TransAlta Corp (TAC) 2013 Q1 法說會逐字稿

Hello, this is the Chorus Call conference operator. Welcome to the TransAlta Corporation 2013 first quarter results conference call. As a reminder, all participants are in listen-only mode, and the conference is being recorded. After the presentation, there will be an opportunity to ask questions.

(Operator Instructions)

At this time, I would like to turn the conference over to Brent Ward, Director, Corporate Finance and Investor Relations. Please go ahead, Mr. Ward.

Thank you. Good afternoon, everyone. I am Brent Ward, Director of Corporate Finance and Investor Relations. Thank you for joining us for TransAlta 2013 first quarter conference call. With me today are Dawn Farrell, President and Chief Executive Officer; Brett Gellner, Chief Financial Officer; John Kousinioris, Chief Legal and Compliance Officer; and Todd Stack, Vice President and Treasurer.

Earlier this morning, we released our first quarter results for your review. For those not on our webcast, the results are posted on our website under the Investor section. We will refer to the presentation during the call. All information provided during this conference call is subject to the forward-looking statement qualification which is detailed in today's news release, and incorporated in full for the purposes of today's call. The amounts referenced are in Canadian currency, unless otherwise stated. The non-IFRS terminology used, including comparable earnings, comparable EBITDA, comparable gross margin, funds from operations and free cash flow is reconciled in the MD&A. Per share figures for the first quarter 2013 are based on an average of 258 million shares outstanding, compared to 225 million shares in the first quarter of 2012. Please note, the financial information has been rounded to the nearest whole number.

On today's call Dawn and Brett will provide an overview of our operational and financial performance for the first quarter, provide an update on recent events and activities. And before going to the Q&A, Dawn will provide commentary on our outlook for 2013. With that, let me turn the call over to Dawn.

Thanks, Brent, and welcome, everyone. I am going to start with some highlights from the quarter. Overall, I am pleased with the quarter on a number of fronts. We were able to deliver a comparable gross margin and EBITDA above the same period in 2012, despite the hedges rolling off at our Centralia plant. This was due to increased cash flow from new growth, lower operating [MG&A] costs, and higher production at Alberta Coal and Centralia.

As Brett will show later, all of our business units continued to perform well and contribute to overall growth margins. Our strategy of owning and operating a diversified fleet is paying off. This is demonstrated by the increase we realized in both renewables, which represents 24% of our comparable gross margin, and gas which represents 27% of our comparable gross margin. These two businesses more than offset the slight decline we saw in the coal fleet. Brett will cover all the numbers in more detail. We also continue to deliver availability at 91.5%, in line with our targets, and trading did deliver in line with our expectations.

In the quarter, we commissioned New Richmond, increasing our total net wind capacity to 1,129 megawatts. TransAlta does continue to be the largest wind producer in Canada, contributing approximately 18% of Canada's total wind capacity, with our next largest competitor contributing only 8%. We also increased the amount we hedged in Alberta since the last quarter, and are now 90% hedged for this year. And I will talk more about that later. During the quarter, we also made a strategic decision to assume the operation and management control of the Highvale mine We believe there are operational efficiencies and additional synergies to be gained by relying on our existing teams. Brett will take you through the accounting impact of this decision. In Australia, the Solomon power plant is in its final stages of construction, and is tracking as planned. We started receiving our full capacity payments as you know in October of last year, and the facility is expected to be commissioned during the second quarter of 2013.

I am also pleased to report that we are beginning to realize the benefits from the corporate realignment that we executed in Q4 of 2012. Our OM&A costs are down relative to the comparable period a year ago, and we are well-positioned for the rest of the year. Just a bit of an update on the Puget contract with Centralia. On March 22, Puget and the staff of the WUTC filed a settlement agreement regarding the coal transition PPA. The proposed settlement addresses the primary issues raised by Puget in its January 23 petition for reconsideration. The amended timeline for a decision on the reconsideration motion is now expected to take place no later than June 28 of this year.

