TransAlta Corp (TAC) 2004 Q4 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the TransAlta fourth-quarter 2004 results conference call. I would like now to turn the meeting over to Mr. Daniel Pigeon. Please go ahead, Mr. Pigeon.

Good morning, everyone. I am Dan Pigeon, Director of Investor Relations, and I also welcome you to TransAlta's fourth-quarter 2004 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; Linda Chambers, Executive Vice President, Generation Technology; and Tim Richter, Senior Adviser, Media and Government Relations.

We released the fourth-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 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. Per share figures this quarter are based upon an average of 194 million shares outstanding compared to 191 million shares last year. We may use non-GAAP terminology during this call. The GAAP numbers and reconciliations can be found in the MD&A section of the quarterly report.

Reported net earnings for the fourth quarter were $62 million, or a 32 cents per share, compared with reported net earnings of $44 million, or 23 cents per share in the fourth quarter of 2003. Comparable earnings in the fourth quarter were $37 million, or 19 cents, compared to $30 million, or 16 cents, last year. Reconciliation between net earnings and comparable earnings is shown on page 23 of the MD&A. We generated $159 million of cash from operations in the quarter compared to $107 million in the same quarter last year.

Steve will now provide a few brief comments on the quarter. Ian will then give more detailed comments and analysis on the earnings, cash flow and capital expenditures. Steve will finish our formal comments with an update on Sarnia, the Centralia contracts, and the outlook for our planned maintenance. After these comments, we will open the call to your questions.

With that, Steve, I turn the call to you.

Thank you, Dan. The fourth quarter unfolded essentially as we had planned. We had good execution on our major turnarounds and we reduced our overhead costs.

Compared to the fourth quarter last year, revenues of 713 million were up 8 percent. Availability, at 90.1 percent, was down 2 percentage points due to the increase in planned outages. Comparable earnings were $37 million, up 7 million, and cash from operations was 159 million, up 52 million over last year.

We had continued, solid performance from our plants, with the exception of an outage at Centralia caused by a breakdown in an excitor (ph). The outage was fixed in eight days and with an operations earnings impact of $5 million pretax. We would consider this outage to be one of those one-offs that happens from time to time.

In our last conference call, we indicated our plan was to reduce earnings risk in the fourth quarter, to continue to control costs, and to execute our maintenance plan. We also said we would reduce our exposure to the proprietary markets in energy trading and use short-term contracts rather than the spot market wherever possible for our merchant output. We accomplished those goals.

In prior calls I have talked about market prices and spark spreads. As you know, the impact of market prices on TransAlta is limited to the 15 percent of capacity which is not contracted. I thought it might be helpful to provide some specifics for you on this 15 percent. And starting in this quarter, I will discuss prices and spark spreads we realized versus the market.

Where the merchant market is more suited for spot activity, as it is in Alberta and Ontario, our marketing team achieved higher merchant prices than the average market price. In Alberta, our price for the 1223 gigawatt-hour sold into the merchant market was 9 percent higher than the average indexed spot price. These sales consisted of 818 gigawatt-hours from our coal plants and 405 gigawatt-hours from our Poplar Creek facility. Poplar Creek's merchant sales were down 22 percent from the same quarter last year due to the 36 percent decline in the spark spreads in the Alberta market. In Ontario, realized average price for the 147 merchant gigawatt-hours sold from our Sarnia plant was 8 percent higher than the average indexed price. But poor spark spreads meant we were unable to profitably dispatch Sarnia plant for any more than the 147 gigawatt-hours that we did sell.

In the Pacific Northwest, which has a more establish bilateral contract market, we have used short-term contracts with establish prices instead of relying on the spot market to sell our merchant output. Pricing realized in the Pac Northwest for the 180 gigawatt-hours sold that were not under long-term contracts was 18 percent below the average indexed spot price. Although we realized lower realized prices than the average spot market average, using short-term contracts allowed us to optimize production and costs for our Centralia coal plant. And I will talk about Centralia re-contracting and the status of our Sarnia discussion later in this call, as Dan mentioned.

Planned maintenance expenditures in the quarter were $29 million, of which 79 percent was capital. This compares to expenditures of $17 million last year, of which 26 percent was capital. Production lost due to plant maintenance was 621 gigawatt-hours compared to 336 gigawatt-hours last year. During the quarter, major maintenance with carried out on our Sundance 4 and Keephills 2 units. And I will address planned maintenance for 205 and 206 after Ian's comments.

I would now like to turn the call over to Ian for further comments on the quarter.

Thanks, Steve, and good morning, everyone. To provide further insight into the fourth quarter, I will cover some additional operating highlights, followed by comments about cash flow, capital expenditures, and our liquidity position.

Gross margin in the quarter was $346 million, down 8 million from the same quarter last year. The year-over-year change is primarily due to our decision to reduce our exposure to energy trading markets in the fourth quarter. Generations margin was about flat with last year, but there were some movements within each revenue stream that I will now address. The revenue streams are those we described in detailed on pages 10 to 13 of the MD&A.

