TransAlta Corp (TAC) 2005 Q1 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the TransAlta first-quarter 2005 results conference call. I would like now to turn the meeting over to Mr. Daniel Pigeon. Please go ahead, Mr. Pigeon.

Thanks, Cindy. Good morning, everyone. I am Dan Pigeon, Director of Investor Relations, and I also welcome you to TransAlta's first-quarter 2005 conference call. 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 Tim Richter, Government Relations Manager.

We released the first quarter results earlier this morning and I hope you have had a chance to review them. After this call we will once again post further operating information on our website for the quarter. All information provided during this conference call us 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. Per-share figures this quarter are based on an average of 195 million shares outstanding, compared to 191 million shares last year.

In our 2004 annual report, we provided a description of the six key measures we use to assess and evaluate our performance. These are availability and production; contracts; margin and productivity; capital expenditures; cash flow; and financial ratios. We will refer to these measures in terms of the quarter's results throughout this conference call. As we do, you need to remember that power generation is a long-cycle business. There are likely to be variances on a quarter by quarter basis given the circumstances affecting production in each period. Although we use these measures to monitor our performance in the short term, they are most helpful in measuring our long-term performance, ensuring that we achieve positive improvements and increasing cash flow and earnings. Where appropriate, we will identify short-term variances from changing trend issues.

Reported net earnings for the first quarter were $52 million or $0.27 per share, compared with reported net earnings of $47 million or $0.25 per share in the first quarter of 2004. Included in net earnings last year was the gain on the sale of the units of TransAlta Power LP of $20 million or $0.07 per share, and a $23 million or $0.08 per share increase in the provision against our California receivables from 2000 and 2001.

Steve will now give a brief overview of the quarter and then provide you with an update on issues in the Pacific Northwest and our progress on major maintenance both in terms of our results for the quarter and to show how we see the balance of the year shaping up. Ian will give further details on earnings, cash flow, and our progress towards meeting our financial targets. Steve will then finish the formal comments with our perspectives on the Kyoto Protocol and other environmental issues. We will then open the call to your questions. With that, Steve, I turn the call to you.

Good morning. Our plant operations and energy marketing results in this first quarter were solid and consistent with our expectations in terms of revenues, costs, and project management. Availability performance was strong at 93.4%, up from 90.5% last year. Our plan to consistently pay down debt has resulted in a reduction in interest expense of $9 million. These factors combined to contribute to the quarter-over-quarter improvement in earnings.

In terms of major maintenance work in the first quarter, the work was minimal, again consistent with our-total year plan. The main project consisted of some minor work on Sundance unit number 5. This plant was down for 11 days, with a related expenditure of $3 million, all of we expensed. We lost 93 gigawatt hours of production due to the outage, with a margin impact of $4 million. Our total planned maintenance expenditures in the quarter were 11 million, with $6 million being capitalized. This was consistent with the first quarter 2004.

During last quarter's conference call, I included a review of electricity prices we achieved market by market. I did this to give you a feel for how we are doing with the 15% of our capacity that is not contracted. Performance in the first quarter was consistent with previous quarters.

In Alberta where our low profile was different than the market average, we achieved merchant prices 10% higher than market average spot prices on 1,120 gigawatt hours sold into the merchant market. In Ontario and the Pacific Northwest, realized average prices were in line with market averages, with a 245 and 840 merchant gigawatt hours respectively.

I would now like to update you on two issues. First, the Pacific Northwest with comments on recontracting at our Centralia Coal plant and the North American coal market; and second, an update on our major maintenance for 2005.

Merchant prices in the Pacific Northwest increased in the first quarter and are now in the U.S. $47 per megawatt range, compared to $46 in the last quarter and $41 in the first quarter of 2004. Dryer than normal winter weather conditions and lower snowpack combined with higher gas prices were the main drivers of the higher spot electricity prices. We expect these impacts to persist well into the year.

These rising prices in the Pacific Northwest are clearly a consideration as we look to recontract our 1,400 megawatt Centralia coal plant. Currently we have 900 megawatts of capacity under contracts that were signed when we acquired this plant. The status of the original 90 megawatts is as follows. 400 megawatts expire at the end of 2005; 100 megawatts expire at the end of 2006; and 400 megawatts expire at the end of June 2007.

For 2005, the remaining 500 megawatts are sold under contracts lasting less than 12 months or into the spot market. Of this amount, 100 megawatts has been contracted for a 10-year period starting in the fourth quarter of 2006. We have also secured another 400 megawatts for 2006, and 270 megawatts for 2007 at approximately U.S. $40.

We have been and continue to be in discussions with both current and potential customers in the region. With electricity prices on the rise, we are not rushing into contractual arrangements. We want to carefully balance the opportunity potentially available from even higher prices in the future with our desire to minimize volume volatility through our contracts. As we work through this exercise we remain confident in our ability to recontract Centralia at market prices above existing levels and with an excellent mix of short- and long-term contracts.

We are aided in this ability due to ownership of Centralia coal reserves. They supply 85 to 90% of our needs. The 10 to 15% imported coal we purchase for the plant is currently bought under a five-year contract that was signed at the end of 2003. While we do not provide specific coal costs for competitive reasons, we, like most coal mining operations throughout North America, have been experiencing increases in coal extraction costs for the last 12 to 18 months. This is driven by higher fuel and tires costs, as well as higher costs due to permitting. At Centralia specifically, we're mining increasingly further from the plant.

