Thank you for standing by. This is the Chorus Call conference operator. Welcome to the TransAlta Corporation 2015 Second Quarter Results Conference Call and webcast. As a reminder, all participants are in a 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’d like to turn the conference over to Brent Ward, Director, Corporate Finance and Investor Relations. Please go ahead, Mr. Ward.

Thank you, Zubin. Good morning and welcome to the TransAlta second quarter 2015 conference call. My name is Brent Ward, Director of Corporate Finance and Investor Relations. With me today are Dawn Farrell, President and Chief Executive Officer; Donald Tremblay, Chief Financial Officer; John Kousinioris, Chief Legal and Compliance Officer; and Todd Stack, Vice President and Treasurer. The call today is webcast. I invite those listening on the phone lines to view the supporting slides, which are available on our website. A replay of the call will be available later today and a transcript will be posted to our website shortly thereafter. All information provided during this conference call is subject to the forward-looking statement qualification, which is detailed in our MD&A 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 gross margin, comparable EBITDA, funds from operations, free cash flow and comparable earnings are reconciled in the MD&A. On today’s call, Dawn and Donald will review our second quarter operational and financial performance, providing update on recent events and activities and then open the call up to questions. With that, let me turn the call over to Dawn.

Thanks Brent and welcome everyone. As always, we have a larger report on our call today. But before we get into the quarter, I would like to take a few minutes just to provide some thoughts on what's happened since our last call. As many of you know who follow our company, there was a change in leadership of the Alberta Government since our last quarter and this has led to a lot of questions and a lot of speculation about the impacts to TransAlta. I want to just tell this down to its simplest form, we worked successfully with governments for over 100 years in this province. We have been successful in other markets and maintained equally strong relationships with the governments in those markets. I will provide later in the call some comments on our strategies and successes. But I just want you to be assured that we do expect to be successful here in Alberta with the new government and we are positioned to both adapt and succeed regardless of the changes in the environment here. I also want just to remind investor guys we really take accountability for this because I think we haven’t been doing enough to be clear about who we are. TransAlta is not and I say not exclusively an Alberta company focused on coal generation here in Alberta and we do not rely solely on the business here in this market. We are a highly diversified, highly contracted company and we've made significant progress on our gas winded hydro operations that provide stable cash flows and these cash flows are generated from assets that are located across Canada and the United States and in Australia. We do need to take accountability for not reminding you enough about the significant values of our…

Thank you, Dawn. As Dawn mentioned earlier, our quarterly results were negatively impacted by low volatility in mechanical and locked in energy marketing. As a result, our EBITDA totaled $183 million during the quarter, compared to $213 million last year. Keep in mind that our second quarter is always our lowest quarter due to higher level of planned maintenance. Year-to-date EBITDA is $458 million compared to $523 million for the same period in 2014. Canadian coal delivered $71 million of EBITDA, down $12 million compared to the same period last year due to lower availability. The impact of lower availability in April and May was most mitigated by low pricing in these periods, which lowered the associated penalties. Also contributing to the shortfall in mechanical was the impact of mark to market losses on future financial contracts that don’t qualify for as accounting treatment. These future contracts provide stability to our cash flow and our solid economic edge for future generation. However, in the rising price environment as we faced in June, the increase in forward pricing generated a mark to market loss. U.S. coal delivered $11 million of EBITDA compared $16 million for the same period last year. We took advantage of low power price earlier in the year to take those changes offline and complete our annual maintenance early. The units were back to service in June and are now ready to capture higher price in the summer months. U.S. coal was also impacted in Q2 by negative mark to market on certain future financial contract. These also are solid economic edge of future generation but don’t qualify for as accounting, therefore, creating volatility in our EBITDA. U.S. coal is about 7% of our EBITDA, and generated secure cash flow through registered deal answering that the unit and…

