TransAlta Corp (TAC) 2005 Q3 法說會逐字稿

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

Thanks, Aggie (ph). Good morning everyone. I’m Dan Pigeon, Director of Investor Relations. I welcome you to TransAlta’s third 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 Sneh Seetal, Senior Media Relations Adviser.

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

I remind you that the amounts referenced in this review are in Canadian currency unless otherwise stated. In addition, the non-GAAP terminology used in this call is reconciled starting on page 16 of the MD&A. Per-share figures this quarter are based on an average of 196 million shares outstanding compared to 193 million shares last year.

Q3 net earnings were C$52 million or C$0.27 per share compared to C$36 million or C$0.18 per share in the same quarter last year. Included in the reported earnings this quarter was a 13 million tax recovery received in the quarter. Last year reported earnings included a gain-on-sale of TransAlta Power LP units of 3 million pre-tax. Therefore, comparable earnings in the quarter were C$0.20 per share compared to C$0.17 per share in the same quarter last year.

Cash flow from operating activities in the quarter was C$149 million. Cash flow from operating activities for the first nine months totaled C$408 million, which puts us on target to achieve our annual guidance range that we provided in Q1 of C$550 to C$650 million.

Steve will now provide a brief overview of the operating results in the quarter followed by Ian who will offer more details on earnings and cash flow. Steve will then discuss some of our key ongoing items and offer an outlook for Q4 and 2006. We will then open your call to your questions. Steve.

Good morning. A combination of strong operational performance and improving market conditions drove our third quarter results. Production of approximately 13,000 gigawatt hours was up 4% compared to third quarter 2004 and fleet availability was up 1.8% percentage points to 89.8%. Even though approximately 90% of our fleet’s output is contracted in 2005, we were able to capture some of that upside that arose from higher prices in our markets. Combined, these factors contributed to a 7% increase in revenues to C$723 million.

Comparable earnings of C$39 million, a 16% increase over the same quarter last year, were achieved despite the loss of Wabamun unit four for 39 days due to the CN train derailment and resulting oil spills into Lake Wabamun. We have estimated the impact to operating earnings was between C$15 million and C$18 million. We are seeking full recovery. We successfully returned the unit to service on September 11.

During the quarter we achieved our planned objectives relative to major maintenance. We completed two major turnarounds at our coal plants and a series of gas outages. The latest spend was C$57 million with about 55% being capital in nature. This was up from C$54 million last year when about 40% was capitalized. We also made further progress on meeting the financial ratios that support our goal of a BBB+ credit rating. Ian will provide more specifics later in the call on that area.

Volatile natural gas prices resulted in increased power prices in all of our North American markets. The power prices in Alberta, for example, averaged C$66.71 compared to C$54.33 in the same quarter last year. Spark spreads, however, were down quarter-over-quarter in both Alberta and the Pacific Northwest due to weaker demand for electricity combined with the high price of natural gas. Spark spreads were higher in Ontario where demand for electricity was also higher in the quarter compared to the third quarter last year.

I will now turn the call over to our CFO, Ian Bourne to review quarter three financial results before reporting on contracting and our outlook for the remainder of the year and 2006.

Thanks Steve and good morning. I will review some of the financial highlights followed by comments about cash flow, capital expenditures, and our liquidity position. Gross margin in the quarter of 373 million was up C$19 million or 5% over the same quarter last year. The increase is primarily a result of higher electricity prices, lower unplanned outages at our Alberta PPA plants, and the addition of Genesee 3. Those positives more than offset the decommissioning of Wabamun units one and two and the outage at unit four. OM&A expense increased C$13 million in the quarter. The primary reasons for the increase were the addition of the G3 plant, the impact of the higher TransAlta share price on long-term compensation costs and higher current-year plant operating costs. These increases were partially offset by plant maintenance expense that was lower than the third quarter of 2004.

Operating earnings of C$3 million for managing, marketing, and trading keep us on track for annual operating income between C$20 and C$ 40 million. I believe our controlled and disciplined trading strategy really paid off in the quarter, especially when energy markets reacted to hurricane-related disruptions in the Gulf Coast. Our mark-to-market position declined from 28 million to 21 million during the quarter, which of course, further reduces our risk profile. Gross interest expense declined C$5 million in the quarter as a result of our overall debt reduction initiatives. Year-to-date, we have paid down C$200 million of debt using a combination of operating cash flows and cash realized from settlement of foreign exchange hedges on our foreign investments.

In our second quarter conference call I stated we were considering a debt issue before yearend to deal with our 2005-2006 bond maturity. We are still evaluating alternatives.

Moving to income taxes, we recognized a C$13 million income tax recovery in the quarter related to prior periods. This recovery was recorded as a reduction in income tax expense. Net of this recovery, our effective tax rate for the quarter was 31.3%. While higher than the same period in 2004, we still expect to be within our annual guidance range of 25% to 30%.