Our assessment when we purchased Centralia in 2000 was that we would be able to reduce mining costs from their existing levels by reinvesting in productivity improvements after a period of underinvesting by the previous owners. Over nearly a four-year period we were successful at achieving an 18% reduction in cost per megawatt hour produced. The current external forces that are impacting the whole industry create a risk of eroding these gains; so we are in the process of developing a renewed productivity improvement plan for the next four years for our Centralia mine. Fortunately, electricity prices in the Pac-Northwest are also up.

With respect to rising coal extraction costs in Alberta, I remind you that the PPAs cover most (technical difficulty) Alberta coal plants and through the provisions (ph) of the PPAs we essentially pass these cost increases on to our customers.

I would now like to turn to major maintenance. As we come out of the first quarter, we remain confident about our total-year plan for major maintenance. As a reminder, in January we indicated we would spend between 210 and $235 million in planned maintenance, with capital representing 70% of this amount. Scheduled for the balance of the year are six major coal outages and six major gas outages or C-inspections. Lost production associated with the coal turnarounds will be about 2,200 gigawatt hours and about 550 gigawatt hours on the gas side. We will do about 70% of our maintenance in quarters two and three, split about evenly between the quarters.

In our last conference call I indicated that it's our intent to provide details on the upcoming years' maintenance programs at our October conference call and to provide a preliminary range for the year following at our January call. We will update you on our 2006 details in October. But as a reminder, we did indicate in January that our current plans call for spending between 205 and $215 million with about 65% capital related. We're looking at seven major coal and seven major gas turnarounds, and we see nothing in our current planning to change these estimates.

We will be more specific about our 2007 plans in our January conference call, but we're still on track to achieve the benefits of our longer-range planning cycle and key supplier relationships. This should allow us to reduce or major maintenance spend to a range of 150 to $175 million. Again, we are on track to achieve these targets.

Just a final point here. While our coal and gas plants comprise 90% of our fleet and therefore are the focus of my comments, I would like to point out that our hydro and wind requirements are factored into our lifecycle maintenance plans and the estimates we provide. Our geothermal plants are included in CE Gen's ongoing maintenance plans, which are also managed over their lifecycle in a manner very similar to our coal and gas plants. I would now like to turn the call over to Ian Bourne to provide further comments on our results.

Thanks, Steve, and good morning, everyone. As Steve mentioned, our operations performed to expectations in the quarter. To provide further insight, I will cover some operating highlights followed by comments about cash flow, capital expenditures, and our liquidity position.

Rather than repeat a detailed analysis of the variances in each of revenue and cost of sales, I will address contribution margin. The revenue and cost of sales details are on pages 5 through 9 of the MD&A. Also, on page 4 we have explained why we have deconsolidated the Campeche plant. I will be referencing page numbers in our MD&A at other times in my discussion.

Gross margin in the quarter was 362 million, up 5 million over the same quarter last year. There were no noteworthy variances in the gross margin. The increase the margin came from the long-term contracts where price per megawatt increased and cost per megawatt decreased.

Operating expenses at 222 million were essentially flat with last year, which was 220 million. Interest expense at 48 million was down 9 million from last year's first quarter of 57. This is a result of lower debt, lower interest rates, and the lower U.S. dollar. The effective tax rate for the quarter was 28.6%, within our guidance range of 25 to 30% of taxable income. We don't see anything for the rest of the year that would warrant a change from the 25 to 30% range.

Let me now turn to cash flow. Operating cash flow at $160 million was $25 million lower than last year, a result of an increase in working capital. The key driver in working capital was the timing of insurance premium payments. The decrease in working capital last year was due to the timing of construction advances.

Cash flow before changes in working capital at 172 million was 12 million higher than the first quarter last year. For the last couple of years, we're been estimating cash flow from operations of 500 to $600 million per year. Now that all our plants are operating commercially, we expect this range to be about 10% higher.

Capital expenditures were $50 million in the quarter and included 12 million for Genesee 3; 9 million for our mining operations; 6 million for planned maintenance; and 11 at CE Gen. Cash flow from operations at 160 million, less the non-growth CapEx of 38, left $122 million. That $122 million was used to pay our dividend and minority interest obligation, which aggregated 51 million, and reduce debt by 53.

As well, relative to our continuing priority of improving the credit ratios, at March 31, '05 versus year-end '04, cash flow to interest was 4.3 times versus 4.1; and cash flow to debt increased to 20.3% versus 19%. As we look forward we continue to project total capital expenditures for 2005 in the range of 360 to 375 million. We also anticipate further improvement in credit ratios as we move toward our goal of achieving levels consistent with a triple B+ rating.

Finally I would like to remind you that our goal is to generate cash from operations that exceeds the total of sustaining capital, scheduled debt repayments, and minority interest obligations. We have met that goal in each of the last five years. For 2005, using the operating cash flow range of 550 to 650 million, we estimate the sustaining capital, scheduled debt, and minority interest requirements will be exceeded by about 225 to $275 million. I will now turn the call back to you, Steve.

Thanks, Ian. As you are aware, the federal government announced its Kyoto plan last week. I would like to finish our formal comments this morning with our views on the current status of Kyoto and other environmental issues. While reduction of targets for the period 2008 to 2012 for large final emitters, or LFEs as they are called -- and that is the category TransAlta comes under -- was confirmed, there were no details of how individual sectors or companies within those sectors would be allocated targets. They were also no details on compliance mechanisms, emission trading rules, or offset criteria, which the government said would be developed later through some form of consultation.