Thanks, thanks Donald. I will start by briefly speaking to the Alberta and Pacific Northwest markets and our hedging in these areas. We did see Alberta prices pick up in May and June but we do continue to believe that Alberta remains oversupplied and power market fundamental support a lower price environment. Given our hedging levels in 2015 and 2016, we do continue to be protected from the downside. As for the Pacific Northwest there has also been some uptick in pricing over the past few months. Accounts who were ready for this having undergone some early maintenance and we captured this pricing is in June and are well positioned if that should continue. But it's still a struggling market there overall because of low gas prices. As I mentioned earlier in the call the change in the government leadership in Alberta is a topic of interest for our investors. As you're likely aware the government announced changes to the specified gas emitters regulation we call it SIGURD here in Alberta on June 25th. It wasn't a surprise as Premier Notley and Minister Phillips were both upfront that there was work being done and the announcement forthcoming. We're supportive of the phased in approach to these changes as well as the commitment to use the phased in approach for any changes that may occur in the future. The changes announced resulted incremental increases to the current intensity reduction target and cost of compliance over the next three years. These increases are essentially a tripling of the compliance cost and will be significant to generators depending on their inventory of asset credit. This will have a limited impact on TransAlta in the short term as these costs are mainly passed through to the buyers under the terms of the PPA. We…

Thank you, Dawn. We’ll take questions from the investment community first and then we’ll open up the call to the media. And so we can do that now.

Thank you. Ladies and gentlemen, we will now begin the analyst question-and-answer session [Operator Instructions]. Our first question is from Linda Ezergailis from TD Securities. Please go ahead.

I just have a question if you could maybe give us a sense of the magnitude of the effective mark to mark losses on your Canadian coal and U.S. coal operations. And did I hear correctly, you said some of that will reverse in Q3?

The answer is yes. And it’s like roughly within the region of $20 million for both units together.

And you can’t stratify that between the two?

It’s probably like I would say $12 million to $13 million in Canada and the rest in the U.S.

And can you give us a sense, just as a follow up. Have you had any updated discussions with the debt rating agencies recently post some of your discussions with the government and this regulatory decision on Monday in the Q2?

We are having like a lot of discussion with our rating agency, we’re talking basically in constant discussion with them. They don’t seem to be too -- they don’t have much question on the change in government I think they basically -- they have been invested this for a long enough, they know that government come and go and policy change. And so they are comfortable with that, and so not much question on this.

The next question is from Matthew Akman from Scotia Capital. Please go ahead.

My question is on the acquisition that was announced on Monday, the valuation metrics that were attached to it in the press release. And then to take here I am wondering how you guys calculated the enterprise value multiple, whether you included the tax equity and the TEV and what EBITDA?

It’s excluded from the valuation.

Can you please expand on that?

We haven’t include the -- we're using the EBITDA after tax equity [Multiple Speakers].

And what about…NAV as well?

I think it’s including the enterprise value.

The net present value of the assets repayments are included in the enterprise value.

And what did you guys mean when you said 9.6% cash on cash return, what cash?

That’s cash on the net investment after tax equity and after debt, so we did cash on cash on equity.

So the 70 odd million piece?

Exactly.

And is that calculated all in U.S. dollars?

Yes.

How do you guys plan to finance this, it’s my last question.

Like fully, I guess part of the portfolio of assets that could be drop down in times also renewable at some point in the future. So initially it’s transaction done by TransAlta and it’s part of the portfolio of asset that could be drop down into TransAlta renewable at some point in the future.

The next question is from Ben Pham from BMO Capital Markets. Please go ahead.

Just following on that last question about the acquisition, and just thinking about the Wyoming transaction, you acquired that through the renewable vehicle. And I am just wondering as you think about future transactions going forward, can you walk me through the process of -- on an acquisition, how you determine that TransAlta Corp vehicle versus renewable?

