's credit rating to BBB. Our target is to achieve BBB-plus credit ratios by the end of this year on all three of our metrics, which are cash flow to interest, cash flow to debt, and debt to total capital. By improving our financial condition and strength on our balance sheet in 2006, we intend to exceed cash flow to interest coverage of 4.2 times and we are currently at 5.3 times; exceed cash flow to total debt of 28%, and we're currently at 26.2%; and be below the debt to total capital of 45%, and presently we are at 42.2%. So as you see, making good progress, but just need to do a little more on the cash flow to total debt.

And with that, I will turn it back to Steve.

Thank you, Brian. Before concluding the call and transitioning to our question-and-answer period, I will briefly provide key points around our outlook for the second quarter and the year.

Firstly, as we talked about in the fourth-quarter call, availability and production are expected to decrease in the second quarter compared to both first quarter 2006 and second quarter 2005 due to the scheduling of approximately 50 to 55% of our total planned maintenance expenditures in this quarter. Our turnaround schedule includes a total of four coal plants, one more than in the second quarter of 2005.

Secondly, as it relates to the markets, in the second quarter we currently see prices continuing to move down from the higher levels we saw at the beginning of the year. Relative to our own markets, in Alberta compared to second quarter of 2005, electricity prices are expected to be similar, as year-over-year demand growth is expected to offset increased imports from approved Pacific Northwest hydro supply. Spark spreads are expected to be relatively unchanged from the same period last year.

In Ontario, electricity prices are expected to be higher than in the first quarter of 2006 due to seasonal nuclear and coal generation maintenance. Compared to the second quarter of 2005, however, prices are expected to be slightly weaker, with improved overall supply. And spark spreads are expected to be unchanged to slightly down compared to the second quarter of 2005.

In the Pacific Northwest, current forecasts are for a normal hydro year versus 2005, which was less than 80%. As a result, electricity prices are expected to continue to decline in the second quarter and will be well below second-quarter 2005 levels. Spark spreads are also expected to be lower compared to the second quarter of 2005.

For the second quarter, we have reduced our exposure to downward power prices somewhat through contracting of approximately 90% of our portfolio output. Our Energy Trading group will continue to work through the quarter to reduce our price risk exposure to the 10% of our portfolio that is not contracted.

I also want to note at this point that on a quarterly basis, our expectations remain that Energy Trading will earn approximately $5 million to $10 million of operating income per quarter. In the second quarter of 2005, Energy Trading had an exceptionally good quarter and reported $21 million.

Additionally, in light of very low forward power prices in the Pacific Northwest, we now have the option to be in economic dispatch mode with our Centralia assets. We will take advantage of this opportunity to modify our mining plan to achieve our targeted inventories at hopefully lower costs. At this point, we are now expecting the planned maintenance shutdown for the facility to be in effect for much of the quarter.

And finally, it is clear a significant drop in short-term power prices, ongoing inflationary pressures, especially in Alberta, and rising short-term interest rates create a tough industry operating environment. However, based on our current outlook of market conditions, our ability to execute our planned maintenance schedule, our capabilities to optimize our fleet of assets, and our integrated approach to managing commodity price risk exposure, we should be able to stretch to offset these challenges.

In summary, the first quarter of 2006 was better than the first quarter of 2005 due to a combination of excellent plant availability and good markets for most of the quarter.

The second quarter of 2006 relative to last year will be impacted by a significant shift of major maintenance work into the quarter. We also anticipate our Energy Trading results will be in line with our targeted range of 5 to $10 million of EBIT per quarter. And for the total year, increasingly difficult market conditions will lead us to find offsets as quickly as possible.

I shall now turn the call back to Jennifer.

Thank you, Steve. So that we may rotate through callers, we shall take one question and one follow-up from each caller before moving down the queue. We shall answer questions from the investment community first and then open the call to the media. We shall then respond to the Web-based questions and individual investors. So please identify yourself when asking a question.

I remind you we do not provide guidance and that we shall answer your model-related questions off-line after the call. Aggie, we may now take questions please.