This was disappointing. Although most of any potential financial impact won't be an issue for us until 2008 or later, we are not standing still and waiting. We have a carbon strategy in place that positions us well to deal with the reductions we will eventually be assigned for our merchant fleet. This four-part strategy includes buying offsets early at advantageous prices; continuing to diversify our fuel mix with gas-fired and renewable generation to reduce our greenhouse gas emissions intensity; undertaking internal efficiency upgrades were economically viable; and continuing to pursue the development of clean coal technology.

It is important to remember that the Power Purchase Arrangements for Keephills, Sundance, and Sheerness plants contain a change in law provision that allows us to flow through costs associated with changes in environmental laws and regulations. We continue to work closely with both the federal and provincial government on Kyoto issues, and we will provide further updates as the details are disclosed and integrated into our plans.

The issues are different in the U.S. of course. We have previously invested $300 million in environment improvements at Centralia and anticipate we can meet the currently projected state and federal targets for emissions.

Just before I close, I want to remind we have a busy plant maintenance schedule in the second quarter. To date, we are tracking to be on time and on budget with that work. I also see nothing in the markets or our internal operations that would create any significant deviation from our prior outlook for the Company for the year. With that, I would now like to turn the call over to Dan Pigeon to handle any questions there may be.

Thanks, Steve. Just before we go into the Q&A I have a couple of reminders, if I may. First, to the equity investors, our annual meeting is on April 29 in Edmonton. I ask you to submit your proxy vote material so that we can get as high a vote as possible at the annual meeting.

Second to analysts and investors, we are holding our investor day in Calgary this year on Tuesday, July 12, and Wednesday, July 13. The meeting will consist of management presentations on the 12th, and a tour of either the Genesee 3 plant or one of our wind farms on the 13th. This meeting is during Stampede Week here in Calgary, so we need to confirm numbers as soon as we can for hotel bookings. Thank you.

Now 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 the Web-based and individual investors; so please identify yourself when asking a question.

I would also like to remind you that we do not provide guidance and that we will answer your model-related questions off-line after the call. Cindy, if you can now take some questions.

(OPERATOR INSTRUCTIONS) Sam Kanes with Scotia Capital.

I would like to a bit more color if I can on your own coal costs and what you have left in terms of reserves. How much have licenses gone up? Is it sliding scale? Or just a little bit more depth on that particular issue.

Sam, Steve Snyder here. Let me try to respond; and Ian or Dan can add anything at the end. First in terms of reserves, in Centralia the reserves as we have currently view them there are equal to the life of the plant. In terms of the Alberta ones, we have certainly beyond the PPA, and so a proven reserve certainly in the sort of 35-year range.

So I don't think reserves are an issue in either facility, and we think there is definitely more than that. But in terms of the definition of proven reserves, more than the life of the Centralia plant and more than the life of the PPA contracts for the Alberta plants.

In terms of the permitting issue, really around permitting, well, there are some cost increases around permitting. It is really more the length of time now to get permitting for mine expansions that will become a potential issue in the future, and the managing of that time frame to match the coal supply to the plant. So that is potentially an issue as we go forward; impact yet to be sorted out, as we are just in the middle of permitting in the Centralia plant right now.

In terms of cost increase, the type of things the industry has seen is really fuel. Roughly fuel, diesel fuel, year-over-year is about 30% increase. Tire costs, which is a major expense in mining, are up about 10%. The real issue with tires is s availability as much as the price. They are in a sort of an allocation process.

Those are all combining to put some price escalators into the mining side. Right now, in the Pac-Northwest electricity prices are keeping pace with that. But we want to attack this issue with another productivity program as we go forward.

Thank you for that, Steve. A quick follow-up. I noticed you capitalized 3.4 million of interest in Q1; presumably that was all for Gen 3. Is that now fully commercially operational, so that capitalized interest goes away Q2?

Yes. Sam, it is Ian. Yes, that is correct.

Thank you.

Shawn Burke with HSBC Securities.

I wanted to ask a question, obviously, noting the decrease in interest payments that you made during the quarter. As you go into the summer months, particularly in the third quarter of this year, and try to realize some of the higher power prices and selling your merchant capacity into the Pacific Northwest markets, can you give us some feel as to how you see your debt profile is trending out as the year progresses? Is it something where you think that you will be able to realize such strong margins in the summer that you will be able to reduce the amount of short-term debt you have outstanding? Or what is your plan throughout the balance of the year?

It's Ian. As it relates to the debt profile, you will recall that we called those COPrS, $300 million worth of COPrS, early in the year. And the expectation was that as we generated the cash throughout the year from operations, we would pay down some of that short-term debt.

Our expectation and our plan has always been to continue to have our long-term debt laddered in a way that we never have too much of it maturing in any one year. So all things being equal, we would expect to be into the capital markets in a longer-term bond issue probably late this year.

But in terms of actual production at Centralia selling at higher prices into the marketplace, when would we expect to see those kind of numbers paint your financial statements? That is more of a third quarter event?

In terms of the earnings, it is the second-third quarter. We get a small -- the relatively modest share of our output in Centralia which is going into the spot markets in the second and third quarters will have some impact as it did in the first quarter. But it really -- the recontracting picks up and the additional margins pick up in '06, 7, and 8 beyond that.