Well, I mean I think it’s the simplicity. The way we think about it is that TransAlta renewables is really the vehicle for the contracted assets after everything. So sometimes we are developing assets and getting them organized, getting them integrated, figuring out where the synergies are. So we do that, all that development work is done through TransAlta and then once the assets are in-house integrated and ready to go then we tend to side win. The appropriate time is to drop them into renewable. And of course as you know right now our plan has that we need to do sort of one more drop down to get to the debt levels we want to get to. But after that it's really the cash that we would raise that the TransAlta Renewables would be used for growth. So we will make sure that we're ready to go with using that cash for future development. There is the possibility I guess if we saw something that we might want to acquire, we could do it directly into TransAlta Renewables and we would do that. But in this particular case just the way that we are restructuring that it made sense to bring it in-house here and as we're thinking about future drop downs we're probably tucking in with -- we've got just two in-funds from our Suncor deal then the long-term contract from the new -- from Poplar Creek might be something that fits into TransAlta Renewables. So it just forms part of some assets that we would do in the future. So we don’t carry any cash in TransAlta Renewables for development. Al that cash is paid out or used for whatever amount of capital as part of the sustaining capital. All of the development gets done here. So you will see as we do this have to make sure that the compensation to TransAlta is correct for the amount of time and effort and money and development dollars that we put into doing these things. Does that makes sense then?

Yes, no, no, thanks for clarifying that. And my second question is on energy marketing just trying to get more color and get into a little bit more. Can you comment on the volatile condition, was this in Alberta that occurred and some regions and was it gas power and was it just one specific optimization tray that one thought a way was it …

Yes, I think …

… for that transaction?

I mean you saw the big run up in Alberta at the end of June so you can imagine that was part of it but also there was -- at the same time there was another region that did sort of the same thing. So you kind of two correlated, two markets that were normally not correlated, correlating at the same time and so that's where the -- and it was pretty significant runs up. And as you know when prices are at that high liquidity can drop pretty quickly. And that’s, that was the issue.

Okay. Thanks a lot though. Those are my questions.

Thanks.

The next question is from Robert Kwan from RBC Capital Markets. Please go ahead.

Good morning. Just was on the Alberta power price outlook and specifically just coming out of MSA decision. I am just wondering where do you think the AUC's ruling is going to have a broader impact with respect to the bidding practices of others?

I can't speculate on that, I have no idea. I mean I think that decision is 200 pages. We're mostly looking at it right now in terms of whether or not we should be thinking about a feeling. We have another team that's starting to look at it relative to what it means for our -- how we think about bidding because they very clearly laid a higher expectation on PPA. So I would imagine anybody with PPA would be reading the decision carefully as well for that. We haven’t come to any conclusions ourselves because we just need the time to do that. So I wouldn’t speculate on that. I think if you understand how the market works and it will be decision -- we might have an assessment on that but we haven’t seen any real change in the forward pricing as a result of the decision. So, but it's hard to say Robert.

Okay. Thanks. I guess the second question I have here is, based on what you did in the second quarter really kind of being good proactively taking down units and kind of scoping them out to get into them before you end up with a more severe, potentially severe forced outage. The good part being going in on your timing in terms, I am just wondering does this change anything structurally how you are thinking about maintenance going forward in the sense of risk mitigation but if anything is there higher spending or increase call it planned downtime to sure that you …

Yes.

… overweighed the forced outages?

Yes, it's a good question because especially Sun 1 and 2 get towards the end of their lives it's, there's a big trade off that you need to make there. I think actually overall it does reduce the capital rather than increase it because you are always doing, you are doing that planned forced outage effectively and you have more control, you have all your equipment ready to go and usually get monitoring stuff and they can see that it's getting to a place for this to do that. But you tend to have more control of your capital, that actually seeds into less routine spending because you have less emergent work. So that's what we've seen so far. In terms, so I would say kind of overall if you can get into that practice, so if they're trying to do it today, it gets you in more control and allows you to be more control of your cost overall. So that, and if you think about it, in the first quarter they took some proactive steps to go into known parts of the boilers and really go after places where they thought they had some weakness in the boilers. So we had some lower availability Dan, and we've seen great performance from those units from a boilerly perspective so that's started to pay off in the second and third quarter and in the quarter we just went through we should start to see, we'll see, we're not seeing the same kind of the rates we normally see, and has been cooler here which is helpful but the cooling parts very high, because as you know those are trailing effect of that. So, I feel where all the expectation is they're more in control of their capital and, but it's not, it's not big amounts of capital but they're more in control of their capital and that tends to be true for the operating costs as well.