(OPERATOR INSTRUCTIONS) Andrew Kuske.

Thank you. Good morning. Steve, if you could just give us a sense of what is really happening out at Centralia and just some of the mine productivity that you saw in Q1 and how you look out into Q2 and where your coal inventory stockpiles are at this point versus historical levels.

Well, let me just respond -- first on inventory levels, our inventory levels first are right on track to where we want to be in terms of our plan for the year. That is below our historical levels. And I think as you will know, Andrew, probably most coal generators in the U.S. market are running at abnormally low inventories, with just the difficulty of getting coal transportation. But we're certainly not in a danger zone, but we would like to raise it before year end and we will have this opportunity in the second quarter to do that.

In terms of the mine productivity, we were actually getting good productivity relative to the two challenges we face. One is just the higher overburden, and that will continue through the year until we can get into Pit 7 and into our other mines in the future.

The second part, clearly the heavy rains in the quarter had some challenges on the productivity side. But we are through that now and we're fortunate that with our overall fleet, we were able to offset that quarterly challenge.

So net-net, I mean the coal cost this year will be higher than last year and we built that certainly into our forward contracting. The second part of that is that we just need to move into other parts of the mine over the next two years to bring that back in line again.

So just as a follow-up, how do you see your stockpiles building in Q2 when you're essentially trying to cover off some of your contractual commitments just by buying in the open market and not running the plant? Can you just give us a look on how the build should happen for the stockpiles and then what we should really expect into Q3?

Yes. On the inventory, the one good news here on the lower prices, I said, it us this economic dispatch optionality. That will allow us to increase our inventories faster than we expected and without having to use some costly overtime costs to achieve that. So it actually will work in our favor during this period. So we will take the opportunity to build our inventories faster than we would have thought because we are not going to be using that coal. And that will allow us to be in a strong position going into the second half.

That is great. Thank you.

Bob Hastings.

Thank you. Great quarter, by the way. Looking at -- just to get a little more color on sort of what is going on in Centralia, if I might. I guess there's an issue here -- you can certainly buy power cheaper with the cheap hydro prices that we are seeing out there. Accounting-wise, are you actually able to shut down the plant and buy that sort of at whim off and on? Because I understand there's sort of a three-strikes rule and then it becomes you can't account it as a physical delivery; you have to look at financial hedging accounting on that.

We've looked through this, and certainly for the work that we're going to do in the second quarter we have no issues from an accounting base. Obviously, if we did this on a longer base, we'll look into that and make sure there are no issues. But as I say, for our current plans, there are no issues from an accounting point of view.

Okay. So actually, the second quarter for Centralia, given that you're going to be supplying under long-term contracts but buying at cheaper hydro prices, actually is going to improve the profitability from what we saw in the first quarter?

Yes, that certainly --

I think that is -- the net impact is our goal, Bob. That is how we will make the base of the decisions on the make-versus-buy in the quarter. (multiple speakers) slight upside -- not much, but slight upside.

Perfect, thank you.

Matthew Akman.

Thanks. Brian, what was the impact of the change in accounting policy on mine stripping costs?

It was around $0.02 in the quarter.

Around $0.02 in the quarter. But the restatement for Q1 2005 was approximately how much? I don't know if that was identified.

Say that again -- the ?

You've restated Q1 2005 right -- restated back?

Sorry, that was the $0.02.

So $0.02 in Q1 '05?

Yes. Because if you think about it, we had $0.27 that we reported last year, which now been restated to $0.25.

Okay, thanks. And my next question is on cash taxes. You paid over $23 million of cash taxes in the quarter and TransAlta hasn't paid a lot of cash taxes in recent years; it was only $12 million in Q1 '05. Is that an anomaly or is that something that is more ongoing?

It's just -- as you know with cash taxes, you sometimes get timing differences and different things. So we still expect our cash taxes for the full year to be no higher than the 30 to 40% range. So it is a just timing one. As you said, they are much higher in the first quarter. But for the full year, we expect to be, as I said, around that range.