Let me spend just a couple minutes on the performance of the fleet. We achieved a total fleet availability as I said earlier of 91.5% for the quarter, a good performance especially considering the availability impacts of the unplanned force majeure outage at K-1. We continue to expect to meet our target of total fleet availability in the range of 89% to 90% for the year. Our planned outages for Q1 and Q2 are going well, and they are going as expected. Just a quick update on spending on the Sundance 4 planned outage. The team is tracking to budget and plan, and we expect to return the unit to service in the next couple of days.

I will make a few comments about the Keephills unplanned outage. First, in this quarter we declared force majeure as the result of a generator winding equipment error which was outside of our control. This type of high impact low probability event was identified at the time that the PPAs were established as requiring a force majeure mechanism. The force majeure mechanism within the PPA is to protect the operator from the penalties that it would otherwise be required to pay, because of its inability to perform for reasons out of its control, or providing the operator with continuous capacity payments from the balancing pool in order to ensure that its fixed costs are recovered over the term of the PPA. Because of this PPA mechanism, we do not expect a material financial impact on the Corporation, as we will continue to receive capacity payments, and will not be required to pay penalties.

Before I move to the next slide you can see from this chart, the rest of the coal units performed well relative to last year, as did our gas fleets. Renewables availability was down from last year, mainly due to increased maintenance required, compared to the same period last year. As we continue to plan and execute three major maintenance -- our three year major maintenance programs, we use many leading indicators to track performance. Within our coal fleet, one operating performance indicator for improved availability is the return on investment, and reducing the number of boiler leaks year-over-year. As you can see from this chart, there has been a downward trajectory, with only four boiler leaks in the fleet in the past quarter.

In Alberta, the rolling average pool price or RAPP was higher, and despite strong availability by TransAlta, the higher RAPP affected the amount of penalties we paid on unplanned and planned outages. This chart shows the higher RAPP prices, and the impact of penalties we pay on planned and unplanned outages. That being said, the continual operational strength of our fleet has enabled us to offset some of the negative impacts from the outage penalties in Alberta, and lower contract levels at Centralia Thermal.

Before I move to the discussion on our core markets, I will provide -- I would like to provide just a brief update on Sundance A. The restoration of the unit is progressing well. It is on time, and it is on budget. We continue to expect that Sun A will come back online in the second half of 2013.

So let me turn to a bit of an update on our core markets. First and foremost, I am pleased to see some stronger pricing in each of these markets. Let me start with the Pacific Northwest, where power prices are strengthening on the back of slightly higher gas prices and lower hydro generation. Mid-C prices are currently averaging CAD40 a megawatt hour for Q3 and Q4. But Q2 prices are lower, due to the reduced hydro production. We currently have Centralia [economically dispatched] down for the quarter, common for this time of the year. The average prices for Q3 and Q4 this year are expected to be about 60% higher than the same period last year. Driving this recovery in price is a combination of higher natural gas prices, and an expected return to more normal hydro production levels.

Moving onto the Alberta market, power prices also showed strength during this quarter largely driven by tight supply demand balance due to outages. Weather-normalized demand was approximately 3% higher than in 2012, which was in line with our growth expectations for this market. The current forward market is indicating a price of CAD63 a megawatt hour for the remainder of the year. These prices are expected to weaken as Sun A comes onstream in the second half of the year. Despite that softness over the medium term, new plants will be required in Alberta before the end of this decade, as a number of coal plants retire at the end of 2019. The market expectations continue to show growth requirements of 2% to 3% year-over-year over this period.

For Sundance 7, our progress continues as planned. And with current market demand requirements, we continue to see how this investment will be competitive and required by the market. It supports the expectations raised by Alberta to have affordable power prices at the end of the decade. We believe the supply from Sun 7 will be needed to meet growth demands in the 2018 timeframe. And our teams are working to deliver these megawatts into the market.

What I wanted to show you on this next slide is how we have taken action to position Centralia for the future. We signed and entered a contract with Puget that secures [client] cash flows until the end-of-life. We have also restructured the plant's operations, below our cost, including delivered coal costs, capital and operating costs. You can see by the chart on the right, that a CAD5 change in price has a CAD30 million impact on average gross margin in the 2013 to 2016 timeframe. When this market recovers, this asset will generate considerable cash.