Gross margins from the Alberta PPA plants PPA plants at $115 million were 27 million lower compared to the fourth quarter of 2003. 19 million of the decline was a result of Wabamun becoming a merchant plant with the expiry of its PPA at the end of 2003. There was a $5 million decline due to the revenue impact of increased lost production of 127 gigawatt-hours associated with our planned maintenance. Margins in the long-term contract stream at $81 million were fairly consistent with the prior year, as you would expect from what are mostly cogeneration plants. Our merchant plants increased margins by $33 million to 100 million. The increase was primarily due to the Wabamun plant. CE Gen's gross margin of 47 million declined to million due to the strengthening of the Canadian dollar. In U.S. dollars, CE Gen's gross margins of 39 million improved by about 2 million.

Operating expenses at $235 million were down 10 million quarter over quarter. While depreciation was about flat, energy marketing's operating expenses were $6 million lower. Lower planned maintenance expense and reduce overheads accounted for the rest.

In summary, gross margin less operating expenses was essentially flat with last year.

I will now covered three below-the-line items. Net interest expense of 49 million was down 13 million, as we repaid debt over the year and locked in lower interest rates. Minority interest of 15 million was about flat with last year. And income taxes at 26 million were at an effective rate of 29.7 percent, at the high end of our 25 to 30 percent guidance range.

Let me now move to capital expenditures and cash flow. Capital expenditures, at $104 million, included 30 million for Genesee 3 and $23 million for planned maintenance, with the remainder covering capital expenditures and CE Gen, payment for long lead maintenance items, and other productivity-related initiatives. Capital expenditures for the year, at 366 million, were consistent with the 360 to $375 million guidance range we provided in October.

Fourth-quarter operating cash flow, at 159 million, was $52 million higher than last year, with the change being predominantly in working capital. The $103 million generated through depreciation is consistent with last year, and very predictable from quarter to quarter. On a year-to-date basis, we have generated $613 million from operations, including 412 million from depreciation.

Let me review our operating cash flow before changes in working capital meets our ongoing obligations. For the year, or operating cash flow of $613 million, we generated 587 million before working capital changes. This exceeded what we consider to be our ongoing requirements. Sustaining CapEx for 2004 was 204 million. Scheduled debt repayments were 51 million. And dividends and minority interest obligations were 239 million. The aggregate of those items was 514 million, leaving 73 million to repay debt or spend on growth.

Before I update you on our financial ratios, I want to point out a difference compared to previous quarters in our statement of cash flows. We have concluded that the cash realized when renewing financial instruments to protect the investment in our foreign subsidiaries from foreign exchange fluctuations should be categorized as an investing activity rather than a change in working capital. The logic for the change is that the decision to hedge the investment in our foreign affiliates does not relate to operations. The change does not affect net earnings, cash balances, or cash generated from operations before changes in working capital. The salient lines on the cash flow statement to look at are changes in non-cash operating working capital balances and realized foreign exchange gains on net investment.

I will now report on the financial ratios where we exceeded our published targets. The combination of operating and transaction-related cash flow allowed us to strengthen our balance sheet, as evidenced by the financial ratios. Cash flow to interest improved to 4.1 times from 3.3 times last year. And cash flow to debt, at 18.5 percent, compared favorably to 17.2 percent last year. Debt to total capital, including non-recourse debt at 47.4 percent, is better than our target of 48 percent.

Looking forward, capital expenditures in 2005 will be in the range of 360 to $375 million, including $50 million to complete Genesee 3, and 145 to 160 million on planned maintenance, and 145 to 155 on other sustaining capital. Included in other sustaining capital is 30 million in CE Gen and $100 million for mining equipment. The mining equipment, as it relates to the Alberta mines, was contemplated in the PPA, and we are compensated for this expenditure in the deemed asset base. The mining equipment and Centralia represents the periodic replacement of trucks.

Our goal with respect to cash from operations before changes in working capital is to continue to exceed cash required to fund our sustaining capital, scheduled debt repayments, minority interest obligations, and to pay the dividend. The excess will be used to pay down debt or fund growth. We accomplished this goal in 2004, and I expect we will accomplish our goal again in 2005. This will result in continuing strengthening of our balance sheet and improvement in our financial ratios. I would remind you that we have set the medium-term financial ratio targets consistent with a BBB+ credit rating.

With that, Steve, I turn the call back to you.

Thank you, Ian. During our third-quarter conference call, I identified three issues were I would provide ongoing updates. These were discussions with the Ontario government regarding our Sarnia plant, re-contracting at our Centralia coal plant, and our major maintenance plans.

With regards to Sarnia, we continue to meet with Ontario government officials to press for a resolution to our market-related problems. In the fourth quarter, the government of Ontario was focused on completing and passing Bill 100, establishing the Ontario Power Authority, announcing the winners of the Renewable Energy RFP, and beginning of the evaluation of bids in the 2500 megawatt Conventional Generation RFP. With these issues moving out of the way, I anticipate we can now start to make progress toward some form of agreement in the coming months.