Okay, thank you.

Sam Kanes.

Staying with accounting, your depreciation run rate increase of $12 million, I presume which you just wrote off of 10, that is it, so we can kind of model out to $2 million a quarter going forward this year. Is that correct?

Yes, I think generally. I mean we haven't given direction on what depreciation is, but as you know, with certain amount of fixed assets, I think that is right. If you take out the turbine, the 9.6, $10 million, I think that run rate is going to be broadly in line with that.

Okay. Switching also to accounting in Mexico, the $7.2 million deferred financing you see on your project loan and the repayment of it. First of all, I guess, is that nonrecourse debt in line with the 7.7% in your annual report as the interest rate? And secondly, how does that interconnect with that interest rate, if at all, or was it just a one-shot write-off?

Well, basically, our nonrecourse debt is probably around about the 8% range. And basically, obviously by taking that out, we had some deferred finance charges that we had to recognize in the first quarter because once you start that procedure. We don't expect to finalize the transfer until probably third or fourth quarter.

Q3. And when you do that then, you're just using your balance sheet at your whole coal level to pay that off?

Yes. We'll just use debt of TAC.

Great. Thank you.

Thank you very much. Good morning. Just a couple more questions on Centralia, to try and get an idea of what we might be looking for here. In terms of availability rate for Q2, we haven't got the production summary yet; I guess it is coming. You say it is going to be similar to Q1. So is that going to be in the neighborhood of about 70%, even with the derating?

I am not sure I --

I'm just wondering what the availability --

I think we should take that offline once we've got the schedule and walk you through it.

I guess it raises the question why we don't post the production summary before the call. Is there any reason for that?

Maureen, I think the reason we don't provide that before that call is so that we can have questions that are probably more appropriately answered by Steve and Brian on the call. And then our team can talk plant-by-plant with you after the call.

Okay.

That is the purpose.

Well, let me ask a more general question then and it comes into sort of the economic analysis for deciding whether to physically dispatch or buy. I mean what are some of the factors that come into that? I know when we go back to Q2 2002, which was a similar quarter I guess to Q2 2006 in terms of reservoir levels and prices; I remember you guys saying at that point in time you really couldn't cycle the plant up and down being a large baseload coal-fired plant. So can you kind of walk us through what type of cost is on an average basis throughout the day, is the cost that would lead you to buy power instead of produce power?

And what are the transmission issues, if any, for say just taking the plant offline, and other issues that would go into that decision?

I can talk to it a little bit from a financial point of view. We've done detailed analysis in terms of looking at our marginal cost of producing versus obviously the cost of buying power, and we think the economics make sense. I talked to the operational people and they don't think that there's issues with transmission and they can manage the issues moving the plant up and down. So from an operational point of view and a financial point of view, we think this makes good sense.

Well, that is interesting, but like what are those issues? When they say they can do it, you mean -- can you cycle up and down during the day, can you cycle down overnight and up during the peak hours?

Maureen, Steve here. We can certainly cycle the plant or the two plants or the three plants really up and down. The only issues on that side are the more you cycle a plant, generally speaking, the more maintenance issues you have in the long run. So you do that, trade off on maintenance versus cycling up and down to capture the market, and our asset teams look at that. And I think to Brian's point, the real driver here really becomes our marginal cost of production on any one day, and we make the decision around that.

I'm certainly not prepared to discuss what our marginal costs are or total costs are for that plant. That is pretty competitive information in the marketplace. But the principle is we look at each day at the marginal price of buying and then our marginal costs, and make a decision. And then we look at the cycling up and down and look at the maintenance cost relative to that and the operating parameters, and then the asset teams make a decision, both day by day, week by week, quarter by quarter.

So that is the thought that goes into it. Net-net is where we see the most margin dollars coming out, that tends to be the way we go. But it's not -- unfortunately, lend itself to a simplistic straightforward answer. It's not a formulistic thing; it's looked at on a constant basis.