Turning to cash flows, cash from operating activities was C$149 million in the quarter compared to 143 million in the third quarter 2004. The increase was primarily a result of higher net earnings and lower working capital requirements. Capital expenditures, including major maintenance in the quarter was 77 million compared to 100 million for the third quarter last year. In 2004 we were building Genesee 3 and the Summerview Wind Farm, which aggregated C$24 million. For the full year, total capital expenditures are expected to be between C$335 and C$350 million. The reduction from our previous guidance of 360 to 375 million is the result of the timing of mine equipment purchases between ’05 and ’06.

Finally, as Steve said, we further improved our credit metrics. Cash flow to interest for the rolling 12 months ended September 30, was 4.4 times versus 4.1 at December 31, ’04. Cash flow to total debt improved from 19% at December 31 to 21.5% at September 30. Net debt to invested capital was 44.5% this quarter compared to 46.6 at yearend.

I will now turn the call back to Steve.

Thanks Ian. I’d now like to make a few comments about our Sarnia and Centralia facilities. I’ll also try to provide some insight into what I see for quarter four and 2006. I’ll finish up with an update on our search for a new CFO.

First, an update on our re-contracting plans for our Centralia coal plant. Virtually all the capacity is now sold through the end of 2005. Going into 2006, about 90% of our capacity is contracted for the year leaving only about 10% available for sale at spot prices. As a reminder, we had an original 900 megawatts of legacy contracts that we inherited when we purchased the plant. A contract for 400 of these megawatts expires at the end of this year. The recent rise in power prices and the volatility in natural gas prices are making it harder to find common ground with our customers who need long-term supply commitments. Nevertheless, they continue to express strong interest in finding ways to work through this volatility and to negotiate long-term contracts. In the meantime, we have decided to sign a series of one-year contracts with various counter parties that total 360 megawatts in 2007, 320 megawatts in 2008, and 165 megawatts in 2009. All are at prices in the US$55-per-megawatt-hour range. Consistent with our contracting strategy we will continue to work with our customers to negotiate multiple year contracts for the period of 2007 and beyond. You can visit our website under investor information quarterly reports to see a graph depicting the duration of our contract portfolio as of September 30, 2005. I’ll further update you on the contract status from quarter-to-quarter.

As we mentioned at investor day, coal prices are rising partially reflecting increased prices for fuel and tires. In addition, the extended processes now required to gain approval for mine permits has delayed our ability to activate more cost-effective siting for our production. We are committed to reducing these costs and will endeavor to find offsets to these inflationary pressures. Our options include – finding cost-effective ways to mix mined coal with imported coal from the Powder River Basin; executing diesel fuel hedging programs; and of course, continuously improving efficiencies in our mine operations. We will continue to provide you with updates in future calls.

Turning to Sarnia, we continue to negotiate a contract with the Ontario Power Authority for our Sarnia facility and are confident that these negotiations will be completed by yearend. Once a preliminary agreement has been reached, it will require the approval of the Ontario Energy Board. We do not know how long this will take, but we are confident of a resolution during early 2006.

I will now discuss our outlook for quarter four as well as mention a few comments about 2006. For quarter four, we anticipate power prices to remain strong due to higher gas prices and increased seasonal power demand. We expect the net impact on our Centralia coal revenue will be minimal though, as we are essentially fully contracted for the quarter. The volume and prices were locked in earlier this year. We still have some merchant capacity in Alberta. We will continue to look for opportunities to maximize revenues with this capacity.

For major maintenance in the fourth quarter, we will be completing one coal turnaround, one C (ph) inspection, and some minor work at other gas-fired facilities. The total amount to be spent on major maintenance in the quarter is expected to be 60 million to 75 million with about 65% being capitalized. This will bring our total major maintenance spend for the year to the range we’ve previously told you of 205 million to 220 million. In 2006, we expect pricing to remain strong and to see demand grow. Major maintenance expenditures for the year are still forecast to be 205 million to 215 million with 65% capitalized as we continue to execute our rolling multiyear lifecycle maintenance plan. We will provide you with details by quarter of our 2006 major maintenance schedule in our fourth quarter conference call. As a result of our long-range planning, key supplier relationships, and technical opportunities, we expect to see annual maintenance costs reduced to a new run-rate of 150 million to 175 million post 2006. This is consistent with the plan we discussed with you in 2004.

Finally, I’d like to comment on our search for a new CFO. This past June, we announced Ian Bourne would be retiring in December 2006. We are currently in discussions with candidates and expect to have this finalized by yearend. Once Ian’s replacement is onboard, Ian will shift his focus to assist me during 2006 on longer-term corporate strategy.

That concludes our formal comments for today. I will now turn the call back over to Dan so that we can move to the question-and-answer period. Dan.

As we open the call for your questions, we will take one question with a follow-up at a time and rotate to the callers. We will answer questions from the investment community first and then open the call to the media. We will then respond to web-based and individual investors. So please identify yourself when asking your question. I would remind you that we do not provide guidance and will answer your model-related questions offline after the call. Aggie, we will now take questions please.