As I have mentioned before, the key to our success is maintaining high levels of contractedness. The following chart highlights our progress to increase our level of contractedness across the fleet to support revenue certainty. We are 90% hedged for the balance of 2013, and working towards increasing our mid-to long-term hedge levels with new contracts at Centralia, and by expanding our C&I business here in Alberta. For 2013 in Alberta, we have been able to execute a number of hedges in the CAD60 range, which is in line with the current forward prices for the balance of the year. We also continue to focus on our C&I business. Today we have 500 megawatts under contract, and our goal is to expand this business to 600 megawatts over the balance of the year. So let me now turn to Brett, to take you through more of the numbers.

Good afternoon. So this slide shows the generation segment delivered another steady quarter of comparable gross margins, compared to last year. Our contribution from the generation segment was largely driven by the higher production, the lower unplanned outages and also some higher hydro margins. We also added Solomon, which although accounted for as a lease it is included in this chart, and is the primary reason the gas segment is higher year-over-year. We did have lower results from our wind business due to slightly lower wind resources, but that was more than offset by the higher margins achieved from our hydro business. And finally, we started up our New Richmond facility in March, bringing a small contribution to this quarter. But in Q2, we should see a -- we will see a full quarter contribution from this new asset. However, as many of you know the wind resource naturally tends to be lower in Q2 and Q3, than it is in Q1 and Q4, which is typical across Canada. On the other hand, our hydro levels tend to be higher in Q2 and Q3 providing a good hedge against the lower wind.

Our gross margins were further supported by the delivery of CAD17 million from the energy trading segment which was consistent to last year. Our comparable EBITDA was CAD267 million in the quarter, up CAD15 million relative to Q1 2012. And FFO was CAD192 million, up CAD3 million compared with the prior period. These results were achieved despite the lower contribution from our Centralia office operations as hedges rolled off. We were able to offset this decline through the lower planned -- unplanned outages, lower OM&A costs, and the addition of new assets. We are also continuing to see improvement in our OM&A, and achieved a CAD13 million decrease during the quarter compared to Q1 last year. In terms of capital spend, prior to growth and the Sundance A rebuild, to date in 2013 we spent CAD51 million in sustaining capital, and CAD4 million on productivity initiatives. And this puts us process on target for our planned spend range of CAD325 million to CAD385 million. Our estimated spend on growth and major projects continues to be in the range of CAD145 million to CAD170 million, most of which is for the rebuild of Sun A.

All right. I am just going to conclude by talking about the accounting for the mining operations which we took over earlier this year. Under the contract with the previous service provider, TransAlta was responsible for paying all the costs associated with operating the mine, including the annual pension obligations. However, under this contract, the service provider, not TransAlta, recorded a pension liability on their balance sheet, as they were the sponsor of those pensions. Once we terminated the service contract, we are now required to take a one-time earnings charge for the pension deficit, which is an after-tax charge of CAD22 million. We have to make this one-time adjustment, only because we are taking over the plan, even though we always had the liability. The majority of this is non-cash, as it is not an immediate obligation to pay, and furthermore that deficit could change over time due to changes in asset returns or interest rates. Also future changes to the deficit will be recorded in other comprehensive income going forward, not on the income statement. And the only other cash component to the CAD22 million charge is related to the annual payment we would have otherwise made under the contract, except under the contract it was previously in our cost of goods sold. So with that, I am going to turn the call back over to Dawn.

Thanks, Brett. I would like to end my formal remarks today with an update on some of the key objectives that we outlined at the beginning of the year, followed by an update on growth. We set a number of objectives, and we are tracking well on all of them. In operations, we are on track, and continue to expect a full year fleet availability in the 89% to 90% range. We set a sustained capital spend target of CAD295 million to CAD335 million, and we are tracking there. Our Sundance A rebuild is well underway, and our corporate safety results are ahead of target. We are track to deliver the full OM&A savings we outlined in our plan to realign the organization, and to find operational efficiencies from our IT investments. We have already achieved the target of growing our C&I business in Alberta to 500 megawatts. So we have reset this target to 600 megawatts to achieve by year-end.