Okay. All right, that is helpful. Thank you.

Karen Taylor.

Thanks. Maybe I'll try a different question Centralia related. Brian, I guess this is for you. The interest costs of 40.5 million, can you tell me what the net benefit was associated with the swap unwind in the quarter?

It was around $6 million.

$6 million. Is that pretax?

Yes.

And just to confirm, I guess, what we're looking at from interest expenses, so I went through the investor presentations in the fourth quarter and pretty much through the quarter of '05 anyway, we were consistently seeing conversation of about 20 to $30 million of lower debt costs in '06 versus '05, I guess due to lower balances outstanding. And now I think -- I just want you confirm that this is the correct interpretation -- that higher interest rates overall could obviate those benefits, notwithstanding on lower balances?

Karen, it's Marvin here. There is going to be some impact on our interest costs as a result of higher short-term rates.

Yes.

We've got about $900 million of floating-rate debt out here. So you can do the calculations of the change in interest rates there. But we're largely unchanged in terms of long-term rates in the near-term.

Right. So the $900 million, if I could just follow up, does that include then all of the hedges?

That is right, yes.

So basically, that is the amount of the outstanding amount of your debt that is not otherwise hedged or subject to an actual fixed-rate.

Correct.

Can I just ask one strategic question? Then I will get off the line. Can you just explain to me the rationale for investing in the Hawaiian Islands, and do we plan to see more asset acquisitions there?

Karen, let me take that. Very simply put, first of all, the power down there, the hydro down there, would fit every single one of our criteria for making an investment other than the region. And the only reason we made an exception in this case is because of our partnership with Mid-American who is the other half owner in this asset. And they approached us and said they wanted a partner for that asset and would we considerate it.

Since it met all of our criteria for long-term contracts, good return on investment, renewable resource, clearly all of the stuff that we would look for in any asset, we decided to make an exception in this case and work with our partner. So it's going to be a very small but profitable asset for us and one that we do with our partner. We're not expanding into Hawaii, so don't worry about it.

Okay. Well, I guess the question that I have is given I know Calgary is a lot closer to Hawaii than Toronto is, but there is still a significant amount of travel time involved. Can you explain to me how much time this asset is going to take and the value of having such an inconsequential asset that will be in isolation in a geographic area? And does that just does not add another layer of accounting and legal complexity and management time?

No, simple answer is now, this is going to be not a distraction, not going to be -- it's a very simple, small plant, Hydrodamp, runs itself essentially with minimal work. And so that was all factored into the decision and net-net, we believe it is a good investment for our shareowners and will return a very positive return on our (indiscernible) small, but positive including all those factors. We're not going to have tons of people trampling over to Hawaii because of that asset. That is not the reason for it, believe me.

Okay, I will get back in the queue. Thanks.

Dominique Barker.

Just wanted to ask, you talked about the cost pressures in Alberta. Can you just clarify if labor costs actually are passed through on PPAs?

Yes, there is a labor formula. There is requirement for some productivity in that, but essentially most of those are passed through to the PPA process. They tend to lag, but they get passed through the following year.

Okay. And with respect to -- you've mentioned labor issues, I think, at head office and in finance in particular. Is that the only area where you would see increased cost pressure from labor and I guess some mining as well?

No, I think in Alberta it is just general labor pressures, which is putting pressure on salaries, and we just have to work extra hard on the productivity. So I think it is just across the board in Alberta, just the fact that labor costs are going up generally across Alberta market in all segments.

Okay, thank you very much.

Linda Ezergailis.

Thanks. Just wanted get a little bit more color on the sale of emissions credits. How should we be thinking of this going forward? What was the total revenue you realized from that in 2005? How can we think of that for the balance of 2006 and beyond, I guess?

Linda, it's Ken Stickland here. Maybe I can just respond to that. When we look at our emissions credits, remember that we use those typically as offsets against our operations here. So first principle is that it's a risk mitigation tool for us. It fits in with our other strategies in terms of how we approach our overall emissions climate change strategy. In certain circumstances, we may sell a credit in an opportunistic fashion, but it's not the business that we are in, certainly not today. And that is just something that we would continue to pursue on a go-forward basis on that same basis. We wouldn't see ourselves today getting heavily into the emissions tradings business.