Thank you. (Operator Instructions) Sam Kanes.

Good morning. Something we haven’t talked about yet is growth going forward. I’ve noticed in the Power and Finance Risk Journal, there is a C$0.5 billion non-recourse debt being requested by CE Generation. Can you update us on that geothermal expansion of Salton Sea and what preliminary – or maybe final – amount of equity would be required on your part for that.

Let me address that question. I think that request on the financing is a little bit of old news. We were looking at that Salton Sea since we continue to look at what those options are. We’ve not concluded anything at this point. We did want to see what alternative financing strategies might be out there. As you know, we do finance CE Gen on its own two feet, so to speak. So we would drive that financing through CE Gen as opposed to being part of the conventional TransAlta financing portfolio.

Well then I’ll ask it another way. In terms of any contribution from the parent, can CE Generation take this type of growth on by itself?

I think that really becomes a function of once the opportunity, if it comes to fruition, then we would figure out what is the best financing technique for CE Gen and for the two partners.

I understand it’s a twenty-year power purchase agreement with an in credit that has already been approved. Is that correct?

That has been in place for some time. So the question becomes, having negotiated an off-date agreement, the question becomes where do we stand in terms of the building of the facility itself and the cost and so forth. That is what is being worked on in terms of whether those numbers all work.

Is there a timeframe for this? Or is this just an ongoing thing?

This is an ongoing one.

A quick follow-up then on credit rating agencies. Have you had a chance to talk with them lately, Ian? (multiple speakers) get better and better every quarter.

Not in a formal sense. What we’ve done is we met with them in the summertime as we usually do following our meetings in the spring. We will be meeting with them again at the end of this year and go through the latest update in a formal sense for ’05 and the outlook for ’06. So it is a continuing series of conversations.

Thanks, Ian. And good luck with your future.

Matthew Akman.

Thanks. Ian, I want to ask about collateral requirements and what you are seeing. I noticed that on page 12, you disclosed – I think this is a new disclosure – that letters of credit have gone to about 820 million from 440 or 450 at the end of ’04. What are you seeing with power prices? Is that one of the reasons why the contract durations at Centralia remain relatively short?

No. In fact, the durations is – it’s related, obviously. But it’s a different question. The collateral requirements are going up. That is not new disclosure. It’s been in the each quarter for the last little while. In fact, as the prevailing prices are higher than the contract prices, then the collateral requirements do go up. As those contracts roll off and the new contracts get entered into, then to the extent you’ve got a lower notional mark-to-market, then those collateral requirements could go back down again. It’s all within the collateral capacity and the credit capacity that we’ve got as a company. One of the reasons that we have a C$1.5 billion syndicated credit facility. For a company this size, that is generally a little bit on the high side. It’s in order to accommodate all those collateral requirements in the contract.

I guess my follow-up is there are some great upsides foreseen at Centralia. How do you lock that in for a longer period, especially given TransAlta’s profile with the high credit rating and a dividend-paying stock? What are your latest thoughts on how to do that?

From a financial perspective, there are no issues with respect to collateral and so forth that are going to get in the way of that. We make sure that we’ve got enough credit capacity to deal with those. In terms of the strategy on contracting itself, Steve may want to elaborate on a couple comments that he made earlier.

Our goal with our contracting strategy is to, both from a risk profile and from a volatility point, try to reduce both. So what we are endeavoring to do with all of our facilities is to have layering of multiple-year contracts going forward. We’ll continue with that strategy. We will – like to keep a small percentage of our ability open for the spot markets to take short-term advantage. But we don’t want too much open. That then introduces too much volatility to our go-forward financials. I think we’ve got about the right mix right now.

Okay. Thanks.

Andrew Kuske.

Thank you. Good morning. Steve, I would like your thoughts on what we saw earlier this week with the Bruce (ph) Power PA deal and any kind of read-throughs you see from that for the Sarnia facility.

Personally I don’t see any connection between the two certainly in any timeframe that we’re looking at. Our negotiations with the OPA are well underway and are framed around a multiple-year timeframe and should have – that announcement should have no impact on that whatsoever. On a very long-term basis, it’s clear that the decisions that Ontario will take on nuclear power will have an impact on the long-term market. But I see those being out years ’10 through ’20, not years ’00 through ’10. That, I don’t think, will have a big impact on us given our current position.

As far as it relates to prospective returns coming out of the Sarnia facility, obviously there are some great differences. You’ve already got a pre-existing facility that is built and already generating power and was built before the market structure changed a little bit within the Province. So the returns on an un-labor (ph) basis that Bruce Power was talking were essentially – were Trans Canada’s 9.5 to 13.5 unlabored returns. What kind of return structure would you like to see off of Sarnia?

You know our hurdle rates. We’ve stated we want to be a 10%-return-on-capital business, 10 to 12 on a sustained basis. We would look for that as a minimum out of our Sarnia facility. I think the nuclear impact is really for future plants. We’d have to take a look at it. For our existing plants, it should really have no impact on our ability to continue to earn the returns that we’re earning now or slightly improve them.