Let me conclude by providing an overview with a discussion on our growth activities, which continue to drive significant amount of work for the Company. As we are moving further into 2013, we are continuing to see and work on opportunities in all of our key markets, both greenfield and acquisitions. For greenfield, our focus remains in Alberta and British Columbia, and we see some interesting opportunities in Western Australia. And in Alberta, there are more than 5,200 megawatts of opportunity, primarily driven by oil sand. Our work with customers in BC is focusing on the burgeoning LNG industry, where we see about 1,000 megawatts of opportunity behind the fence. I did have the opportunity within the quarter to tour our western Australia operations. Our team in that market continues to focus on growth opportunities with the Australian miners, for developing large-scale projects with power requirements to get commodities out of the ground and into the Chinese market. We see about 500 megawatts of opportunity there.

On the acquisition side, we see and are working on, much of what is a large portfolio of about 11,000 megawatts that have come to the market, most of are -- which are in the renewables, and particularly in the wind space. And we are looking at all of those packages. Altogether this means that we are sifting through about 18,000 megawatts of growth. And if -- all of that will require some CAD36 billion worth of investment. So we believe we are positioned to capture at least a piece of this. We will continue to remain disciplined, as we search for acquisition opportunities. And we know it's your investment that we are protecting, and we will only invest when we see the right set of assets.

When I look at the balance of the year, I see a team that is well-positioned to grow the Company. We are focused on executing our strategy. We are focused on our operations. And I think the first quarter has shown what -- what -- has just got us positioned for what is to come. So with that, I will turn it back over to Brent.

Thank you, Dawn. We will answer your questions from the investment community first, and then open the call up to the media. We will then respond to individual investors, so please identify yourself when asking a question. We also ask that you limit your questions to one plus a follow-up, before reentering the queue, so that we keep things moving along. I remind you that we do not provide guidance, and that we will answer any model-related questions off-line after the call. Operator, we will now take questions.

(Operator Instructions)

Linda Ezergailis of TD Securities.

Can you provide us with some more color on the delay with the Puget Sound PPA situation? And also, do you view that contract as largely a precedent for other contracts, or might they be structured differently? And what other discussions are you having around Centralia contracting?

Puget went back to the regulator with their concerns. They had a number of other regulatory files that they were trying to put together and get solved all at once. That has now all been filed. And I think it is in the normal regulatory process that you have in those jurisdictions, where once they file their settlement, there is time for people to comment. And then, of course, the Commission has go in, consider those comments, and make a final decision.

So it is much longer than we ever expected or anticipated, because I think we got caught up in a process there. But at the same time, the filing that Puget has filed gives us a lot of comfort in terms of that contract overall. So I think the process now is just a matter of us waiting the time for the Commission to get its comment, make its final decision. And as far as I know, and we have been told that decision can be no later than the end of June. So I think that is good news for us.

Once that contract gets signed, I think it does open up the baseline set of conditions for contracting going forward. It is nice that prices are lifting a little bit in that market, because I think it will help people see that some of the pricing that they saw in the spot market in the last three years is not sustainable until the end of 2025. So our team continues to have discussions there. But for sure, they -- I think the market is waiting to see those contracts close. But it has certainly been the basis of discussions we are having down there.

Thank you. And just as a follow-up, recently the Alberta Energy Minister, Ken Hughes has asked the renewable power industry to present proposals that could increase the use of renewable power in the province. Is TransAlta participating in that discussion? And do you view that as all very preliminary, or do you think that this could potentially have some implications on market structure in the medium- to long-term?

Well, as you know the Alberta market structure is -- has been running for a long time, and has got -- there is a lot of implications to it. So any of the proposals that would ever have any impact on the market, would take a long time to sort through and figure out. Being Canada's largest renewables operator, we definitely are participating in that process, and would be working closely with the government. Both to see what the concerns are, and see what the opportunities might be. But it is really early, early days, in terms of all the implications that would have to go into that kind of work, to see how that would work with the Alberta market.