With respect to the long-term contracts at Centralia, let me remind you that 400 megawatts in contracts expire at the end of this year, 100 megawatts expire at the end of 2006, and 400 megawatts expire at the end of June 2007. In the fourth quarter, we signed a one-year contract for 2007 for 15 megawatts with pricing in the mid-US$40 range. Discussions with customers in the Pac Northwest continue, and we anticipate pricing for new long-term contracts will be in this range. We are targeting to secure 3 to 5 year contracts for 400 megawatts of the output by the end of the third quarter of 2005. We are progressing steadily but cautiously here in order to get the best mix of price and contract terms in a market that is seeing upward price movement right now.

As I committed in the third-quarter call, I would like now to provide some details on our plans for major maintenance for 2005. Our maintenance plans for 2005 include total spend of between 210 and $235 million on planned maintenance, with capital accounting for about 70 percent of this amount. The plan calls for 6 coal turnarounds, with about 2300 gigawatt-hours of lost production; 6 major gas outages, with 600 gigawatt-hours of lost production; and a bit of work on our hydro facilities. Our current plans call for 20 percent of our maintenance expenditures to occur in quarter one; 35 percent in each of quarter two and quarter three; and 10 percent in quarter four, reflecting the seasonality of our business.

For 2006, our planned maintenance expenditure for major maintenance will be between 205 million and 215 million, with 65 percent being capital in nature. The plan calls for 7 coal turnarounds, with 2400 gigawatt-hours of lost production; and 7 gas outages, with 600 gigawatt-hours of lost production.

As also discussed in the third-quarter call, planned maintenance spending will further reduce beyond 2006 to a range of between 150 million and 175 million, with CapEx averaging 65 to 75 percent.

Once again, I hope this overview is helpful in your better understanding of our business. And we will certainly keep you informed quarterly about our progress with this major maintenance activity.

One other update issue is the impact on our Poplar Creek plant and the recent fire at the Suncor facility in Fort McMurray. Our most accretion recent projections indicate an impact of about $300,000 pre-tax per month reduction in operating income. We understand they are expected to be back online towards the end of the summer. Meanwhile, we will focus on costs, and to the extent we can, sell our available capacity into the market as a way to reduce the impact of this event.

Finally, when I wrote my December letter to shareholders, I described the various business cycles impacting our business. Within that context, our overall 2005/2006 priorities continue to be -- first, focus on strong execution to help drive improved earnings; second, reinvest our capital in our existing fleet to achieve productivity improvements; third, further strengthen our balance sheet through debt reduction; and forth, we would capacity growth will be limited to modest amount of renewables or unique one-off opportunities, if they were to occur.

And I am now going to turn the call back to Dan to lead our question-and-answer period.

Thanks, Steve. 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 up to the media. We will then respond to the Web-based questions 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, you can now take questions, please.

(OPERATOR INSTRUCTIONS) Andrew Kuske.

You gave a presentation at a conference, and I think this was in December, and the number for lost production due to maintenance was estimated to be 2700 to 2800 gigawatt-hours for '05 through '06. And the number that is in your release this morning was a little bit higher; it's about 4 percent higher at about 2900. What is the real driver behind that? Did you shift some maintenance into the 2005 year?

Andrew, it is Dan. I am going to get Steve to address that first, and then maybe follow it up with some comments from Linda.

It just reflects just the further fine-tuning of our maintenance plan, Andrew; a bit of shift in timing, and then just the mix between the gas and the coal. So we didn't view it as particularly significant. I think we will probably get swings of 3 to 5 percent over the course of a year wouldn't be particularly unusual. But I don't think it would be much more than that.

Okay. And then if I could just turn everyone's attention to just your returns on capital and your return on shareholders' equity, what is your view of your weighted average cost of capital at this stage? And how do you see your returns over the cycle, because if we look at the last couple of years on a normalized basis, the returns have been just relatively sub-par? And that is understandable given the maintenance program, but how do you see that on a go-forward basis, especially when you come through the maintenance cycle?

Andrew, I am just a bit confused on the question. Is it you are specifically looking for our view on ROE?

Well, how do you see returns on equity and also your returns on capital?

I am ask I an to take that (multiple speakers)

Andrew, our view is that a realistic return on equity, return on investment in this industry in the long haul is in the 10, 11 percent range. Maybe 10 to 12 is a reasonable range. And that that would be our goal that we would see us evolving towards that and then holding onto that over the long haul. We have obviously a bit of drag right now based on combination of the percent of new greenfield development that we put into place the last 5 years, and of course a bit poorer market positions than we thought.

But as we go forward, and as these greenfield plants move out of their debt pay down stage, ROE, ROI will just naturally go up. And I would say our long-term goal is to be in that industry toward the high end of the industry average.