That’s great. Thank you.

San Joan (ph).

Hello. I think he moved on.

We’ll proceed to our next question from Elizabeth Perella. (ph)

Thank you. A question on Centralia. Could you comment, at least in general terms – you’ve signed a few shorter-term contracts in the mid 50s US per megawatt hour. If you were to look through the existing contracts as they roll off and effectively re-price the 900 megawatt at that type of range, how much of a gross margin improvement is there at Centralia? When do you get there? Is it not till the remaining 500 megawatts roll off? Picking a price at a point in time.

We’ve actually not disclosed that level of information. In terms of the general trend in your question, the margins are moving up as we roll off the old contracts recognizing that there is a faster run-up in spot market prices than there is in the cost of coal. We don’t capture all of that because of the contracted status of the plant. So there is a little bit of a lag. But clearly, the margin is higher this year than it was last year and it will be higher next year than it was this year.

Is it possible – I know that you give us the average revenue realized for the merchant segment and Centralia is embedded within that, but not broken out. Is it possible to say what the average contract prices are at Centralia in ’05?

On our website we provide, other than for the Alberta thermal plants – we provide revenue and production by plant. You’ve got to do a little bit of mathematical gymnastics with the US stuff today because we’ve converted it to Canadian. You can go in there and look at total revenue in the plant and take a look at the production and you can work back into a per-megawatt-hour price. The other thing I would add is, remember we’ve got four of those legacy contracts – the original ones that we entered into – we’ve got 400 megawatts coming off at the end of this year, a 100 megawatts coming off at the end of 2006, and 400 coming off at June 30, 2007. So you can layer in your assumptions on what power prices are going to be at those times and work up the numbers, I think, along with the base of the historical that we’ve provided.

Right. I remember now that you do give it us by plant in those supplemental spreadsheets. Thanks very much.

Winfried Fruehauf.

Thank you. My question is on the Wabamun train derailment. If I understand correctly – and correct me if I am wrong – you have been recording no revenues, obviously, during the outage. But you probably have been recording fixed costs such as depreciation and labor costs and other fixed costs. Is that correct?

That would be correct.

So as a result, if anything, you have recorded these types of expenses, but no offsetting revenues. We can then look forward in the current quarter, hopefully, for a pretty good quarter assuming a reasonable settlement (multiple speakers)?

I wouldn’t speculate on the time of the settlement. But when there is a settlement, it would flow through as revenue. You are right, those costs have been recorded and incurred in the quarter.

We would expect revenue and earnings from the Wabamun facility during quarter four that we did not get in quarter three.

I have at this time one question regarding CE Generation. You commented on the outlook for Centralia, your Alberta plants, and so on. But you haven’t said anything about Centralia. Would you have some comments that would add a bit of color as to what the markets look like and how you plan to take advantage of them.

CE Gen is pretty heavily contracted for the fourth quarter as well. There is not a lot of flexibility on the pricing down there. As we move into the future years, there does continue to be some upside in the existing contracts. Again, it is pretty heavily contracted. There is just not a lot of market pricing in the existing portfolio down there.

Regarding that Centralia, you have been quite successful in reducing your net interest expense. Is there anything that you could do through a refinancing that would lower the costs at CE?

We don’t look at it quite that way. We tend to look at it in terms of the total portfolio on how we finance our interests in these various entities. As it relates to CE Generation itself as a free-standing entity, they are also continuing to pay down debt. So yes, their interest costs are coming down. How we finance our piece of the equity is part of the total portfolio.

Thank you.

Karen Taylor.

I have a follow-up to Win’s question on Wabamun. If I am reading this right, the effect on operating earnings, which I am assuming is EBIT, is 15 to 18 million. But the reduction in revenue was only 10. Can you explain that to me?

Sure. If you think about it in the context of what Wabamun produced last year in revenues and margins, that is the comparison year-over-year. What we’ve identified as the 15 to 18 million is the opportunity costs, if you will, or the foregone margin by not being able to operate the plant during that period. They are two different concepts.

So the 10 million would reflect last year’s revenues on some price per megawatt hour versus zero. The 15 would take into account some price plus the cost.

Correct.

Can we talk about Wabamun for a second. I think the commentary that I’ve heard as you’ve traveled around a little bit during the third quarter is that that plant is still going to come out of service at the end of 2010 and that 2006 – I guess from what I’m hearing – is going to be the year of the bondholders. Maybe this be the job when you hire the new CFO. Can you tell me what you are going to do to replace what looks to be a fairly material contributor to the overall earnings profile.

2010 is when the license expires at Wabamun. At this point and as part of the re-licensing in 2000, it’s a hard stop at 2010 on that plant. In terms of future growth and replacement of that capacity, that goes into the whole growth profile as we go beyond 2006, 2007. Steve may have a couple comments on that.