And are there -- is generally -- all the stakeholders on board? Or what would be the divergence of opinions by your perception at this point?

You know what, Linda, I haven't spent 10 minutes thinking about this honestly. I would be speculating, and that would not be a good thing. So I think as the process goes on, we will for sure have views. But at this point, it is pretty early days in terms of that announcement. I think he just started thinking about that last week. And I think as you know, all of that is in response to people worrying about the bitumen bubble, and trying to think about greening Alberta.

Great. Thank you.

Juan Plessis of Canaccord Genuity.

You mentioned your desire to grow via acquisitions. Can you talk a little bit about the potential acquisitions size you would consider in the near-term, and in what markets you are seeing the best opportunities?

Let me give you some comments. And then I will turn it to Brett, because he is in charge of our M&A for the Company, as well as all the work he does as the CFO. But there is lots of different portfolios out there today, primarily wind assets. We do see gas projects from time to time, but less often than we see wind. A lot of the acquisitions that we see are in the US market, very little in Canada.

There -- from time to time, we are seeing a few things in Australia that could potentially makes sense. I would say, just in -- most of the assets we are seeing are fully contracted. There is certainly a lot of competition for them. You see competition from pretty well everybody, who is looking for long-term contracts. So the challenge that we have, is to make sure that if we are going to undertake a set of assets, that there is -- we have a way to add value. Because we don't want to just pay premium, and have low returns. But I will turn it Brett, to give you some color.

Yes. No, we are seeing all sizes, anywhere from single wind farms or gas plant opportunities, and to larger packages. And some of the larger packages might have a component of existing operations, but also some greenfield. Which is a nice mix in that you can fund the greenfield over time, and it just adds cash flow later on. The bigger ones, clearly, we have to think through how those get funded. But each one is quite different. Some might have already put some project financing on them, so the equity component might be manageable.

We do -- but we are going to stay in -- within our return hurdles, and also within our investment-grade parameters. So it is not always a size thing, it is really how we look at those things. And then, does it fit in, and is it something where, to be able to go after by ourselves, or could we team up with somebody, or more than one person to go after them.

Okay. Thanks very much. That is very helpful. And Dawn, you made a comment this afternoon at your AGM, that you are looking at unlocking the value of your renewable assets. And just wondering if you could give a bit of color on what type of things you are considering to unlock that value?

Well, there is, as you know, there is a range of possibilities from just marketing heavily, so that investors actually really see the contracted assets that are in our portfolio, and really the valuation that could go along with those, all the way through to looking at, are there potential vehicles where we could expose that value. So it is a -- and we are 25% renewables. Most of our renewables are covered by long-term contracts. We are seeing some good valuations there. So it is along that range of potential idea.

Great. Thank you very much.

Ben Pham of BMO Capital Markets.

I just wanted to go back to your comments about partnering on the green energy side with somebody. And I think initially when you signed an agreement with Mid-American to look at gas-fired opportunities, I think there was a notion that you could consider adding green energy to that agreement. Any sort of update there?

Oh yes. Mid-Am would definitely -- if we found an opportunity and it was something they were interested, they would definitely come in as a partner. They are not always the best partner on acquisitions for these things that we are seeing where there are other financial players that may have a different return expectation than Mid-Am. So we would better off to partner with somebody else. But in our Australian operations, and in our -- anything that we are doing in wind, they definitely indicated that they would be interested if we wanted them to come in.

Okay. And then can I check on, just your partnership with CKI. Just wondering if I could get a quick update on just that partnership, and what you have learned or gained over time? And how do you see that relationship evolving on a go-forward basis?