Right, if I can just make sure I understand that Dawn. So you're talking about reduced capital, is that versus avoiding the potential for major forced outages often at time a very high pool prices.

Right, so the economics that they do, is as you know they, we pay penalties under the PPA if we're below the PPA availability and the penalties are based on the rack. So if they're in you know, so if you manage to the quarter, if you can't manage availability to the quarter it's actually not a great way to do it because you trying to hit an availability target but you're actually losing economics. But if you say to yourself okay we're in June, rap is low, we know that we're going to have, the condegers are going to start to get plugged up here because of the hot cooling pond. In that case the cooling pond was already high. We're going to have significant D rates. What they do is they run the models and they go let's take the outage now proactively, clean the condensers, get ready for the next couple of months. So it's that kind of work that they get a couple of benefits, they get to do it under the lower prices, for the penalty as opposed to waiting and seeing what the prices might be the future because Alberta as you know can be very volatile when it comes to pricing. And then secondly they can, they, much more in control of the work, because they're actually taking what I call a, a planned forced outage. So counter the forced outage in our statistics but they're planning to do it and they know when they're going to do it so they get the guys lined up, the equipment lined up. And those tend to always cheaper to do because you're not in an emergency.

Right, thanks. Thanks Dawn.

[Operator Instructions] Our next question is from Paul Lechem from CIBC. Please go ahead.

Thank you, good morning. Maybe just another question related to following on the last conversation around these cooling ponds and the D rates. I don't suppose there's any way of actually quantifying the impacts of Q2 results given the D rates are kind of mixed up then with some of your outage work. Or is there, could you give a financial impact. And then sort of related to that, is there anything that you can do to the actual design of the cooling system to avoid or mitigate this impact going forward.

If Donald would take the first question, I'll take the second one.

Like we don't have the specific or like number for the financial impact of the outage Paul, so sorry about that. Like maybe we can follow up but like I don't have the number with me now.

And in terms of the actual, so these cooling ponds, this cooling pond at Sundance was a new design for day one for hot temperatures, hot years. And so the, and it's usually, Wayne's not very happy with me because it was hot last year and I said oh, it's usually not that hot in Alberta, so it's not that hot and Alberta and then of course it was hot this spring. So the problem is the economics of improving the cooling pond situation for the one in ten years to the one in eight years that it's that hot, because we do D rate every year but it's different in asset D rates depending on the heat are huge like you couldn't justify the capital that goes in. So we always have that sort of trade off between D rates and forced outages. But the guys are looking at, is there, you know are there temporary cooling ponds they could bring in and they're always doing those economics of would that pay off against taking an outage or taking a D rate. But it's the one they designed in the 70s for those six units. It's interesting when, it's not interesting but when Sundance 1 and 2 were down for that kind of two years there, actually we didn't have this problem because we only had four units on the cooling pond and of course they're all running now.

Good thanks. I just wanted to maybe circle back to the comments you made going on the climate change discussions going on in Alberta and I think you said that you're not opposed to coal transition and potentially bring the plants down early. So I'm just wondering, a suitable compensation I guess, is that the reaction to talks are going at this point or you feel that there will be an earlier shutdown of coal in the province or you're trying to put forward a, bit of a, more of a dispatchable model around the coal.