Thank you.

Matthew Akman with CIBC World Markets.

Question on maintenance if it hasn't been asked. Sorry, on Centralia, on the contracting. Steve, for 2006, it looks like you have got a lot of open capacity still. Is that part of the strategy or are you still working on contracts for 2006?

We are still working on contracts for multi -- sort of a staggered approach. So one, two, three, four-year type contracts. We will keep some of that plant, though, open just for the spot market; and also to provide backstop to the contracts we do have, to make sure we can fulfill those.

It is Dan. Just to be clear, we have presently contracted for 2006 1,025 megawatts. So if that is a lot to you, then I guess yes we do. But that is sort of getting into the range where we are very comfortable with that, I think, in 2006.

Okay. So potentially up to 3 or 400, 300-plus open potentially there.

Yes.

Then if I could just ask a follow up, which is frankly on a different issue, but I'll ask it anyway. I don't of anyone asked about Sarnia contracts. You didn't say anything in your opening comments. Is there any update there?

On Sarnia? Sorry, I didn't get the last part. No real update. The government has indicated to us that once this RFP/RQ process was finalized and in the public domain, they would be willing to sit down with us, and would want to sit down with us to negotiate a contract for Sarnia. So we have had some informal discussions with over the last quarter. We expect those to move to a more formal state here in the second quarter sometime hopefully.

Thanks. I will get in the queue.

Andrew Kuske with UBS.

You have done fairly extensive emissions work on your Centralia plant in the past. Given the EPA's announcement on their mercury emissions back in March, how do you see that unfolding, in particular to the Centralia facility?

I am going to have Ken Stickland, who heads up our sustainable development group, to respond to that, Andrew.

It's Ken. Yes, that is actually a favorable result for us. The money that we spent a couple of years ago got us ahead of the curve. So with that money in the facilities already and the enhancements that it has made, it really pushes off further investments, we think, maybe as late as 2015, 2018 for us. So very positive for us.

Now if we consider the magnitude of any investment out on that timeline, is there any sort of speculation as to what that amount would be? Or is it just too far out at this stage?

It is too for out to guess at anything we might have to do out that far.

If I may just add one follow-up on that. With the recontracting efforts do you anticipate putting in change of law provisions into any contract around Centralia, similar to what you have in the PPAs?

The answer is yes. The answer is a soft yes, and that will -- depending on the contract and the price, we negotiate various risk mitigators. So clearly the lower the price, the more risk mitigators we have; and the higher price, generally speaking, the less. So it is really contract by contract, Andrew. I'm not trying to -- it's just that we have to do that each one.

It depends on the customer and then our risk mix. But I don't think we get too many of those. But there are certainly some where that might be the case.

Okay, that's great. Thank you.

Karen Taylor with BMO Nesbitt Burns.

Can I just ask a quick follow-up on the contracts that I think Steve mentioned? You answered it pretty quick, but I just want to confirm. You had 500 megawatts that were presently contracted for less than 12 months on a spot basis, I guess. 100 of that was going to be sold through a 10-year period commencing in the fourth quarter of '06. Then you mentioned 400 megawatts to be sold commencing in 2006. Then you mentioned a further 270 megawatts to be sold in the $40 range, I guess, commencing in 2007. I am assuming there is an overlap there, because that is more than 500 megawatts.

It's Dan. Let me tackle that one. You are right. We have got the 900 we originally signed; plus 500 of less than 12 months that is in effect in 2005. At the end of '05, 400 of the original 900 comes off.

Right; I got that.

All right? So then going into 2006, of the 500 we are selling right now at 12 months and less, there is plus now 400 that has come off. You're really looking at a number of about 900 there that is really available to be sold.

So let me just make sure I write that. As of January 1 of '06, we will have 900 megawatts. And of that 900 then, 100 is sold for 10 years commencing in Q4 '06; and 270 megawatts of that 900 is sold commencing for '07, for an undetermined term.

275 in '07. But 400 in '06 has also been contracted now.

Okay; now I have got that.

Add the three up, and that is the total of (multiple speakers).

Then remember at the end of '06 another 100 comes of the old legacy; and therefore it is available. You see? That is the problem we get into, is trying to match up contracting coming off and new contracting being done.

But I think you've got the numbers there.

You've got it.

That's right.

I just want to come back then. So Jan 1 '06 we have 900 megawatts available. 100 is contracted for 10 years; 400 is contracted beginning in '06; and 275 in '07.

Right.

Perfect. Can I just ask a question on the deconsolidation of Campeche? Exactly how much debt, because I just to make sure I understand all the accounting. Because we are equity accounting, we are no longer showing the nonrecourse debt on the balance sheet. Is that right?

That is right, Karen. Yes.

How much debt then did we eliminate from the balance sheet at the end of the first quarter?

$135 million, U.S. dollars.

U.S.? Okay. So when I sort of in my simplistic way quarter-over-quarter added the debt up, I only got a net reduction of 62 million. So we took about call it 180 million of debt off the balance sheet. But the net reduction is only 62. So our overall net borrowing went up during the quarter. Is that fair?

No, that is not right, Karen, because we restated 2004. If you look at the notes, the financial statement says we retroactively applied the Variable Interest Entity standard. So effectively we have restated 2004 to be on the same basis as 2005. So that debt has now come out of the numbers for first-quarter 2004.