Well, they are great partners. We love working with CKI. We have that existing set of assets that we partner on. I think you know we have a good strong working relationship with them. So to the extent that they have assets in Hong Kong or whatever, that they have operating things that they are working on. If we wanted to get access to that, they are very open to that, and things coming back this way. So that partnership has worked really well. I think if we wanted to add assets into that partnership or grow that partnership, they definitely would be keen. They have the same kind of profile as we do, in terms of the kinds of assets that they would look at.

Okay. Thanks, Dawn.

Paul Lechem of CIBC.

You mentioned for Q1 that margins were impacted by higher co-PPA penalties. And I was just wondering which units those penalties were attached to? Was it just on Sun 4 that you are paying penalties or -- I am assuming that Keephills 1 was not. You didn't book any penalties from Keephills1 in the quarter? Is that correct?

You are correct. It was mainly our Sun 4 planned outage. And as you know, once you've got the labor and everything, all the resources in place, you can move forward with those things. Clearly, it does if we do have some unplanned during that period, it has that impact. But Sun 4 would have been the main one. And you are correct on K-1. We did take a bit of a provision, 15%. So there is a little bit there on K-1. But it is mainly the planned outages.

Okay. And so, there were no other units that had any material impact on the penalties?

No, that is correct. And we are anticipating our unit Sun 4 planned outage to be completed very soon.

Okay, good. Thanks. On the Highvale mine that you have taken control of now, do you have any sense of what the rationalization, what the cost synergies might be going forward? You mentioned that maybe some of you are going to need -- can you quantify those numbers at all?

No. I think it is early days there. The key thing there, within the mine there, there are several buckets of cost that you go after in terms of your mechanical availabilities and your equipment and all that sort of stuff. So I wouldn't -- I don't think we would be prepared at this point to put a number on it. But as I think we go through the year, I think we will have a better sense of it.

Okay. And what were the costs over -- under the previous contract? How much were you paying for the operations?

Yes. We don't disclose that level of detail on that mine. But I would say, Paul, in the first year, what it will cost, and what we were paying will be about the same.

Okay.

So there is no real net difference there. It is -- it will be over time that we can add the efficiencies.

Okay. And last question, if I can sneak one in here. The -- Brett, can you just remind me what, if any debt covenants you have? Have you disclosed this, and if so, can you remind me what they are?

Yes. We don't disclose our covenants on our credit facilities. But clearly, we are -- something we look at closely, but nothing we are concerned about.

If you don't give me -- give the numbers out, can you at least give what are the metrics that you track here for them?

Typical ones are similar cash flow type metrics, debt to cap type metrics that they look at.

Okay. Thank you.

Andrew Kuske of Credit Suisse.

Just a question about your assumptions for power pricing in the West Coast and in the Pac Northwest. Do you see any kind of impact from San Onofre and the nuclear facility coming on line later in the year? Is that really in your estimates and in your assumptions for that marketplace?

No, at this stage we are -- we don't see any material impact to, and have not seen much in the forward curve. It is more driven by, as you know, the gas prices, Andrew, and in the spring here, the water level. Water levels are at about 95%, whereas last couple years they been in that 130% to 140%. So we have seen an improvement here. And we are seeing as reported -- as you have seen, it is an improvement in the gas side. But at this stage, no, nothing material. You will see some pickup in local markets within California. But -- and we will trade in, around some of those markets, but that is about it.

Okay. That is helpful. And then just a question on the sustainability of the DRIP. You obviously have quite a bit of take up on the DRIP at this stage. And with the declines of the share price, it creates a bit of a conundrum, that in effect it becomes more dilutive on a per-share basis as you go through this downturn in the market. How do you think about the sustainability of the take up at a beyond 70% level, if we look out another year or two?

Yes. I mean, what -- and I kind of went through this previously. In investor day, we put that on -- the other program, the incremental program, premium DRIP program to help fund some of the capital that we undertook. K-3 is a good example, New Richmond, and to help the balance sheet to some extent. So we see it as a tool, Andrew, of -- but we are very mindful of the dilution. We have both programs, and we can scale back those programs, especially the premium program is quite easy to scale back.