Yes, yes. We've got actually several models that we're working towards so what I'm trying to do is create the dialogue that really gets people to think about what the trade offs are, because Alberta's economy is weak right now, nobody wants job losses and of course I don’t want any of our people that are working in our coal plant to have to suffer job losses early when really all of them know right now there is a coal transition in place, they know when the units are starting to shutdown and especially in our communities around our plants, I mean those communities are robust because of the coal plants. We have a good Stony Plain and good growth. They received community development funds from us. They get service taxes from us, which support the communities and the jobs for our communities. So, what we’re trying to do is set up a modeling and a conversation that says okay, share the jobs, and share the spinoffs of the job and a lot of those job spinoffs, it’s about 10 jobs for one job in Edmonton. So, it’s a big spinoff, share the jobs care the issues with -- we've been fighting on this cost of front but if you want to reduce the delays of time of the coal plant and you will be putting the M&A expenditures in on NOX and SOX, and that’s how we got our transition to work in Centralia. They wanted us, I don’t know if you recall, but they wanted us to put $600 million scrubber in Centralia. And instead we put a $20 million piece of equipment and to reduce NOX slightly and do the community development funds. So, we’ve got them thinking about what are the different options around and what…

And last question for Donald. Just on the question around acquiring the U.S. renewable assets into TransAlta. Is there any tax benefit in doing that? I remember with the Wyoming when do you sort of [indiscernible] tax loss that you can utilize. Is there any tax benefit and what are your tax losses remaining in the U.S.?

So clearly there’s some tax benefits that you have like a huge amount of tax also in the U.S. and when we’re transacting and acquiring assets that are taxable in the U.S. that create some benefit. So, that’s part of the equation of putting those assets in TransAlta’s first and then structuring it in a way that we can transfer them to renewable at some point in the future.

And what are the tax losses that are still available in the U.S.?

Yes.

And what are they?

We have roughly $600 million to $700 million of tax losses there that we can use in the future that are not even reflected in our balance sheet because with the size of our business in the U.S. now we cannot show what that will bring get value for those tax losses unless we do acquisitions.

This concludes the analyst question-and-answer portion of today’s call. We will now take questions from members of the media [Operator Instructions]. Our first question is from Charles Fishman from Morningstar. Please go ahead.

I am sorry I am actually an analyst I got confused here. But Dawn if I could go back to your comment on the energy marketing loss, and you said it was a leadership issue. I am assuming then we’re not dealing with a rogue trader issue, is that correct assumption?

No, we’re not. Not at all.

And then the fact that you’re back on track for the $40 million to $60 million and energy marketing you expect your mark to markets to reverse you felt like you brought some of the maintenance forward. I guess what is moving your expectations to the lower end of your EBITDA guidance range? I am not tracking that.

Well, I mean I think in the -- just looking at kind of where we are and some of those mark-to-market losses reverse this year and some of them reverse next year. And if I look at the overall availability, I mean, it all has to work so right now I am just being cautious about just in terms of thinking about the availability for the first six months compared to the availability for the last six months, I would tend to be in our lower range on availability. So when we work that through the models and our expectations for pricing in Alberta are probably, maybe weaker than others might be.

And keep in mind, like the mark-to-market are full reverse are the one on our generation because we have the generation to back start it, some of those losses may not reverse as well because they are like real trading loss.

And when I think about the 40 to 60 I am at the low end of that range for trading, they had excellent fourth quarter that would get into the higher range but I am not putting that in my expectation, I am putting it more in the lower end of the range.

Okay. Thank you for the clarification.

Okay. Thanks Rob. We'll get you in the right queue next time.

Your next question is from [Indiscernible] from Morgan Stanley Investment Management. Please go ahead.

Hello, good morning guys. This is [Indiscernible] Analyst Group actually. On referring slide 11, I just wanted to clarify, you calculation is near debt in as of 2014, does that includes the, include the non-recourse debt as well?

It does include the non-recourse debt.