For both? Okay. I will get back in the queue. Thank you.

So you are comparing -- if you look at the two years you are actually comparing it on exactly the same basis.

Okay, thanks.

Linda Ezergailis with TD Newcrest.

Just wanted to follow-up on Karen's questions re Campeche. Just want to understand. This is not a new accounting standard. I know there was a change, but who would be the primary beneficiary if it is not TransAlta? That is part A of my question.

It is not a new accounting standard in the U.S. sense, but it does apply in Canada for the first time this year. There is some debate, Linda, about this whole theory of primary beneficiary, but we think that the argument would probably lean towards the CFE, because of their involvement in the pricing of the gas and so forth.

CFE for pricing of gas. But why would not Chihuahua be treated this way as well?

Because Chihuahua is not thinly capitalized. The test does not applying once -- the first question is, is the plant, is the company -- and in the case of Mexico, each of Chihuahua and Campeche is a separate plant and it is also a company.

And the first question is, is it thinly capitalized? Yes or no? In the case of Chihuahua it is not thinly capitalized, therefore you do not move on to the next question. In the case of Campeche, it is thinly capitalized, and so you then move into the next question.

So are you going to need to confuse more equity into Campeche to finance the operations going forward?

We are evaluating whether we should do that or not. In point of fact the flaw in the accounting standard, quite frankly, is that they differentiate between equity and intercompany debt. So if we were to convert our intercompany debt to equity, it would change the game. But obviously with nonrecourse debt you can't do that just at the drop of a hat. So our investment in Campeche is not going to change. The characterization of it between debt and equity might change.

Okay. Then you had an equity loss of 1.3 million in Q1 '05. I know last year there was some startup hiccups. So there was a 1.2 million loss in Q1 '04. What is going on operationally there in terms of are we going to start seeing some equity earnings from this facility? Or what is going on?

The thing to remember with that equity number is it is after interest; whereas the rest of our operations are obviously at the pre-interest level. The plant in Campeche is doing fine and we are cash positive. If we were looking at that on a comparable basis with all our other assets, we'd get some different answers as well because of the treatment of the interest.

Okay.

Thanks, Linda. I think it's back into the queue.

Maureen Howe with RBC Capital Markets.

I was just wondering if we could get some color on the nature of the $100 million that is expected to be spent on the coal mines, with respect to the capital expenditures.

It's essentially trucks.

Trucks? Okay. If I can ask one more question, it has to do with the steam sales at Sarnia. The variability, and I guess the increase in Q1 that you referenced in the comments in the MD&A, is that a function of the host just calling for more steam? I'm just wondering what drives the increased steam sales.

It's a combination of the host, and I think there is some reference in there to some improved margins associated with that, because we were getting more efficient in terms of the burning of the gas to create the steam. So it's a combination of a little more volume and lower-cost.

Just a little bit of clarification on the efficiency. What is driving the efficiency?

It is the equivalent of -- it is a heat rate story.

A heat rate? Is that the plants running warmer often?

We've reconfigured. The engineers have reconfigured the plant recognizing that in '05 we are probably not going to run the plant on the electricity side full out. Therefore there's an opportunity for us to reconfigure the plant to be more efficient on the steam side. They took that opportunity to do that.

So oriented more towards steam and less towards power sales.

Steam, right. We have some flexibility in the plant where we can, depending on the configuration, gear it to be a bit more on the steam side, a bit more efficient on the electricity side, and make some of those trade-offs. We chose this year given -- looking at the markets -- that we would be better off to err on the cost side on steam. In the first quarter that proved to be a good decision, and we anticipate that will continue to be the case through the rest of this year.

Okay, thanks.

Karen Taylor with BMO Nesbitt Burns.

I just have one other quick question. Actually two very quick ones. The costs associated with the swap, the fixed for floating electricity price swap, with Sheerness, was there any cost associated with that that was incurred by TransAlta Energy? Or is it done at market, effectively?

It was done at market, Karen.

So all you are trying to do there is limit the volatility for the TA Cogen?

Correct. During the outage. You know, there is a planned outage in Sheerness.

The profile for outages, we are sort of work notionally off the distribution on the thermal side of 3, 2, and 2 being the second, third, and fourth quarters? Is that fair?

I think it is probably more like 3, 3, and 1.

Just lastly, in the circular, management bonuses start when earnings per share exceed $0.70. Is that an indication of where performance is going to be going forward absent the contract on Centralia? Or Sarnia, rather?

Repeat your question, Karen. Sorry.

In the circular, your proxy circular, management bonuses start when EPS exceeds $0.70. Is that an indication of the long-run performance from these assets?

No, just -- all an indication of is that we think that is the lowest we should be and the lowest we want to be. So our expectation quite frankly is earnings will be going up as we go forward, and we're not going to reward management for taking them down for whatever reason.

I would hope not.

So whatever the reason, whatever, if the market, whatever reason it may be that management will -- so that sort of put a stake in the ground on that. That is all that is from a compensation viewpoint. It has nothing to do with Sarnia whatsoever. It's a total Company.

Let me just get this straight. So we've got a dividend of $1.00 and bonuses starting at $0.70 like?

It's Ian. Can I just interrupt for a second? I would like to get the AIF because I don't have a copy of it in front of me, and just see what we should have been talking --.