Clearly we are now focusing a fair amount of time and attention on growth opportunities beyond, let’s say 2008, 2009. Recognizing we have a Wabamun coming out and recognizing there are increased opportunities in the market due to increased demand. We would hope to add new capacity or purchase capacity somewhere in that 2008 and beyond timeframe so that we can continue to grow our revenue. We clearly have our eyes focused on that and are focused (technical difficulty) on looking for those opportunities right now.

So just as a quick clarification then, if 2006 is going to be a year when you focus on the balance sheet – from what I’m hearing – then we’re looking at a potential acquisition or making a material investment in a greenfield project in 2008 with the hope that it would replace the revenues beginning on a full-year basis in 2011?

I don’t think we’d be quite that precise. I would say – the way I would put it is yes, 2005 and 2006 we said would be focused on the balance sheet and earnings. We haven’t lost that focus; we will not lose that focus. 2007, 2008 start a transition period when we have to look more seriously at the growth side. Whether those – then it really becomes opportunistic. When do they happen and when can we implement? I can’t tell you if that will happen in 2007 or 2009. But clearly we are going to try to do our best to make that happen in that timeframe so that we continue to grow the revenues.

The one area that we have declared that we will look at on an ongoing basis is still renewables with a focus on wind. Those opportunities, if they come up in ‘06 or ’07, we will probably pursue those fairly vigorously to see if we can find one that meets our hurdle rate. That is the best I can do right now. That is our plan. We’ll see how we execute it.

Can I ask a quick technical one. How many gas units were done during the quarter? Then I’ll get back in the queue.

I’ll get you that information. We don’t have that at our fingertips.

Okay, thanks.

Bob Hastings. (ph)

Thank you. First of all, let me say how pleased I am to hear you talking about growth once again. One of the things in looking at Sarnia, I noticed the revenue increase pretty much matched the fuel cost increase. Are you suggesting that Sarnia, therefore even despite high electricity prices and improved spark spreads, didn’t make any money in the third quarter?

No. I wouldn’t draw that conclusion. Maybe we need to give you more specifics on Sarnia offline. There were a number of factors at play in Sarnia in the summertime particularly of course, the way they import power versus what they request and dispatch domestically and so forth.

But some of the (multiple speakers) are trading?

Yes. And volume, of course, was higher than last year’s. Maybe that is something we can give you a little more insight into, a little more information on offline.

Sure, that would be great. Let me ask you another one then. On the pricing of Centralia contracts – maybe I just missed this. It sounds to me like we know that the contracts – there are 400 megawatts coming off at the end of the year. I understand that you’ve been up there re-signing contracts for beyond that. I think there is some mention of one-year contracts going out. Can you clarify that for me. Could you give us anything in terms of what kind of pricing levels you’re signing on new contracts?

You did miss it. I did mention that the contracts that I mentioned roughly 360 megawatts in ’07, 320 in ’08, and 165 in ’09 were in the US$55 per hour megawatt range. The existing contracts are in the C$30 plus-or-minus range – 27 to 35 range. To give you some order of magnitude of the current difference.

I am wondering why there wasn’t a 2006 number because there are 400 megawatt coming up. I missed that 2006 number.

We’ve entered into a number of those contracts over time. There is a – I think what Steve was referring to in his comments were those contracts that we had done for post 2006. We’re about 90% covered for 2006 already.

Okay. Thank you very much.

Brian Purdy (ph).

Could I ask for an update on your total spot exposure. Back at the investor day you had indicated something along the lines of C$0.05 per share after tax impact for C$1 change in your megawatt hour spot price. Has that been reduced with the contracting you’ve done at Centralia?

A little bit, but not much. We’ve not contracted very much more for ’06 in Centralia than we had when we did the investor day in July. So I think those numbers are still good.

Okay, great. Thanks very much.

Maureen Howe.

Thanks very much. You’ve probably provided us this information in the past. Just to clarify Centralia and the contracted power, we know that the legacy contracts were at approximately C$30 prices. But you’ve given us 90% contracted number for the year. Since the incremental series of short-term contracts that have been entered for the contracts that or the capacity freed up through these rollovers. I know Steve, you’ve mentioned fifty-five dollars for 2007 and thereafter and then gave megawatt hours. What about the re-contracted amounts in 2006?

We haven’t given that number out. That is the kind of thing I think we provide a little more information on when we’re talking about ’06 in the fourth quarter conference call.

Okay. When we talk about 90% contracted, is it 90% of the 1,400 or 90% of some target availability?

It’s 90% of our expected production. To the extent that we anticipate – there is always a bit of unplanned outage, so you build that into the numbers. To the extent that we have any planned outages, we take that into consideration as well. It would be X percent of our anticipated production.

So would a good – for modeling purposes – a good estimate be about 1,200 megawatts? Would that be the run-rate?

I think that’s a reasonable number.

Thanks very much.

Linda Ezergailis.