Okay. And so if I get it correctly, as of the first quarter your revolver was up to 680 million and then you will use the 212 million to pay down some of the revolver but you will be drawing again for acquisition that you just announced. At the end of 2015, can you give a sense of what you think your revolver is going to be?

Clearly like our plans for this year was reduction of 300 million to 500 million and that will be mostly on our revolver. So if you look at the number we have today, you should assume it will be roughly like 300 million, 300 million to 500 million lower at the end of the year.

3 to 5.

Million lower.

Got it.

Because we have no more maturity on our debt this year. So like all the additional proceed will go and reduce the bank facility.

Okay. Okay. Thank you.

No problem.

The next question is from Jeremy Van Loon from Bloomberg News. Please go ahead.

Good morning. Just a quick question on the earnings at the coal division. It seems like or the gas division, it seem like it was one of the first quarters that it exceeded the earnings at the Canadian Coal division and I am just wondering it sounds like that's going to return to the normal ratio in the coming quarters. But when would you anticipate that gas would have sort of much more significant portion of overall earnings on a consistent basis?

Dawn?

Well just, so the gas is up because of the pipeline that we built last year in Australia. So those earnings we're trying to get, I think we got a full year this year.

Yes. Like, like.

Maybe less than month or something.

Yes like we …

Yes.

... commissioned in February.

Yes. So we're going to get 10 months of that this year and then 12 months next year and then in 2017 you will see that Port Hedland come through. And so, you will start to see gas really coming, creeping up there.

Our expectation is I think 80 million for like increased accretion when South Hedland is fully commissioned in 2017.

So and 2017 will be half year at South Hedland and 2018 will be a full year at South Hedland.

Okay.

And so, and I just -- our guys can do some transformation. Remember coal will be, will start to list in 2018 as the PPAs roll off with Sun 1 and 2 so it will creep ahead of gas. And then we will keep, our growth plan is around gas and renewables so two together should start to, right Canadian Coal is 40% if you add in U.S. Coal at 47%, that will start diminish if we get more growth.

An d a question just to follow up on your comments on the conversations you are having around policy changes here on green house gas submissions in Alberta. You mentioned a number of different options, I mean which one would be the optimal one for you guys and what sort of price range if you were to translate it into price for carbon per ton, I mean what would that look like at the moment?

It's hard to say that price per ton carbon per ton, so let me just set that aside we will think about that. But the way I think about it is I think the optimal solution for coal plant is a solution that keeps people working the longest and keeps prices down for consumers for the longest period of time because I think overall that, been tough times here right now in Alberta for sure and there is a lots of people that work in the oil and gas industries that pay a lot of bills here. So I think that something that's moderate in prices for customers. And the other thing to think about is 65% of the power sold in Alberta is sold to the oil and gas industry and their trying to get their cost structure aligned at $50. I don’t think anybody in Alberta is thinking that pricing oil and gas are going to 100 again if they do that's great but costs are on everybody's mind. So I think cost and jobs would be at the top of my list but you were talking the environmentalists, shutting down coal early would be at the top of their list. So I think that's where the -- but I do we think, I had some interesting discussions with people in the environmental community and we had this asset actually when we were doing Centralia and they actually don't want to be seen to be costing people their jobs, they do not like to waste capital, so they don't want us putting in weights of capital into plants that are going to shut down. And I think if they had they would like something where you transition from coal to renewables and storage versus coal to gas to renewable and storage. So there might be a way to get a meeting of the minds there. But I can't speak for them, these are kind of conversations that we're in.

And your comments on, if you speed up that transition from coal, you end up getting some kind of you know gas based system more so than a renewable one, I mean at what point does that change and you have a more renewable basis that becomes the obvious.