I will follow up with this off-line I guess.

I think we should. Because I think it should have related to '04 actuals. It should not be talking about prospectively in a longer period of time. So let's carry that one off-line.

I think (multiple speakers) two different issues.

All right; thanks.

Winfried Fruehauf with National Bank Financial.

My question is on Big Hanaford. Did this plant operate at any time in the first quarter? How many hours has it been operating in the months to date? What are your expectations for the rest of this year, particularly the summer?

It is Dan. The Big Hanaford ran very, very little in first quarter. R less than 10% of capacity. As Steve mentioned in his formal comments, power prices in the Pacific Northwest, yes, were up. But so also was the gas price. So as you noticed in the MD&A, the actual spark spread did not move much at all. It's actually still below what makes Big Hanaford in the money.

So we have no expectations at the moment to operate it this summer?

Again, if the spark spreads come around for the summer months, yes, we will be ready to operate it. It is ready to go.

But we built modest expectation into our plan right now. We hope we can do better than that; but our plan calls for modest amounts.

But you're doing a lot of homework and you have an idea of what your estimate of weather is and gas prices and demand and so on. So based on your expectations, do you expect to operate Big Hanaford?

Put it this way, Winfried. The marketing team is able to sell it in the forward months. Whether we actually run it or not as you know depends on what the spread is at that time. So we are able to generate some margin around Big Hanaford, but the actual question of are we going to run it or not really depends on the circumstances at the time.

All right, thank you.

Marlene Howe, RBC Capital Markets.

Just a follow-up question on the Sarnia plant. Is there any concern or is a possibility that the reconfiguration would impact your ability to perform on a prospective contract? I guess, is it an indication that for this year you are really looking at selling spot and would not expect the contract to kick in until perhaps 2006?

I think that is fair.

Okay. Just with respect to Centralia, you were talking about permitting with respect to the mine; and presumably that is going further from the plant. I know you have entered a contract to sell power for 10 years starting in 2007. So I am just wondering, is there any major permitting or licensing extensions that would being required for the Centralia power plant in the foreseeable future?

No, but what we are certainly doing is we have -- our mine group have some good-sense estimates of where costs could go as we go forward. Those are factored into the pricing decisions when we make those contractual decisions.

Okay, but I am just talking about limitations on the operation of the plant per se.

We don't see any in the current life span of the plant at this point. We should have adequate coal for the period of the life span of the plant.

Do you have an estimate for the life span of the plant?

I am just using right now the theoretical depreciation, which is out 20 years or something like that, as a basis for that. That is all we can do right now. Whether it is a likely to extend or not, that's another story. But we have matched the coal reserves to that type of date.

All right, thank you.

Linda Ezergailis, TD Newcrest.

Before ask my next question, I just have a follow-up from our previous discussion on accounting changes in Canada. I actually thought that the Variable Interest Entity accounting change was originally released in June of 2003. I know there was a recent revision. But I'm just wondering what the nature of the revision was, and if that was what led to the reclassification, I guess? I guess there is a lot of judgment call here. I'm just trying to understand what is going on.

I think it's the U.S. versus Canada, Linda. Because we have been including this Variable Interest Entity in our U.S. Canada GAAP reconciliation note throughout the year 2004. But it applied to Canada for Canadian GAAP in 2005.

Maybe we should follow up off-line, because my sources are telling me something different. With respect to some of the new emissions laws that have come out in Alberta, I know that you can capture any costs incurred on your PPA plants for complying with these emissions standards from the PPA holder. But just wondering from a cash flow perspective if you can give me a sense of what the timing and magnitude of the cost will be to comply with the 50% required reduction in mercury by 2010?

It's Ian. From a cash flow standpoint, we have not gone into that level of detail. As Ken mentioned earlier, we're still trying to sort out what the costs are going to be.

Can you give me a sense of when you'll get an understanding? Because 2010 is not that far away if you are already starting to do a rolling five-year budget for your maintenance activity.

It's Ken. Maybe I can just help a little bit with that. There's kind of two parts do that. One is the technology for removing mercury from coal is very difficult. We have been working that for some time. We are involved in a program testing the qualities of our coal so that we understand exactly what the challenge is at each of the particular plants. It also is impacted by the plant configuration itself. So we are working that piece.

The other pieces is the choice of the actual technology, so that is underway as well. So at this stage, it's a bit premature to start guessing at what those costs will be until we actually land on a technology. The whole industry is moving very quickly not only in Alberta but across North America, because remember this is not just an Alberta issue; it is a North American issue. So there is a lot of brain power and a lot of engineering studies going on, on this.

We remain confident though that we will be able to solve the issue. The trick is to schedule it in with the lifecycle maintenance plans that we've got. We're working with our maintenance planners on that right as we speak now.

Again, there could be a lot of interpretation in the PPA contract, like you said, with respect to operational disruptions and everything. So I appreciate that clarification.

Now, the other reductions, sulfur dioxide, nitrogen oxide, and particulate matter only come into effect in 2025. So my perception would be that that sort of maintenance activity would occur post 2020. So therefore it would not be the PPA holder but perhaps TransAlta Corp. that would be incurring the capital costs to comply with those emissions reductions.

That is a long way out.

I guess what I'm saying is it's not clear to me if the plants would be running beyond 2025 depending on what the magnitude of those costs would be.

That's right.

Thank you.