So that was 10 to 11 percent return on equity?

Yes, I think this industry is a 10 to 12 percent ROE, ROI type of industry. Once you get beyond that, the risk profile probably rises too high for us to participate.

And then just one final issue, if I may --

You are pushing the edges here, Andrew, on my one question with a follow-up.

Well, it is related to the our ROE issue. Your DRIP program has been fairly successful, but there has been fairly significant share creep in the (multiple speakers)

Fairly significant what? Sorry?

There has been a fairly significant share creep in the last few years because of the successful DRIP program. So that does, obviously, affect the outlook. Do you see closing off the DRIP program in the future?

I think, Andrew, the way to look at the DRIP program is as part of our overall capital structure. And to the extent that we have a number of investors who are interested in participating and we have a use the money, we would continue to use it. As evidenced by the fact that we in the year 2004, and a little bit 2005, are continuing to invest on the Genesee 3 project. And so in effect, what we're looking for is some new capital for that kind of an initiative.

Sam Kanes.

I noticed you have increased your depreciation on the Ottawa and Windsor plants. Has there been a shift in thoughts on remaining useful life? Or is it due to expected major overhauls?

(multiple speakers) Ian to address that, Sam.

It is a function of the slight increase per unit, which because that in those plans the depreciation is a unit of production basis as opposed to a straight line aging basis.

No more, no less than that?

Right.

Okay, a quick follow-up then, if I may. You mentioned that your Mexico plans just had I guess fewer megawatt hours generated in Q4. Is there any special reason for that? Was there some maintenance there or something different happened in Mexico? I guess you'll put that up shortly on your website. But did anything of any consequence occur in Mexico in Q4 in generation?

No, not particularly, Sam.

Winfried Fruehauf.

What does January 2005 look like compared with December 2004, both in your generating department and trading and marketing?

I don't think we are into talking about 2005. We're talking about 2004 here.

Well, we are --

No, we are not about to get into giving you interim guidance in the middle of a quarter.

Well, I am not really looking for guidance. I am just looking to find out whether progress was made or not made.

Progress on what, Winfried?

Well, on the generating side and trading and marketing.

But you are asking us to compare some numbers of January '05, and we are not prepared to do that.

No, I am not asking for numbers. I am just asking for a general comparison -- better, worse or flat.

We are not going to do that, Winfried. Next question.

Sean Burke (ph).

Question for Ian, if I could. Ian, if you look at these cash flow numbers, which appear to be very strong, and particularly if you look at the debt pay down program that you all have been going through for the last several quarters, and then you think about in terms of ratcheting down this CapEx program in '06 and beyond, as you all just articulated, when do you think we are going to see some push through? And you are putting it in the numbers, and when do you think we will see some push through on the rating agencies side?

What we have done, Sean, is really set our targets on the ratios to get them up to that BBB+ range, and that is sort of a 2004 to 2006, 7 kind of a program. And I think as we have consistently said, we will get the ratios up, and then the rating agencies will have to make their own call based on their investment of our overall risk profile, their view of the sector and so forth and so on. But we are definitely on target to hit the numbers that we have set for ourselves.

I mean, if you look at the FFO interest, FFO to debt, debt to Cap metrics that S&P puts out, you are very comfortably in that BBB range at present. I am just trying to think do you have any specific balance sheet targets that you are looking at for 2005?

Yes, we do, and we have published those. I don't have them at my fingertips. But we show an improvement in each of funds float to interest, cash flow to debt, and debt as a percent of total capital structure. I think we are improving the turns by like 1 or 2; the percentage by a point or 2; and the debt to total capital, I think we are moving down towards that 45 percent level.

Bob Hastings.

Sorry if this was answered in the first 15 minutes of the call, but I didn't get the new number. So in looking at Genesee, it has been testing out its production; it has been in the market. When does it officially startup and stop being capitalized and be brought into the numbers?

The current plan calls for it to be CODed (ph) at the end of the first quarter.

So starting up April 1st?

That is the current plan, and they are currently in testing phase. And we will provide update as soon as there is anything different than that.

And I see in your outlook provided in the MD&A that you expect production to be up somewhat this year with Genesee more than offsetting the other outages from the other Wabamun plants closing down. It looks to me like about 400,000 sort of net extra hours, which would be I guess another 12 million of revenues. Is that sort of the implication there?

Yes, that is not a bad call, Bob. It is a function of 250-ish megawatts coming on and 120 some odd megawatts going off. But the 250 is obviously only for the three quarters of the year as opposed to the full year.

Matthew Akman.

I want to just talk about the maintenance expense in the quarter and then outlook maybe as a follow-up. But in the quarter, Steve, you have mentioned that in Q4 '04 the percent of maintenance that was capitalized versus expense was like 79 percent or something, and then 26 percent only in the prior year. So I'm wondering if you could just describe what changed in terms of the type of maintenance or whatever that caused you to capitalize so much more in Q4 '04 than Q4 '03.