Okay. Now this emissions credit, was it related to perhaps not being utilized for Centralia, so can we expect maybe in Q2 to see some revenue from sale of emissions credits as well?

Yes, we're not going to get into the detail on this one, but yes, you will see some emissions credits from obviously the Centralia change in Q2.

And more broadly when I look at your maintenance schedule of coal plants, if we see a few years -- so if we see less coal maintenance next year, we can expect perhaps no sale of emissions credits and then vice versa; is that generally the trend?

No I don't think -- Linda, it's Steve here. I don't think you can draw that conclusion. I think the second quarter was, I think, on terms of Centralia plant, there's anomaly clearly driven by unusual circumstances unlikely to be a reoccurring thing on a regular basis. So generally speaking to Ken's point, we don't look to sell SO2 credits. If it situationally happens that we've got them and they're going to expire, we'll do look at it. But I would say you shouldn't draw any conclusions for '07 beyond on that basis.

Okay. Can you give us a sense of how much, if at all, revenues you realized in 2005 from the sale of emissions credits?

No.

Okay, so it really was anomalous this year.

It wasn't -- was not significant at all.

Okay. And then just, I guess, a process question. Will we be getting on the website your physical and financial gas and electricity marketing volumes? Because you guys used to provide that in the quarterly releases, and then last quarter you said you'd give it now in the quarter but in the annual report. But going forward in all the quarters, you give it and I don't see it, so I'm just wondering what is going on.

No, that is no longer information that we are providing on our website due to competitive reasons in our marketplace.

Thank you.

Okay, thank you.

Brian Purdy.

Hi, guys. I wanted to ask about your power price outlook. In some of the previous quarters you used to mention the -- I guess the hedge position for your merchant exposure in Alberta and the Pacific Northwest. And I just didn't see it in this quarter, though you did mention overall your contracting position. Is there any hedge position there for the merchant exposure in Alberta, Pacific Northwest?

I mean, as always we have certain hedge positions going forward, but I don't think -- again, some of this is competitive information, so we wouldn't be talking exactly about where we hedged and what we hedged for. But yes, we have hedge positions going forward.

Okay. So --.

I think just overall, I think we should go with what we said in the script here, Brian, which was we're -- just slightly over 90% of our output is contracted for the second quarter. And then the rest is going to be dealt with just on a daily or weekly basis.

Okay. So the second quarter about 90% overall?

Right.

Production, not necessarily the merchant production?

Right, right.

Okay. Great, thanks very much.

Sam Kanes.

Steve, with respect to Sarnia and what you can provide us on that side of your contract, which may be limited, I'm just wondering if the plant does not run versus running at 100%, does it make any difference to TransAlta shareholders anymore for five years?

I think the simplest answer, Sam, is with that contract is the way it's structured is that we feel -- I think we indicated would deliver at $0.10 to $0.12 of earnings this year. We indicated at the last call that I would use the lower end of that guidance, and that still exists today. I wouldn't say -- I can't answer your answer directly.

It's a fairly complex contract, so we don't -- it's a full capacity in energy. When you net it all out, I think the impact is marginal whether we go full out or we just go for capacity side. There is a bit of shifting in there, but not dramatic enough to change that forecast for the year.

Okay, that's good enough. Brian, back to Centralia for a minute. Gross margin of $29 million that you referred to you, you were short on the 850 gigawatt hours.

Yes.

If you had to try to extrapolate that into earnings after-tax, could you kind of walk us through what that might have been had you run -- with all else being equal?

You mean in the quarter?

Yes.

Yes, it was about $0.08 to $0.09.

Okay, thank you.

Winfred Fruehauf.

Thank you. I was wondering why the decision was made to hold the analysts conference in September in the desert of Southern California instead of lush Hawaii?