We've got lots of modeling work to do on that but it really depends on storage, so luckily we've got excellent choices, we on the hydro storage here and another way to create, to create surges to go to gas pieces there's this gas to mine cycle plan. But Alberta's been 82% system load factor, right, there're kind of five people here and a ton of industry. And so there's only about 10% of the load, it's for the retail sector. So what that means is that 82% of time you need power here because you're running 24/7. So I think in that equation I think there's a way to [indiscernible] more behind the fence and I think that's a pretty acceptable solution because it's such a high efficiency. What you're really potentially trying to do is think about your next to mine cycle plant. So we have seven as in 800 megawatts cycle plant going, ready to go for 2020. But we truly have to know what the current policy is going to be before we build that. So if the province is trying to go from coal to renewable and storage you really, that cost structure comes really into play in that 2025 to 2030 area, probably not quite there by 2020. So you would stick with the current coal transition if that's what you wanted to do. If you wanted incent a bunch of combined cycle plant, because of the high system load factor you probably you transition earlier, so those are the kinds of tradeoffs.

The next question is from Carrie Tait from The Globe and Mail. Please go ahead.

Hi, thanks for taking my call. I'm just trying to understand a little more about the utilities investigation, I'm wondering if you can explain a little clear on why TransAlta disagrees, believes that taking the power plants offline was forced rather than a discretionary decision.

It's John Kousinioris responding to the question. We, in connection with the investigations occurred and I think as you can see if you followed the hearing from the evidence, there is a, there's quite a bit of a unique structure that exists within the marketplace in Alberta when it comes to outages. So from a TransAlta perspective we spent some time consulting with the NFA the markets around administrative reforms embarking on the strategy that we did. And really what it came down to for us was important [indiscernible], making a decision in circumstances where the plant needed to come down. We've had issues with those plants that required us to come down and in making those decisions we based on our understanding of the situation and in light of what we saw others doing in the marketplace. We factored in financial impact to the company in making those decisions. That's really the essence of the case, from our perspective, hopefully that will shift a little bit of line. But in all of the circumstances that we had and all of the four instances that were the subject of the hearing we actually had units that had a mechanical issue that resulted in them having to go down and the only issue was some element of discretion as to when exactly we would be able to take them down. In other words did they need to go down immediately or could you wait to have them go down let's say four days later.

But I think the essence of the dispute is, was TransAlta, did TransAlta have a different obligation because of the power purchase arrangements that were put in place as transition arrangements for deregulation because currently in the market participants have the ability to make those decisions and they insist that we have a extra set of special obligations because of the PPA and so, and we said that we didn't, so that's where. I think that's at the heart of the dispute and you know ADCs ruled that they were correct and we were wrong.

So to make sure I understand correctly, you spoke about the mechanical issues, did they have to go down precisely at the time that you took them down.

As I said earlier the units had to go down and we did have discretion as to whether or not they would, you know what would make sense for them to go down. So in other words there was a mechanical issue that needed to be addressed and needed to be addressed within a relatively short time period, so it would be within the matter of a few days in terms of when you would need to take them down.

And then, so then that basically boils down to the financial consideration. And your understanding that the rules that you could take it down when you did because of finance and the regulators as well know you could?

That is correct and it’s not just finance I mean we look at if the situation getting worse, is there increasing safety issue at the plant as you can imagine, there is a lot of heat, there is a lot of personnel that we have around the equipments that’s being used so we’re continually monitor the status of -- the mechanical status of the unit that isn’t performing very well and end up taking the decision. So if there is a safety concern particularly a safety concern as it relates to our employees there, that can’t stop it.

And was that then the final decision, or was there way -- was it possible that you could have taken them offline without having the prices change and the way that the regulators have said about?

I think from a regulators perspective yes I think it’s important to recognize those that whenever you take a unit down because there is a mechanical issue, it’s like there is some price impact. I mean our units do go down.

But from your perspective could you have done it in other time, or was it an immediate concerning you had to do it when you did some mechanical and safety reasons?

As I said, we have this question on when we could take the time, so yes.

Next question is from Ian Bickis from The Canadian Press. Please go ahead.