It is really in the mix of the plants and the type of work. Linda Chambers is here, and perhaps she can give you a bit more specifics on that that might be helpful. Linda?

That is correct. One is the timing issue of how much maintenance you actually do in the quarter versus the prior year. And the second issue is when you have more capital it is related to scope were you are tending to replace components rather than repair them. So it would be tried very much to the scope plan.

Okay, so I guess that was a lot different year-over-year?

That is correct. We are certainly trying to look over like, say, a ten-year cycle. And that lead us to do a bit more replacement as opposed to repair. That is still specific to the unit and to the specific issues being addressed. But that is correct. The mix changed dramatically.

Just a final comment on that -- that is consistent with the bigger strategy on this maintenance program we are undertaking over this two or three year period we have been --

I think, Matthew -- remember about a year ago we did indicate that the quantity and mix of the type of spend you do can change quarter to quarter. Over year-to-year it doesn't change a lot, but quarter-to-quarter -- and that is why we will provide those guidance numbers on those issues, to help you sort through what the changes in mix are for your modeling.

That would be helpful, because -- that would be helpful. Okay, let me ask a follow-up, if you don't mind (multiple speakers) this is the first time you have talked about 2006 maintenance. And I guess just to confirm, so we have kind of similar operating expense-related to outage in 2006 as 2005, but a little bit more lost production. Is that a fair way to characterize it?

I think so, yes.

Just one piece of maybe advice on the lost production. It is difficult to draw a direct line between lost production and margins, because to the extent that the lost production is in the gas plants, which are some of the co-gen plants, to the extent that they are scheduled into the contracting structure and so forth, there is less of an impact on margin than there might be if we had to go and replace that power.

But I guess if I am just looking at earnings models and looking out to 2006, clearly there is upside from Centralia re-contracting; maybe whatever happens on Sarnia. But from a maintenance standpoint we shouldn't look for a big earnings improvement, or really any significant earnings improvement until 2007, because of reduced maintenance. Is that a fair characterization?

That is a pretty fair characterization, yes.

Maureen Howe.

Just continuing on on the maintenance schedule, I am looking at investor presentations that were done in the fall. I guess in particular I have the one from the Edison Electric Institute conference in front of me. And it looks like the ongoing maintenance has changed -- not a huge amount, mind you, but in that presentation the rage for 2000 and beyond was 175 to 180 million annually, with 60 percent capitalized. It was lower today, I think. What was the number you gave, Steve -- 165 to 175, with -- was it 65 percent capitalized?

I think (multiple speakers)

65 to 75.

65 to 75 range, right.

Okay. Is that simply fine-tuning your numbers or is there --?

That's correct, yes. It is just a fine-tuning. And we will keep you up-to-date on that we go forward, as they schedule these outages as they go forward.

Okay. So again, I guess, Linda, in terms of a run rate, even with the lower number and the higher percentage capitalized -- again, not a huge change looking forward in terms of the amount of capital -- or amount of maintenance expenses.

I think there is again two things. I think that as we come off -- and I mentioned before some of the capital program, where you are replacing components, you see the numbers trend down on that, because you start to go more into that kind of run rate model now and the run rate proportion on the spend.

I think you use 2005 peak; 2006 coming down; and 2007 and beyond as the numbers you gave as a good longer-term run rate.

Can I ask another question, Dan?

Yes.

Everyone else seems to be. I don't think we should exclude you, Maureen. I will have to get Dan to be a bit more disciplined as we go forward here.

This is a different question. In the interim, there is a mention of a -- I think it is on page 13, and it is of a shrinking spark spread at Centralia. And I am just wondering if you can put a little color on that. What is happening there that -- because I actually thought there was about 300 megawatts and that were re-contracted at a slightly higher price; my understanding was not hugely higher, but a few dollars. What is causing the compression there?

We have had some increase in the coal costs, Maureen, as we have been -- we have talked about our coal operations in Centralia not being exposed to commodity prices. But in fact, as we move further away from the plant, you end up with some increased coal costs. We really got hit this year by some increase diesel costs as well, both in Centralia and in Alberta. In this case of Alberta it sort of goes into the pricing index through the PPAs. But in Centralia the cost of diesel hurt last year, in 2004.

Karen Taylor.

I just have a couple of follow-up or clarifications, and then I will ask my real question, if I may. For the '06 budget for planned maintenance it's 205 to 215; 7 coal units with lost production of 2400 gigawatt-hours and 6 gas?

I think it was 7 gas, Karen.

7 and 7, then?

Yes.

And how many of the coal units would be subject to availability incentive payments?

Well, I can answer that for you. It is primarily the Alberta thermal PPA units. I will make one other comment for the audience here to just have in the back of your mind that we also continued to have to do some what I would call one-off maintenance on our Wabamun 4 unit. That is planned, as you know, to be taken out of our fleet in 2010. But we still do have to have that in the mix as well for some maintenance expense.