Well, that way Karen can say that we didn't buy Hawaii to go to Hawaii. No, there is nothing in it, Winfred.

Okay. And before I ask my question --.

It's just easier for our hosts down there to manage that timeframe.

I see. Before I ask really my question, you mentioned that availability increased by 3.5%. May I suggest to you that it increased by 3.7%, because 96.9 over 93.4 times 100 gives you -- minus 100 gives you 3.7%?

Thank you, Winfred. We'll get our adding machines better next time.

All right. And I'm just wondering what were the main reasons for the rather anemic performance of marketing and trading in the quarter?

As we've said, I mean the range we projected is 5 to 10, and they were just below that range. I think in this quarter there was probably less momentum in the market and there was quite a bit of volatility. When there is more volatility, then we tend not to trade as much because we're risk averse.

Could you give us some direction ask to how much of your operating income was accounted for by proprietary trading rather than trading around the asset base?

You see we report on our trading, and it is between 5 to 10, and this quarter it was just below 5.

Okay. So was that all physical trading then?

I mean, that is basically how we show in the accounts. We show that the element that is around not related to our assets, and the rest of any work that we do is all related to our assets.

Well, I have to think about that answer, so I'm going to pass for now. Thank you.

Maureen Howe.

Thank you very much. Just a couple pretty simple questions. Regarding this change in accounting, you mentioned what it was for Q1 in 2005. Do you have an estimate for the year, for in 2005?

Basically, it will adjust by -- for the full year it will adjust by $0.07.

$0.07, okay. And the Centralia contracts, going back again, I think in conversations I've had with Dan, he's mentioned that the contracts are shaped through the year and that there has in the past anyway been less contracted volumes in Q2. Is that still true, or are the schedule that you give us, is it flat through the year now?

I think probably it might be better on the detailed scheduling just to pick that up with Jennifer if you wouldn't mind after the call, because there is quite a detail. Basically, it's not changed dramatically since the last call, if that all, and she can take you through that.

Okay, thank you very much.

Linda Ezergailis.

Thank you. My question relates to your Ottawa facility. Just wondering what we can -- what you're expecting in terms of production curtailment in gas resales?

We don't talk about individual plants and going forward on what's going to happen. So as I say, that is our position; we just don't talk about individual plants.

It is really up to our customers in this case to -- if they need the power, we'll supply them. When we don't, then we will look at alternate ways.

So last year I can't recall how much detail you gave in 2005 actual, but what sort of revenues did you realize in total from gas resales from production curtailment?

Again, could we take that offline? Could you take that up with Jennifer, because that's not sort of information that we carry around with. We're looking at this quarter and trying to explain the results. If you wouldn't mind, Linda, could you pick that up offline with Jennifer; she'll give you the background details?

Of course.

Winfred Fruehauf.

Thank you. The dividends on common shares number in your cash flow statement, that is a net number, is it?

What was the question again?

Whether the dividends on common shares in the cash flow statement, whether that is a net number?

Yes, it is. It is net of DRIP.

Okay. Approximately what was the DRIP participation in the quarter and what do you expect it to be for the year?

You like this question, Winfred, don't you? I think it was around the 34, 35% range. That is probably too tight a range probably. Marvin, what was it?

I think it was just under 30%, I think is the number. You are close enough.

It was just under 30, so a little bit lower this quarter.

Well, I have to keep you on the current so that I know what is going on here. And in that connection --.

I'll revise that one for next time.

In that connection, does management intend to recommend to the Board an increase in the dividend sometime this year?

We usually wait till --.

Winfred, that is a Board call, nothing to do with management, and we will not have any comment on that whatsoever.

With all due respect, I know that answer, but I asked you whether management intends to recommend to the Board a change in dividend.

Management has no intentions of anything at this point in time without discussions with the Board.

All right, thank you.

Karen Taylor.

Just two quick comments. Steve, thank you for picking up on my Hawaii question. I wasn't aware of any sort of shareholders meeting in September. So maybe you're -- analysts meeting rather -- so maybe someone could address that.