I can't give you -- I am not going to tell you here today that it is coming off next week or anything. But we are mindful of the -- it is clearly adding some benefit on lower interest costs. But we also need to add incrementally -- EBITDA tends to otherwise, we will not continue with it. So it is a tool we use. And it is one we can manage very quickly.

Okay. That's very helpful. Thank you.

Jeremy Rosenfeld of Desjardins Capital Markets.

First a question on the contracting strategy overall. So you put some new contracts into place in the quarter. And I am just curious, how you reconcile the desire to increase hedges, especially in the Pacific Northwest market, with recognizing that prices are still relatively low, and likely to rise in the future? So how quickly can you -- do you want to put on more hedges there?

Yes. That is a good question. So we manage our portfolio as a whole. So when you look at our contracted level, that is for the Company overall. And that is taking into consideration our PPA assets, all our long-term contracts. And then, we add Alberta and the Pac Northwest together. So what we do is we ask our team to look at that level of contractedness, keeping both markets in mind. So if they see higher prices in Alberta, they can contract off Alberta, and leave Pac Northwest open. If they think prices are rising in the Pac Northwest, they can start to take some of it off the table.

As you know, in that market, you might have water 130 one year, 95 the next, and 130 the next year. So if you start to see some prices rising there, you might want to get a few contracts off the table. So we look at it as a whole. So if we, if we like some of the prices we have seen in Alberta this year, and some of those forward prices are going into next year. So we have the ability to flex between Alberta and the Pac Northwest.

Okay, great. And then I don't know if you can add a little bit just in terms of the timing, of the contracts that you have put into place. Are they more back ended, with the additional capacity that is going to added towards the end of the year? In the Alberta market specifically here?

No. We don't really disclose that level of detail. But our portfolio, do consider how much -- they do consider when there is an increase in merchant, when those units come on for this year and next year.

Okay. Great. And the other question really that I had, it just relates to the overall growth -- and presumably if you are looking at adding fully contracted cash flows into the mix, what kind of return expectations would you have for that type of -- for those type of projects, let's say?

Yes. We have talked -- what we have said to the market before is that our overall average project IRR is in the that 10% range. And so, we will lower those returns, the more contracted, and the more stable the assets are, and we will increase them, if there is more merchant. We are not looking to add merchant. So for the most part, we are in that range of kind of 8% to 10%. But 10% being sort of the average for the portfolio as a whole.

And those are guidelines. (Multiple Speakers).

Those are guidelines.

Each asset we look at separately, and analyze the risk, and where it is located and --

And the competitiveness of the project. Some particular projects, for whatever reason there is not as much competition. And so we can sometimes get a higher return, with a lower level of risk.

Great. Those are my questions. Thanks.

Robert Kwan of RBC.

Just first question on Centralia coal cost. The guidance now is for a decrease of 6% to 8%. Just wondering what changed in the last couple of months from the previous guidance of a decline 9% to 11%?

Yes, it is just as we made it through some further negotiations around the coal, that is what allowed us to do that. Clearly, it is also a function of how much coal we move and so on. So we factor that all in, Robert, and just try to update it as we -- as new information comes through, or we have negotiated some new arrangements.

Okay. So just to be clear, the most recent contracts you have added since then, have been at higher prices?

Well, we have -- sorry, when I talked about renegotiated, it is both around our -- it is our full delivered cost, so both the commodity and the rail. And as we negotiate some of those and finalize them that will -- what we update and reflect.

Okay. And then just going back to a question, and Dawn your answer earlier around the acquisition markets. You talked about your returns. But given that you have mentioned that competition is quite fierce for highly contracted assets. Just wondering outside of say, the Alberta market and maybe Ontario, what types of things do you think you can bring to the table that can allow you to achieve the healthier returns, despite all that competition? And there was a comment around Mid-American having some -- I think it was mentioned as different return expectations? I am just wondering if you can give some color around that as well?

Certainly, as assets come to the table -- what you see is always an aggressive competition at the front end, as packages are coming. I have seen times before, whereby the -- you have to just keep going through the process. Because that sometimes by the time you get to the end of the process, a lot of people have fallen away because they have taken stuff off the table. So that is helpful. We do find sometimes that there are projects people may or may not want, because they don't like the -- let's say it is a pension, they may not like the operating risk. So we understand all the operating risk, so that helps us.