What I was just trying to get at is of the 7 coal units that are going to go down, 5 of them will have some sort of availability incentive payment, and the other, I am assuming, a unit for Centralia and a unit for Wab?

That is a reasonable assessment.

And my last sort of clarification question, if I may. Beyond then we are looking for planned maintenance of 150 to 175, 65 to 75?

Right.

And just a clarification. On page 21 of the release, it says planned CapEx in the text of 190 to 225 million for 2005, but in the table it says 210 to 235. I am assuming it is the 210 to 235 for planned in '05 tat is right.

That is correct.

Karen, our apologies. We changed the table and we missed the words in the text.

Just one other last math question, Ian. When you were running through CapEx for 2005, you said that CE Gen CapEx would be 30-odd million. But if you say -- you said the CapEx in 2005 is 367 million; 150 is the capitalized planned; 100 is the mines in Alberta and Centralia; 50 for Genesee 3. That leaves 67 for CE Gen.

No. It is 30 in CE Gen, and the rests is kind of productivity-related items in the rest of TransAlta -- things like IT; things like some of those initiatives where we are spending small amounts of money relative to some of the other dollars in order to improve productivity.

So in total, then, 367 is capitalized in 2005; 150 planned; 150 for the mines; 50 for GP3; 30 for CE Gen; and 37 for miscellaneous productivity?

Yes. That is a good summary.

Now my real question really comes back to just the performance for fiscal '04 and for the quarter and whether or not it met the Board's expectations. Is this consistent with the plan that you and the Board hashed out (multiple speakers)

It was consistent with our forecasts, Karen; absolutely consistent with our forecast and expectations internally.

Now, was that on a total earnings basis or earnings from operations and onetime items?

Both.

Winfried Fruehauf.

Before I ask the next question, I would appreciate some clarification. I was admonished that we are only talking about fourth-quarter 2004. I would suggest that we have talked perhaps on balanced more about 2005 and 6 than about the fourth quarter of 2004. There was guidance given as to where the debt to cash flow ratio might be in 2005. And when I asked a simple question, just directionally how January differs from December I am being redressed and prevented from asking the question. So what is the logic for that?

I think, Winfried, the logic is that what we are trying to do on the guidance in '05 and '06 is provide directional things on some of those items that we have talked about before. What we don't want to do is talk about specifics as it relates to January or the first quarter, because we are just not in a position to do that.

Well, I was only interested in a directional comment. And I would suggest that the questions -- the only guidance for question of the criterion is relevance. And I don't think anybody can suggest that what I was trying to ask was not relevant.

Yes, I think, Winfried, to be fair -- let me just say, because I think he has a point, we don't want to give guidance here. But I think it is fair to say that January is tracking just like December relative to markets and everything we are doing. We don't see anything unusual in January at this point. Okay?

Well, at least that is helpful. Thanks for that. Now my --

(multiple speakers) I would say a continuation is a fair thing, and that is all I would like to say on it.

And now to my question. Had you not used short-term contracts and reduced your trading and marketing activity, what would the operating income for the fourth quarter for trading and marketing look like?

It is awfully tough to back-test the model there, Winfried. It would be almost impossible, because just the fact that we were not in the market as much as we otherwise might have been may have actually even moved the market. So I don't know if that is a fair question.

I think the theory of the case was that to achieve a better number we would have had to take on a much higher risk profile, and therefore the volatility would have been much higher. So I guess a simple answer is it would either been a lot higher or a lot less. And I don't know how to answer it other than that, because we cannot redo the model in hindsight very well.

Causes me a little bit of difficulty, because if you make a conscious decision to do something different compared to what you have done in the past, then I would suggest in order to do a variance analysis you have to be able to tell whether your decision to do something different was good, bad, or indifferent, because otherwise how would you really know whether there is any justification for the change in tactics and strategy?

Yes, I think, the very simple decision we made -- we looked at it, and we talk to our trading people. They saw some opportunities on the plus side, but said that they were a much higher risk profile than we would normally do. And we made a conscious decision not to accept that risk profile. We didn't want to increase our bar (ph). We didn't want to put more volume into the business. And so we decided not to do that. And we did some analysis, mathematical modeling, around the risk and what the EBIT would be. I don't think -- that is not something we would normally share. But the result of that was to do what we did. But I wouldn't say -- I'm not prepared to say that we did not have some sense. But those are really internal calculations that I don't think are really stuff that is of value externally.

Bob Hastings.

Just going back to the Sarnia plant, you mentioned before you had had discussions with the government, and the government made some public comments. From what you have said now I guess all those conversations just stopped for a period of time. Have the conversations with the government restarted? And is it likely to go very far or fast given that they are still trying to get an agency and staff it up, etc.?

I would say, to be fair to the Ontario government there have been some ongoing, low-level discussions over the last three or four months. I think they indicated that they did need to get some of these other issues that I indicated behind them before they would like to take it to a next level. They indicated (indiscernible) that they are now ready to do that. And we are hopeful to be in the more senior-level discussions in the course of this quarter.