(OPERATOR INSTRUCTIONS) Dominique Barker, Credit Suisse First Boston.

Could you please discuss your plans with regards to asset divestitures this year and next? Also clarify, there something in your annual report, and I'm quoting here. You say that the current mix includes more newer plants than you would like. We will adjust this in the coming years. Can you clarify that and discuss asset divestitures?

There's no specific plans that we're in a position to discuss on asset divestitures at this point. On that other question, that really is a reference to the mix of greenfield plants at any point in time and existing of brownfield plants. Just the nature of the greenfield plants as you're aware is that they tend to have -- generally speaking if you build a greenfield plant you will tend to get a higher return than buying an existing asset. But the negative is that the use of cash and our -- don't impact earnings until they have been operating for a couple of years.

So from a balance sheet perspective, we like to make sure we have got only a certain percentage of our fleet is in that category of using cash and not generating great earnings. As you are aware, the opportunities to expand our plants was in a narrow time frame, and we took that. But it was probably in a shorter time frame than we would normally like in a longer cycle. So that is all that is referencing. It is something we just work ourselves out of naturally with time.

I guess the reason I was asking about the divestitures is because I know S&P in their report in December talks about planned asset divestitures. And perhaps you can not discuss particular asset divestitures; but perhaps talk about areas that you believe are perhaps non-core?

Yes, I think the reference from S&P perhaps would be consistent with some of the track record of some of the transactions with TransAlta Power. Whether or not there are more going forward, those will be decided at this time and on their own merits.

If I could just ask, it's a bit slightly related. You have about 588 million of debt repayment to make in 2005. I assume that a large portion of that is refinanceable. You touched on it earlier and you said that you were probably going to out with a more longer-term debt program at the end of this year. What portion of that 2005 debt repayment is refinanceable? Second, in follow-up, is how much debt you actually expect to pay in 2005 and 2006?

It's Marvin here. Just a bit of clarification there. We've got a debt maturity of about $80 million in October. We also have another bond; that is an extendable bond for $150 million. It is the holder of that bond, they have the right to extend it or not here. Current interest rates would indicate they would extend it; therefore we don't have to repay it. We have also got another about $200 million in January- February of 2006 that we have to refinance here.

That is refinanceable?

All is refinanceable, quite right.

Just to correct, though, Dominique, I'm not sure where your 588 came from. Is that including -- ?

It comes from your note 12 annual report.

But is that including the COPrS?

No, I don't think so; because I believe the COPrS were done in Q1 2005. So I'm looking your December 31 balance sheet.

I will follow-up with you on that just to see where that is coming from.

Can I ask one more question, since we're at the end of -- or no?

Sure.

Your cash taxes, I know they are really small; I think they are about 14 million for 2004, or about 14%. I think was about 14% of earnings before tax. Is it fair to assume that -- you have loss carryforwards that are helping -- that those are going to expire and that you're going to get to a more normalized cash tax level in the 2007-2008 time frame? Have you looked at that?

Part of it is a function of our intercompany cross-border financings as well. So it is not all related to tax loss carryforwards. We have told people consistently that we will run somewhere between 25 and 30% on an effective tax rate, and that our cash tax horizon is out a fair length of time. We have not been specific, and I would rather wait and be more specific in a more formal sense as we get closer to it.

Okay, thank you very much.

Bob Hastings with Canaccord.

Just going back to the Sarnia situation, Calpine of course had that new pipe going in around Sarnia. It's pretty cheap on the capital cost side I've given its size, etc. I am wondering if you see something like that being a reference point when you're negotiating with the government of Ontario. And whether that impacts on what you think you might be able to contract that plant for?

No. Steve Snyder. I think that what -- the discussion we have had with the Ontario government really been around they would like to get the pricing from those quotes out. They would negotiate specifically for Sarnia based on our costs and our situation. But I think that will be, within that context, that it is going to be probably in the range of where those contracts are. It's not going to be dramatically different. But it will be unique to our plant.

So it would be unique. Okay. (multiple speakers)

But it won't be related to that particular one. It will be related to the blended rate of all of those contracts that they have let out.

Okay. Around that plant I see that there was an outage in Sarnia with electrical, feeding the NOVA plant. They made the comment yesterday they would love to get a direct connection from somebody else. I guess, is that ever a possibility? Sounds like they've signed something.

Well, I think it's always a possibility. But those are -- I would have no other comment right now. We don't know enough about the situation to go beyond that or what that particular customers needs.

Okay. (inaudible) We are at the end here. Just one other question. When I read ATCO Power's results they're always talking about how they exceeded expectations and they're getting extra payments from the government. I know they account for it different than TransAlta does. Can you maybe go through a little bit of how your performance is and the accounting difference?

The accounting difference, Bob, is that they are essentially as I understand it -- and I am far from a resident expert on ATCO's accounting -- but my understanding is they have continue to use traditional regulatory accounting for the Alberta PPA plants; whereas we do nonregulatory accounting, i.e. what happens in the quarter flows through. How that impacts their numbers I am afraid I don't know.

As it relates to our performance, we continue to be on or better than the plan that we put together for each and every one of those PPA plants.

So every quarter, other than certain quarters where you are doing the major maintenance, you're receiving extra payments for better availability?

I think you will see that an our MD&A each quarter where we talk about what has played out in terms of revenue, and to the extent we have received incentive payments because we have outperformed the availability, or penalties if we have been under when we have been doing maintenance and so forth. We have been trying to be pretty transparent on that.