I think the key thing is -- all I was commenting on with Mid-Am is, if there are other partners that have more return expectations who need a partner who is in operator, sometimes they might be a better partner for us than Mid-Am would be, because Mid-Am is both a strategic and an operator. So they may have -- and they don't need partners. We do.

So I think each different, each situation depending on the size of the bid, depending on the competition for it, brings a different set of conditions. And we look at all of those. What you are hearing from us is that we are not seeing things where we would say, okay, let's dive down and take this one on, because we think we can recover the returns on it. We will let a lot of things pass and go by us. But I am also pretty optimistic, in terms of some of the things that I have seen, that there are things that we can add value to that would help us get the return that we need.

Right. And I guess, just with that, are -- without obviously getting into specific packages that maybe have already traded, have you gotten deep enough into the process and final rounds, that you feel that the types of returns that things are transacting at, that you are close? And it is just a function of coming up with the right situation versus the returns that you are looking for?

We don't want to comment on individual processes, Robert. But I would say, that it really depends. If it is one asset, highly contracted, that is going to be highly competitive as you can imagine. If it is a few more assets, with a mix of things like Dawn talked about with greenfield and development risk associated with them. Or it is a newer asset, with not a lot of history, we might get more comfortable than that, than somebody else.

And then when we are in Australia, it is a different picture. Because we can bring our operating experience behind the fence to bear there, where others may not bring that. So, price is not always the factor at hand. They also want to make sure they are -- whoever the op taker is, is lining up with a party that has proven themselves to run operations. So each one is different. I don't want to generalize about any one situation. All we are saying is there is quite a bit we are looking at, and we think we can compete for some of that.

If you are asking have we have got deep enough in that we know where assets are trading at, and what the returns are, the answer is yes.

Okay. That's great. Thanks, Dawn. (Multiple Speakers).

And we know what the prices is.

Okay. Thank you.

(Operator Instructions)

Charles Fishman of Morningstar.

Slide 9, on the Alberta power market outlook. The way I understand it is, is the downward trend in the latter part of this year is more of a supply issue than a natural gas, based on your comments and the bullet point there. Do you -- and then specifically, I guess the return of the Sun 4 is what drives that. But if we go into 2014, are you seeing any other supply additions? Are we to just a natural gas-driven market at that point?

Well, Alberta is not really a natural gas-driven market. So Alberta has two major impacts on it. About 50% of the time, it is driven by gas, and the other 50% of the time, it is by outages. And how the potentially stack up on each other. So I don't think through the decade, you will ever see Alberta be driven by natural gas. It is a long ways away from there.

We do see past 2014, there is a big power plant coming on, I think in 2015, which will affect supply and demand. But in Alberta, if you grow by 2% a year, you add 200 megawatts a year. And if you grow by 3%, you add 300. And it is a huge difference over three years. So it is a -- you are either 900 megawatts or 600, that is 300 megawatts. So that can make a huge difference to how the market trades.

Well then, on the demand side when -- you said 2% to 3% growth, what time period were you looking at when you make that growth?

Yes, Alberta has been growing at 2% to 3% for a long time, and it is forecasted to continue to grow there in that 2% to 3% range, because it is a pretty hefty economy. So it grows at 2% when things are a little slow here, and it grows at 3%-plus when things are more normal, which is way faster than most economies. So like I say, it is about a 10,000-megawatt market, so 2% is 200 megawatts, 3% is 300. And that is a whole power plant a year.

Yes. Okay. Thank you.

This concludes the analyst Q&A portion of today's call. We will now take questions from members of the media.

(Operator Instructions)

There are no questions from the media at this time. I will turn the call back over to Mr. Brent Ward for our closing remarks.

Well, thank you for joining us today for Q1. If there is any follow-up calls, we are available after and tomorrow. So thank you very much.

Ladies and gentlemen, this concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.