Is there any sort of talk there of using the bids that came in on the 2500 megawatts as maybe a proxy for whether your plant should be contracted out, for example, maybe slightly under the others for you to be able to be competitive?

I don't know how they intend to use that. We (indiscernible) get a look at those or anything (ph) that is in the public domain pretty closely. But I think we will just have to wait and see how they will want to deal with that.

Sorry I can't be more forthcoming. We just -- at this point it just really requires us to sit down, and we will see what happens, and we will certainly keep your updated as that changes.

Matthew Akman.

I just wanted to ask about the outlook for the Genesee 3 plant that's just coming online in terms of its profitability and whether -- I guess maybe this is for you, Ian. Will this add significantly to profits or is this kind of like, you know, a lot of the new plants where there's a lot of depreciation upfront, and it is going to be more neutral?

Recognizing that it is nine months of the year and Wab was twelve months last year, the impact of the difference between the two is a slight positive in terms of absolute earnings in '05 versus '04. Recognizing that there is a lot more capital involved in Genesee 3 than there is Wab, the percentage return on capital obviously would be lower.

That's the difference. Just in terms of the absolute (multiple speakers)

Absolute is positive.

It is a positive to earnings?

Yes, positive to earnings and positive to cash.

Maureen Howe.

Ian, in the interim report there is mention on page 14 of tax assessments that impacted interest income as well and positive tax assessments. And I am wondering if you can give us more background on what these tax assessments are, the magnitude of them, and how much up of the interest income was comprised of the impact of the tax assessments.

Yes. We received a tax refund on the money associated with our distribution and retail disposition, whenever that happened, four years ago. The impact on earnings, you know, was essentially a break even. I think we actually book-kept (ph) that a previous quarter. But the cash was physically received in the fourth quarter. And of course, the government pay interest on the cash which they had owed us. It was about $7 million. It came pretty close to offsetting the amount that we wrote off associated with the prepaid interest costs that we wrote off associated with our coppers (ph) recall at the end of the year. So in terms of the impact on interest in total for the quarter, the two were pretty close to balancing each other.

So the coppers (ph) -- and I was going to ask about that as well. This is the 7.6 million?

Right.

And that is associated with the cost of the recall. Is that because of just the expenses associated with that or was there a premium?

No. It was a function of the -- when we issue fixed income instruments, to the extent there are transaction costs (multiple speakers) amortized over the life. To the extent that had a 2048 maturity, obviously it had a whole bunch of unexpired costs to be dealt with.

Okay. Just one last question before I finish up there, and it has to do with the re-contracting of Centralia. And Steve made mention of it in his remarks, and I just want to make sure I understand this and that I'm not double counting. There were 300 megawatts that came available at the end of 2003, and those are being re-contracting short-term. I think we were using a price -- I don't know -- in the range of $30 or thereabouts for 2004. Is that being continued forward through 2004 at a similar type of price?

That's exactly right.

Okay. And then at the end of 2005, there is another 300 megawatts that come available. Now, I think we have a higher price going in in 2005. Is there some -- and is that right, Dan? I am going by memory a little bit here. Does some get re-contracted in 2005 at a higher price, or did I just make that assumption?

Let me just review here. As we sit here right now there is 900 megawatts under the original long-term contract still under contract; 400 come off at the end of this year, not 300. You said 300?

I said 300, but it's 400. Okay, yes.

So we have 900 on contract right now which is averaging around that US$30 per megawatt hour that we have talked about. The balance of the plant is either under short-term contract or sold into the spot market; primarily short-term contract, which is in the mid-US$30 range.

And then the amount that Steve referred to in terms of the mid-40s going forward, I think -- was that 2007? Can you just remind me what is contracted going forward and short of what sort of range?

Again, back to this 900, because you have got to keep that in mind. There is 400 coming off this year, end of this year, 100 at the end of 2006, and 400 mid-June 2007 -- sorry, June '07 -- middle of '07. So we announced, I think it was July last year, we contracted 100 megawatts starting at the end of -- fourth-quarter 2006 for 10 years. And now we have had another one, 50 megawatts for the year 2007.

Okay. So the 50 megawatts for 2007, that is over and above the 100 megawatts for 10 years?

Right. And that one is in the mid-US$40.

And at this point, that is it?

That's right. Other than what we do in the short term market. Right.

Karen Taylor.

I have two questions regarding 2005. I know you have talked about it in the past. For 2004 where you are using an average run rate for the EBIT contribution on EM&T (ph) for 5 to 10 million, is that still good for '05 going forward?

Yes.

Okay. And your effective tax rate in 2005 is expected to be --?

We are in that 25 to 30 percent range, Karen.

And the percentage of that that you expect to be cash is how much?

Extremely low.

So would it be commensurate with sort of your 2004?