You also see those megawatt hours show up in the production summary, Bob.

Oh, yes. I know. I just kind of like to see the actual dollar payments recorded.

We record them.

I meant reported to me. Thank you very much.

(multiple speakers) We will work on the second arm (ph).

Sam Kanes with Scotia Capital.

Back to Kyoto, I was curious in Q1 if you were active buying credits. You mentioned you are active in general. And whether or not you were able to sell any S02 credits to the extent they are available to you from your 93% reduction at those Centralia emissions? Are you active in either/or of those markets last 90 days?

It is Ken here. Just generally we don't really acquire the offsets or credits to sell. We are not in the business of trading in those instruments. In terms of the Kyoto style credits, we didn't do anything in the first quarter.

On the SO2, what we had excess, we may have actually entered into a transaction in 2004. I do not recall off the top of my head, but I think we actually sold those back in 2004.

In '04? So nothing more you can sell as of '04?

We may have some more coming. But I think what we had excess we did sell in 2004 on a forward basis.

The final question for me I guess is, Ian, I'm sure this is the case but I will throw it up anyways. You mentioned that you spent 12.9 million on maintenance expenditures under your planned maintenance table on page 7. I presume that that is in prepaids?

Say that again.

You said you spent 12.9 million on future period expenditures. I was just speculating that, and just want you to confirm, that that is in fact in your prepaids and did not go through your P&L. Or did it?

It would be in our fixed assets.

Okay, thank you.

Winfried Fruehauf with National Bank Financial.

You had a margin improvement of about $5 million year-over-year. Was that margin improvement spread fairly evenly over the three months? Or was any one of these months stronger than the other two? And if so, which one?

It was relatively evenly spread, to the extent that some of it came out of that long-term contract stuff. That by its nature is relatively even.

But I was really thinking more on the merchant side.

Net-net on the merchant side it was not a whole bunch different quarter-over-quarter. To the extent those coal -- at least some of the cost increase that Steve was referring to on the coal side, that is a relatively steady thing. There is obviously a bit of volatility around the spot pricing. But that trend has been fairly consistent through the quarters.

I think that, Winfried, pretty steady over the 90-day period.

Okay. Is there any change in momentum that you have observed in the first three week or so of this month versus the first quarter?

No. I would take the 90-day and add what were 22 days; and it's been about the same. Now it is 120 days -- about the 10 days. No. I think I said in my end closing comments, right now, nothing we have seen up till April to date sees any major change in the trends as we have seen them, or our plans as we have outlined them to you over the past two conference calls.

I have another supplementary question if I may on marketing and trading. I take it that Ian's guidance from last year of approximately 10 million to 15 million a quarter is still valid for the rest of 2005?

I think what we said was 5 to 10 at the EBIT level; and that is -- we are consistent with that guidance from last year, yes.

Maybe I was just a little bit anticipatory and gave you a little bit more credit maybe than I should have. But on the other hand maybe not. Maybe that is what you're going to do. So thanks very much.

Well put, Winfried. Well put.

Thanks.

Karen Taylor with BMO Nesbitt Burns.

I just want to ask a quick follow-up on the licensing of the coal mine at Centralia. My understanding or if my faded memory is working that that current license expires before 2015; is that right? And that you do have to get permits for the mine adjacent to that in order to operate the plant beyond. So is that, I am presuming, what you were working on? Can you just confirm the current license expiry?

I don't know that. I do not have that exact date right now. I want to get you --

We will get you the exact date.

(multiple speakers) Dan to get it to you. But what you have stated without -- take the date out, you are correct.

Okay, thank you.

Winfried Fruehauf, National Bank Financial.

It is on CE Generation. What is sort of your assessment of the ability of CE Generation to increase its own profitability in 2005 and 2006 versus 2004? If there is an opportunity, what would you attribute it to?

It is Ian. The opportunities to increase probability are modest at the margin line, to the extent that those contracts, particularly on the geothermal plants, are locked in. The Saranac plant is locked in. Where there will be increased profitability is as they pay down some debt; that will flow through as reduced interest costs as well.

Then there is a continuing focus on productivity, of course, on the operating costs. So the real value is a little less on the margin side, relative to the interest rate or interest costs and the operating costs.

So I take it that CE Generation essentially is a little bit like the Mexican plants right now. It is generator of cash, not a big generator of earnings to TransAlta.

Oh, it is a pretty good generator of earnings. It is consistent with the characteristics of a couple of our other plants. But I don't think we have ever said that was not throwing off pretty good earnings. We are pretty satisfied with the earnings level. All I am saying is that they are not going to escalate at any great rate. But they are throwing off a very acceptable return on capital.

That is fine, then. On distributions, what did you receive in 2004?

Distribution from CE Gen?

From CE Generation.

(multiple speakers) corporate TransAlta? I want to say it was about 13 million U.S. I will get you that number.

That is fine. That's all I have.

At this time we currently have no questions holding in the question queue.

Let's invite the media, then, into the call, if they have any questions.

(OPERATOR INSTRUCTIONS) There's no questions holding.

Then I would like to thank everyone for joining us this morning. Thanks very much.

Ladies and gentlemen, thank you for participating in the TransAlta first-quarter 2005 results conference call. On behalf of myself and the rest of the teleconferencing team, thank you for choosing Telus.