Thanks. A lot of my questions have already been answered. Could you elaborate on some of the delays in your mining approvals at Centralia in terms of magnitude and duration of delays and what the stumbling blocks are. It sounds like it’s administrative on the government side. Were these delays baked into some of your forecasts as discussed during your investors day back in July?

I would say that these delays, while we anticipated some, are probably a little more than we’ve built into those numbers. The reality is that this permitting cycle just does take longer than I think everybody would like, including some of the people on the other side of the conversation. Yes, it will put a little more cost pressure in the shorter term. I don’t think it’s a – it’s not something that we’re really worried about in the immediate term because of the pricing side of the mix. But as we look forward we really need to make sure we get this right.

On your one-year contracts that you signed up at Centralia, are those for firm power? What happens if, for some reason, there are unplanned outages or whatever?

In large part they would be firm prices. We always have a blend of some firm and some unit contingent. The majority are firm.

Alright. I noticed in your trading business that the terms of the contract seem to be increasing. Is that related to a change in your production mix? Or is that related to a slight improvement in liquidity further out in the forward markets?

I think it’s more the latter because, remember the material that we provide here in terms of the energy trading, is the non-asset-backed activity. We are seeing a little more liquidity in those longer dated markets.

That’s great. Thank you.

Karen Taylor.

Thanks. the foreign exchange gains that were realized on, I guess, the long-term net equity hedges at 77 million if memory serves. Has that changed the amount that you are looking to refinance in total for the year? I think the number that has been floating around is 500. I am assuming that that would include the amount that was rolled recently as a post-quarter event. Is that 500 net of what? I guess it’s 150 million still that you’re looking for?

I don’t want to speculate on what we may or may not do as we go forward. But your first premise is exactly right. The fact that we rolled over some of the foreign exchange hedges and generated some cash does reduce our overall borrowing requirement.

So the foreign exchange hedge rollover, was that something that was done opportunistically? Or did they actually expire and then you've had to rebook them? Can you explain how all of that came about?

They expired as we anticipated. The fact that the Canadian dollar is a little higher than we had built into our plans means there is a little more cash than we had otherwise expected. But it is within the zone of what we were thinking of doing.

On the taxation side, are there any more recoveries or anything else that we can look forward to? Or is it again, are you extinguishing those as we go forward through time given the lack of coactive businesses particularly in New Zealand?

This one was related to some domestic activities. There will continue to be tax transactions. To the extent that we’re dealing in fairly large dollars with the tax authorities, as these things happen and with the accounting conventions becoming much more a function of accounting for the specific transactions as opposed to taking a blended set of numbers, there will be a little bit volatility around those individual tax transactions.

Just lastly, given the higher prices in the US, does the tax – if we had talked about earlier in the year 25% to 30% effective marginal rate for the year and that would probably have been something – and I think you talked about it before for ’06 as well, we should be trending then to the upper end of the range certainly for ’05. Then for ’06 is that range still valid?

It is still valid. But I wouldn’t characterize it as a marginal tax rate. That is the composite tax rate. Therefore, as we (multiple speakers) higher earnings and the marginal tax rates, which are higher, then you do move to the upper end of that range.

So (indiscernible) the effective rate, then, is the upper end?

Yes.

And that would be similarly for ’06?

Yes.

And just lastly on the mining equipment expenditure deferrals. Is that the primary reason that the planned capital numbers that are reviewed in the release come down?

Yes. It’s a function of when the cash changes hands. You will recall that the capital that gets recorded on the financial statements is when the cash actually changes hands. It is not a function of changed buying patterns. It is more a function of when we think the money is going to move.

So there is really no actual physical deferral of the acquisition. Some of the stuff is hard to defer----

That’s correct.

So it’s basically just a timing issue on the cash.

That’s correct.

Okay. Thank you.

Maureen Howe.

Thank you very much. Just a couple clarifications. The range for annual maintenance post 2006 was 150 million to 175 million. I am wondering about sustaining capital during that post-76 period.

I am trying to remember what we told people in the investor day on that. (multiple speakers).

We don’t expect that to change. We expect that be quite consistent on a forecasted basis.

So what you presented in investor day----

We’ll come up with that number in the quarterly call in January.

Right. And I’ve still got my presentation from there. And then also----

Okay, Maureen, sorry. The number 150 to 175 is total spend. That is not all capital.

Right.

Okay, alright.

I missed the amount contracted at the Centralia plant in 2009 at the fifty-five dollar range. Was it 165 megawatts?

165 megawatts.

Thank you very much.

Winfried Fruehauf.

Thank you. It’s on energy marketing. What was the impact on the third quarter results of having exited an energy services agreement back in April of this year?

Not a number I have at my – off the top of the head. It would be reflected in – Dan can get you the number offline. It would be reflected in both the revenue and the cost of power because that was power that we actually took title to. The margin on that stuff was thin.

Still on that sector, you have hired more staff and you pay your staff better than you used to. There must be some reason why you are hiring more staff. Does it mean that you are trying to crank up the contribution of energy marketing relative to the generating segment?