I don't have that number off the top of my head, Karen. But it is a very low number. We expect to be -- continue to be very low in our cash taxes for the next couple of years.

Okay, and I just want to ask one quick follow-up to Maureen's question. So you have got 900 that is currently under the original contracts. That expires 400 in 2005, 100 in 2006, and 400 in June of 2007.

Right.

So the plant 1400 megawatts. So that leaves 500 megawatts, 100 of which is sold for 10 years, beginning in fourth quarter of '06 and 50 megawatts beginning in '07.

Correct.

So we are basically sitting there with the residual spilled (ph) spot --

The residual what (multiple speakers)

The residuals subject to your capacity factor.

That's correct.

Sam Kanes.

Out of curiosity, the $5 difference in the 50 megawatt starting '07, 100 megawatt ending '06 at roughly 40, if a recall, is there a contractual difference between the two, i.e., you're obligated to deliver on one and not the other?

Sam, I don't have an answer to that right here. I can get back to you. I just don't have that at the fingertips.

I believe you are correct, Sam. But we will get the specifics for you.

Okay, I appreciate that. And lastly, you have 538 million of current portion of long-term debt due this year. You are paying out 300 million February 15th. Do have a general observation how you would like to finance that going forward in the U.S. market or the Canadian market or term 5-year, 10-year instruments?

To the extent that -- as we have said in years gone by or periods gone by, to the extent that we have a U.S. dollar-denominated assets, we would like to get more U.S. dollar-denominated debt. And our term and is probably going to be longer rather than shorter.

Winfried Fruehauf.

Regarding the outage at Centralia, were you able to purchase replacement electricity or generate replacement electricity at the (indiscernible) so that you neutralized the impact of the outage? Or did you actually take a hit on the operating income line?

We did run the gas plant in the first 24 hours as a way to mitigate that. Our tradespeople did do as much as they could to offset it. And then the balance, we just hit our books (ph). So all of those were undertaken to try to mitigate the impact of the excitor outage.

So in the end did you actually suffer an impact on operating income?

Yes. I think we indicated a 5 million pre-tax operating income impact.

I didn't realize that this was a net number. I thought it was maybe a gross number.

No, it was net, Winfried.

Is there anything happening regarding Big Hanaford in terms of trying to sell it? Or what is your strategy with respect to that plant?

Our strategy is to try to run it as much as we can, and to use it as a backup for the coal plant, which helps us in our contract negotiations for re-contracting the plant. Other than that we don't have any other plans for it at this point in time, Winfried.

Thank you. And at this time we have no additional questions holding in the question queue. One moment please. We do have an additional question. Maureen Howe.

I will ask this question with some trepidation. But, Ian, in the past you have talked about an earnings range of 75 cents to $1 in a down market. So assuming current pricing and the current maintenance schedule, if I understand correctly, including some positive re-contracting at Centralia and a positive contract at Sarnia. You have sort of changed a little bit, fine-tuned your maintenance schedule going forward and some other things. Are you still in that ballpark?

Yes, I think we have said that we would not expect any major differences in '06 and '05 versus '04.

Cindy, maybe we should invite the media, then, to join the call for questions?

(OPERATOR INSTRUCTIONS) James Stevenson (ph), Canadian Press.

I just wanted to get a little bit more detail on the Sarnia thing. Understanding the delicate political process that has to take place, but this has been dragging on for years now. Are you getting a little dismayed that something hasn't been sorted out by now? And how positive are you that you can actually tie this thing up when discussion start up sometime this quarter?

I think we went into this knowing this would take awhile to work through, so there is nothing here that we see untoward in terms of that process. And I based (ph) certainly in all the statements that the government to the minister of energy have stated, I continue to be optimistic that there will be a resolution for this facility as we go forward here.

And can you just refresh terms of the amount that is tied up in long-term contracts there?

100-odd megawatts over and above what is required by the host, the co-generation hosts.

So we have about 150 to 200 megawatt ranges in contracted, and the balance is available for sale into the market (multiple speakers) roughly another 200 megawatts, plus or minus.

James Stevenson (ph).

Steve, there has been talk about bolstering export lines out of Alberta. Does TransAlta have any interest in that in any of the markets, for example in the States, that are not around Centralia?

We have an interest in promoting supporting transmission builds pretty well everywhere. We think that is a main constraint right now in the market. So we certainly support a policy that would encourage transmission lines to be built, to provide access for Alberta generators to the U.S. market. We do not have any plans currently to participate directly in that investment, but would certainly be wanting to access those transmission lines if they were to be built.

Were you approach by the group that is talking about building the lines? Have you had talks with them at all?

No.

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

Then I would like to close up by thanking everyone for joining us this morning. And as usual, we are available on the phones for your follow-up questions later on. Thanks very much, Cindy.

Thank you, ladies and gentlemen, for participating in the TransAlta fourth-quarter 2004 results conference call. On behalf of myself and the rest of my teleconferencing team, thank you for choosing Telis (ph).