I was just curious if you could give more details on the review process that you announced kind of who is doing review, when it will be done and/or specifically what are we looking it?

We haven’t actually appointed anybody yet to do the review but we’re thinking about doing a review in respect of two elements and it’s on as know it earlier and publicly we’ll make the results of those reviews actually public. The two things that we would be and let me stress that the reviews would also be independent in our case it’s not that they would be done internally by TransAlta personnel. So we’ll be looking to appropriate experts to help us make those reviews. But the two areas of reviews would be; one, we want to make sure that our current practices around taking forced outages, our state of the art and our best practice from an Alberta perspective so that’s the one area that we’re going to review. In other words given the decision that came up in the Alberta Utilities Commission and given the law as we understand it, what is the best way and the most compliant way to ensure that our decision making around when those outages -- when they need to be taken down or done appropriately. And the other review that we haven’t actually highlighted as much publicly yet is that we will be doing a review just our trading compliance program generally compared to where that program was sort of three or four, or five years ago, it’s developed quite significantly. We put a lot of resources and increased the personnel and monitoring that we do in terms of all of the trading that we do in all of the trading jurisdictions in which we’re active. And we’re going to redouble our efforts in bringing the third party to assess that program as well. And again that’s something that we would happy to share publicly.

And again any idea when these reviews might be finished?

I don’t want to say when they will be done I mean the decision came out on Monday we’re digesting the decision. But we’ve already had consultants that have reached out to say that they’re available to help us and we’ve already had discussions internally about we would consider retaining to actually do the review. So it’s not like it’s something we’re going to drag out.

It’s not something that I think would be done in the next quarter, but it’s also not something that’s going to take us a year, I’ll take it probably in that six months time frame.

I will be I expect it will be -- by the end of the year we’ll have it done.

And Dawn you mentioned after the allegations coming out back in 2011 that you change too much practices at the time. Can you give a bit more details on what practices were actually changed after the [indiscernible]?

I mean the dispute was whether or not we reach -- without PPA products whether or not we could follow the way that the rest of the market had discussion around their outages. When there is some question about that we changed it to -- we don’t do that anymore. So that would change in 2011. And really when John talked about the review that we’re going to undertake it’s going to look at the changes that we did made in 2011 and test then against the new decision that came out Monday.

[Operator Instructions] Our next question is from Dan Healing from Calgary Herald. Please go ahead.

I was just wondering you have 30 days to decide whether to seek leaves to appeal. I was wondering if you could talk about some of the factors that you’ll look at before you make that decision. What are some of the things, the elements that you need to see before you decide to appeal?

So, as I said earlier the decision came out on Monday so it’s a lengthy decision as Dawn mentioned, it’s over 200 pages long and it’s filled with a lot of detail legal issue. So I don’t want to speculate that because we’re just in the process of trying to digest it and understand all of the ramifications of the decision. But what I can say is that in thinking about proceeding with an appeal, one of the things that really drives us is trying to make sure that there is clarity in the decision and in the ruling. And so, that the rules at least from our perspective as a company are clear and understandable. So to the extent that we feel that the decision is unclear or creates an element of uncertainty from a patches perspective on a go forward basis, that will factor significantly in making an assessment because we think it's important that there's clarity for us for our peers and competitors and in the marketplace generally from a governmental perspective, from a consumer perspective, from a stakeholder perspective. So that’s one of things that we're looking at.

Okay. And just a follow up. Is the company making any financial provision or do you anticipate making a financial provision because of the decision?

We haven’t made like any provision yet, probably like as far as the process of reviewing the decision and our decision is whether to appeal or not to appeal will be for that process and we will decide in Q3.

Okay. Thanks.

There are no more questions at this time. I will now hand the call back over to Brent Ward for closing comments.

Well thank you everyone for joining us today. And we're available after the call for any follow up questions, so please feel free to do so. Thank you.