I am not sure your reference to hiring more staff in energy marketing?

Yes. It’s on page eight in the penultimate little paragraph on energy marketing. Due to an increase in staff and higher compensation expenses.

I wouldn’t connect those two dots. The people – we had some holes and some vacancies, which we’ve filled. I think that is – it comes and goes. On the compensation side, it’s more – I think the comment we made was it was more related to the impact of the share price on some of the long-term compensation programs, a little bit of which flows through energy marketing, most of which flows through at the rest of the Company.

So as far as headcount is concerned, has that headcount changed since the beginning of the year? If it has, by how much?

It has gone up a little bit. In terms of any change in the strategy, that is not a reflection of a change in the strategy. It’s really a function of making sure we’ve got the right number of people on the desks and in the back office and in the middle office.

Final question. On dividend reinvestments, in the third quarter how many shares did you issue under the DRP and at what total – at what average price per share?

I’ll get back to you with that. We don’t have that at our fingertips here.

Thank you so much.

San Joan. Excuse me is your line muted?

What?

There we go. Please proceed with your question.

I wonder if I should dial back in.

Hello.

Excuse me. Please proceed with your question. Your line is live, San Joan. Our next question comes from Brian Purdy.

I want to ask about the potential recoveries at Wabamun. Obviously you are uncertain on the timing. I was wondering, if an action against or a recovery from CN was unsuccessful or only partially successful, was any business interruption insurance available?

No.

Okay, thanks.

Nick Elfner. (ph)

We talked about your maturing bond debt. I notice you have a C$250 million issue coming due in January ’06 and another one, 100 million, in October ’06. What if any asset sales have been seriously considered as a means of further accelerating your debt reduction plan? I’ve got one brief follow-up after that.

I guess I would answer that with we don’t give that information prospectively, obviously. We manage the total financial plan on the basis of maturities in the portfolio and so forth and so on. If we were to sell an asset, we would tell you after the fact as opposed to before the fact.

With your goal of arriving at a BBB+ rating, I think you’ve mentioned by ’07, would that be easier to achieve through paying more debt down with internal cash flow? I am looking at the 175 million common dividend in addition to the 100 million to free cash flow, which if utilized, could pay off your ’06 maturities.

We’ve stated that the strategy of maintaining the dividend and using the cash from operations is the basis for the dividend and the basis for paying down the debt. There is no change in that strategy.

Thank you.

Winfried Fruehauf.

Thank you. Could you say a word or two on what has been happening in the third quarter in Mexico in terms of plant performance. I am not sure if you would comment on operating income levels. If you care to, that would be great.

I don’t have the two plant performances right in front of me. Recalling from my weekly reports, both of the plants ran quite well during the quarter with high availability rates. They generally run towards the high end of our total fleet. So they tend to be in the high 90s. I believe that was the case during the third quarter. Their revenues are steady there because they are all contracted to flow through gas to the CFE. I don’t believe there is anything particularly unusual in the quarter for our two Mexican. Pretty well steady Eddie and good performance.

Thank you.

Maureen Howe.

The question has to do with the treatment of the Wabamun lost operating profit. You talk about continuing earnings taking out the tax benefit. But you don’t seem to be leaning towards adjusting for the Wabamun outage. Is there a rationale for that? What is your thinking in that regard? Do you view it as unusual? Or do you view it as recurring? It doesn’t seem like recurring item.

I think it would be on the basis that it would be speculative to put that in as if it had happened. If there had been a hard loss in the sense that we had cash that went out the door and we reflected that in the financial statements, then clearly that would have been treated as a recurring item. The fact that there was an opportunity cost, we don’t feel that qualified for that kind of a treatment.

In terms of your comments, or Steve’s comments – I can’t remember who actually made them – about looking for similar financial performance in the fourth quarter, is that assuming Wabamun is in or is that assuming Wabamun is out?

I don’t think we referenced that. I think all we said about that was that we expect Wabamun to be fully running in quarter four. It did not run fully in quarter three. Therefore, that additional volume would flow through in quarter four relative to quarter three. I think that is the only reference we made to quarter four on that issue.

Okay. Thank you.

Matthew Akman.

For clarification, the contract for ’07 for 360 megawatts at Centralia, is that a full year? Or does that come on in the middle of ’07 when the 400 megawatts expires?

It’s a full year January to December.

Thank you.

Dominique Barker.

Thanks. I had trouble dialing in for a question. I have three questions. The cost for megawatt hour on the merchant side increased about 20%. I hear you on trying to improve the cost structure on trying a number of things. All those options would seem to decrease volatility, but would certainly increase costs. I am looking at a chart from your investor day – your coal costs. Certainly you’ve shown a big ramp-up in costs to now, but flat going out. Can you provide some commentary on your three-year outlook on costs.

I don’t think that is something that is appropriate for a conversation here. I think what we’d rather do is go through that kind of a thing in more depth at an investor-day type scenario.