Sorry, we apologize for that. We did -- normally in the past had it in May, and then --.

No, that is fine.

-- just to accommodate our host, we shifted it. But if we missed you, we apologize.

You are invited, Karen.

Well, we'd find a way to come anyway. Just back to a little bit more serious. I know we will see this in the production schedule, but did Big Hanaford run during the quarter in any way to offset the Centralia losses or derates?

No.

The number of coal and gas units that were taken off in Q1 for major maintenance, was there any?

Minimal, maybe just at the tail end of March. Nothing that would be of significance.

So strictly speaking --.

It's all second quarter.

Okay. In total for the year, I apologize if you have got this someplace or I'd just like an update. How many units of both types will be taken off in total for the year?

In total for the year, we've got currently planned seven coal turnarounds. And I think we indicated that that would be equivalent to about 2300 gigawatt hours in terms of lost production. And again, about 55% in the second quarter, 30% in the third quarter, the balance obviously in the fourth quarter. So I think that is -- we're working consistent to that plan. I mean we will update it every quarter, but right now that is our plan.

And do you have similar numbers for the gas units?

I believe --.

Or just in terms of the number of units equivalent that would come out?

Could you take that up with Jennifer offline?

Yes, I would be happy to do that.

We don't have the gas one. Of course, we have the major one in Mexico which is just coming to completion. I believe the rest are more of what I would call minor pit stops, but we will get that information for you. Somehow I just got the call schedule with me here.

And then just lastly with respect to Mexico, you now have deconsolidated the two facilities completely and there are RFPs going on in Mexico right now. Are you planning to bid into any of those initiatives?

We are looking seriously at seeing if any of those would fit our criteria, and if so we would probably like to participate. We are not at that point yet to make a call on that, but yes, looking seriously at it.

With the nominal CapEx e-plan for growth this year, are you looking at any sort of things that would change that or is this year just completely retrenching for growth in 2007?

I think what we've said is that we are certainly looking at this year to be proactive on the analysis side in looking at this; one of the reasons Dan Pigeon has transferred over to our development group to help us with that. And clearly, we've outlined our priorities. One is up-rates of our current facilities, and we're looking seriously at that.

Then the second would be obviously any facilities within our current geographies and current fuels with renewables being a priority as the next priority on that. So I would say that we're doing the work now and would look at 2007 and beyond for any of those investments. And that is why I've indicated the small amount this year. It's really development work this year, capital in the future.

And that would include the Keephills as well; is that correct?

Sorry, Karen?

The third unit?

Yes, that is definitely being -- we hope to make a decision on that over the course of the next 12 to 18 months.

Thank you very much.

There are currently no more questions holding in the queue. Excuse me, we do have one question from Winfred Fruehauf.

Thank you. What is the total time that you expect to elapse between the date you make the decision to proceed with Keephills and the anticipated in-service date, assuming you make that decision?

I would say if we use Genessee 3 as an example, we are probably four years, three-and-a-half to four-and-a-half years, Winfred.

And then if you go ahead and -- are your current thoughts more or less duplicating the steam generation equipment you have at Genessee 3 in Keephills?

That is certainly what we are looking seriously at in terms of getting some efficiencies of scale on purchasing and maintenance, and that's certainly the current look right now.

Okay, thank you.

There are currently no more questions holding in the queue.

We are able to open the call now to media.

(OPERATOR INSTRUCTIONS) [Haret King].

On Hawaii plant, where is that located in Hawaii?

It's the big Island.

The big Island?

The big Island, yes.

Okay, that is my only question. Thank you.

There are currently no more questions holding in the queue.

Well, with that, I think we will conclude our call. Thank you very much for participating this morning, and we will certainly be available to take follow-up questions this morning and this afternoon. Thank you, Aggie.

Thank you. Ladies and gentlemen, thank you for participating in the TransAlta first-quarter 2006 results conference call. On behalf of myself and the rest of the teleconference team, thank you for choosing Telus.