So is it fair to say that if I look at your investor day Centralia coal cost, for example, increased. You’ve got it going to 1850 in 2009. That’s probably inaccurate. That is probably on the low side.

I think one of the points we were making in that chart was that we did not expect any more discontinuities on the coal side from things like fuel and tires that would not also flow through the price side. The costs themselves – I wouldn’t – I don’t think we ever portrayed that as being correct to the decimal point. It’s directional as opposed to specific.

I would think to be fair, left to its own devices, given what we see in coal mining inflationary pressures, it will tend to try to push that line up. What we are now is, do we try to take proactive actions in advance of that to try to find ways to mitigate that. What we’ll do at our investment days is review those with you and indicate how we think that will play out over that timeframe, if we have to change that line or not. Clearly, if we didn’t do anything, if we just sat here and did nothing for the next three years, that line would just, on its own, creep up as fuel goes up and tire prices go up and you strip out more overburden. I think the coal dynamic is changing, not just for us, for the industry. I think we’ll go right back and re-look at everything in our mix of mine versus purchase versus equipment to see how we can offset what are natural industry pressures on price or in cost.

Okay, that’s great because you had mentioned mixing PRB coal as one of the options. I think you currently do mix some PRB coal. Would that percent increase?

We would certainly look at that.

So you are looking at it right now.

We would look at that. There are some opportunities. Rail transportation is a restriction. We do have some opportunities in ’06 and then a lot more beyond. So we look at that mix and we are certainly in the process of doing that.

I have a question on Sarnia. Following on Bob Hasting’s comments, the electricity price in Ontario is really high, yet Sarnia was I would say underutilized. I would have thought that it would have been utilized much more. I would appreciate an online explanation for that, if that is possible.

I don’t have enough numbers at the tip of my fingers here to give you that kind of a response. (multiple speakers)

Because on the next – you had mentioned doing an offline conversation. It would be really useful, I think for everyone to understand the dynamics there. Because certainly we saw huge power prices in Q3. Maybe on the next conference call you could address that?

I think the key issue is clearly the spark spreads. The days when you can run on a positive spark spread were a lot less than the days when absolute pricing would have indicated. But we can certainly provide some more granularity, if you want, around that to give you a better sense of that.

Alright, that would be great. And then the third thing. I want to ask with respect to Centralia re-contracting on one-year contracts, I would imagine that would be treated as spot by your rating agencies. I want to know what percent of total output would be considered long-term contracted now. I believe you had a target – I could be wrong – but 70%.

You are right. I think what we’ve said is we would be a minimum of 75% contracted. These kinds of contracts at one year each, would not qualify for long-term contract frequency.

Where do you think you would sit going into 2006 on a long-term contract as a percent?

We will still be in that 75% and north range.

And ’07 as well?

Across the suite, yes.

Okay, that’s great. Thank you very much.

Karen Taylor.

Can you quickly tell me – and I don’t think I saw this in the release – about Big Hanaford during the quarter. Did that actually run? I guess we’ll see it when the production summary comes out tomorrow. Just for now, did it run? If so, what would be the delta versus Q4 or Q3 of ’04?

You’ll see this when the numbers come out. It ran at 123 gigawatt hours in the quarter. Compared to 232 last year same quarter, so down considerably.

Sorry, 232 gigawatt hours.

232 last year. As Steve said in his comments, the spark spreads did collapse.

We know.

We’re not expecting any tremendous change in that on a go-forward basis.

Okay. Thank you.

There are currently no questions holding in the queue.

Invite the media then, Aggie, to jump in if they have some questions.

(Operator Instructions) Harriet King. (ph)

Could you expand on your discussion of when you would find new resources. Were you looking at wind immediately as in more of the type of plants in the 2007-2008 timeline?

Say that again.

You were discussing in answer to a question on when you might be looking at more growth for the Company. As I understand you, clearly you are saying that you would like to pursue wind opportunities and renewables as soon as they came up. But that other types of plants might wait until the 2007 or 2008 timeframe.

Just to again reframe that, we’ve stated quite clearly that our focus in ’05 and ’06 is on our financial performance and delivering higher earnings and improving our balance sheet. We will not lose that focus. In that regard, we want to get very, very focused on any growth opportunities. We made a decision that, unless an outstanding opportunistic one comes up, the only type of expense that we would look at probably in that timeframe would be renewables with a particular focus on wind. Beyond that timeframe, we know that we would like to add capacity to our fleet to start growing our top-line revenues. We will then look at multiple fuel sources beyond that timeframe. As you are aware, a greenfield would take four to five years anyway. Even an asset acquisition is generally a twelve-month plus exercise. Probably not much will happen until the 2007-and-beyond period at the earliest other than on renewables.

Thank you.

There are currently no questions holding in the queue.

I would like to thank everyone for joining us this morning. As we’ve done before, we’ll have some further information on the website by – shortly after the call. Thank you.

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