Ladies and gentlemen, thank you for standing by. Welcome to the Methanex Corporation second quarter results conference call. As a reminder, this call is being recorded on Thursday, July 26, 2012. I would like to turn the meeting over to Mr. Jason Chesko, Director of Investor Relations. Please go ahead, Mr. Chesko.

Good morning, ladies and gentlemen. I would like to remind our listeners that our comments and answers to your questions today may contain forward-looking information. This information by its nature is subject to risks and uncertainties that may cause the stated outcome to differ materially from the actual outcome. Certain material factors or assumptions were applied in drawing the conclusions or making the forecast or projections which are included in the forward-looking information. Please refer to our latest ND&A and to our 2011 annual report for more information. For clarification any references to EBITDA, cash flow or income made in today's remarks reflect our 60% economic interest in the Egypt project. In addition we report our adjusted EBITDA and adjusted net income to exclude the mark-to-market impact on share-based compensation and expenses and charges related to the Louisiana project. We report our results in this way to make a better measure of underlying operating performance. We expect this will make our analysis of our results more straightforward and for consistency we encourage analysts covering the company to report the results in this manner. I'd now like to turn the call over to Methanex' President and CEO, Mr. Bruce Aitken, for his comments.

Good. Thank you Jason, and good morning, everyone, and welcome to our second quarter investor conference call. I have got a number of colleagues with me here in the room, and they will be available to answer questions a little later on. I will first give some comments on our second quarter results. We reported adjusted EBITDA of $113 million which is a 22% improvement over the last quarter. Adjusted net income was $44 million or $0.44 per share. The average realized price in Q2 was similar to Q1. However, we achieved higher production in produced methanol sales and lower logistics cost and these factors drove the higher EBITDA. With the recent start up of our second plant in New Zealand, we now have annual operating capacity of over 5 million tonnes and our cash generation capability has improved. I will be commenting more on the expectations for the third quarter and the industry impressing outlook a little later in the call, but before I do that I will make some comments regarding our operations for the quarter. In Trinidad, our plants operated at 90% capacity and produced about 460,000 tons of methanol. As I've mentioned on previous occasions, we and other downstream users in Trinidad have continued to experience some gas curtailments as a result of supply disruptions from upstream gas producers. We are engaged with key stakeholders to find a solution to this issue, however at least during the next quarter we expect to continue to see some shortfalls in gas supply as we understand there are more outages planned by upstream producers. In New Zealand, the Motunui plant operated at full operating rate and produced 210,000 tons in the second quarter. The restart of the second plant in Motunui plant was completed on schedule at the beginning…

(Operator Instructions) And the first question is from Jacob Bout from CIBC. Please go ahead.

I had a few questions on Geismar. So just to clarify your comments on the payback, so you are saying right now that you think the payback is going to be in 2017, 2018 or 2016 and then what is the methanol and gas price assumptions behind that?

So the assumptions we gave you is that its about current price around [$300 million] per ton and then if you look at the forward curve in natural gas it’s around $4 to $4.50, when we put those numbers into our model we generate about $200 million of EBITDA and that generates a payback of less than four years. So we are starting up at the end of 2014 then the payback will be by 2018.

And then this 550 million to move the plant, what is included because the engineering and all that included in that or?

So it is all of the deconstruction, the removal of the plant, the engineering, the reconstruction also includes all of our owners' costs. So all of the insurance and the other sort of ancillary cost that and it typically experiences and all of that pre-startup cost and most of them is about $50 million of pre-startup cost which are in two brackets, one of them is to recruit an organization which we are actually starting to do right now. So we will have employees on board, well in advance of the plant being operational and we need to do that, so they are well trained and ready to operate the plants. And the second bracket is just a commissioning cost that sort of gas you consume during early stage of commissioning, which is often offset by revenues. We take no account of that. So this is all of the cash that we will spend and moving this plant from A to B and getting it operational between now and into 2014.

So, all are uneven equivalent in the permanent cost?

Exactly

And then the last question here just on Chile, just you know it sounds like the gas exploration continues to be not where you were hoping it to be, how much you've invested to-date and how much you are willing to invest going forward? And at what point do you look at this and say may be we should look at moving all these plants?

Well we have invested today about $150 million and it's like, where I look at the economics of all of those investment decisions and they are in different parts of the exploration area. Every one of those investments have paid back remarkably quickly. So when we count the amount of margin that we make on methanol we produce at that site, these are being strong investments that have provided a decent return for our shareholders. So that’s why we are inclined to continue making those investments. Looking at what's disappointing in Chile, we haven't seen others spending at the levels that we anticipated. Companies like Apache have a couple of blocks down in Southern Chile and they elected to surrender those blocks after spending a small amount of money and I think that the reality is the oil and gas industry that the industry attracts money towards oil rather than gas and those big companies have opportunities in other parts of the world to look more attractive than what they were looking at in Southern Chile. There are a number of smaller companies working away in Chile that have got an interesting business model and continue to make good money and continue to spend quite a lot in drilling and exploration. So there is a lot of activity continuing to happen and I think one of them makes me more confident is we are seeing it across a broader array of exploration blocks. This just in the next couple of months there is a well being drilled in the area called Isla Riesco. That is a conventional gas reservoir that could be quite game changing. I have probably said that a few times that there is a number of potentially game changing opportunities down in Southern Chile and if one of them comes in our outlook would change tomorrow. Really, we think and when we sit back and think about Chile, if we could run two plants there in capacity maybe into long-term we would be very, very happy. That would be a very nice outcome first that mentions the mark and need quite nicely. So it certainly seems to me that we have one another redundant plant down in Southern Chile that we could relocate. And as I mentioned in the prepared comments, we will make a decision on that probably towards the end of this year, at the beginning of next year, whether it’s to Geismar or somewhere else we haven’t made that decision yet here and I think we certainly have another opportunity to relocate one more plant.

Thank you. The next question is from Ben Isaacson from Scotiabank. Please go ahead.

First question is on the potential relocation of the second plant. You said that there would be some synergies there or cost savings. Can you describe kind of what the magnitude or where those synergies would come from, would there be anything other than infrastructure at Geismar already in place?

That’s probably the biggest answer then. Clearly, we’ve done a lot of site preparation. This project has something kind of Greenfield project and that we’re starting with truly a Greenfield, that’s what it is today. So we’re doing a lot of site preparation and we build a lot buildings, admin building, storage facilities and warehouses those sort of things you never need to repeat the second time. So a lot of those ancillary pieces on the plant are very incremental and you don’t need to start from scratch. So we don’t really have an idea for what the number is, but I think it will certainly in the tens of millions and maybe $100 million.

That’s very helpful.

Also not claiming to demobilize at Chile, so its just works the way we currently think about it as we will continue from one deconstruction to the second without demobilization, remobilization. So there is cost savings there as well. So yeah I think the numbers are significant.

Okay, and when you’re thinking about the second plant, how do you think about the natural gas price risk. Would you want a long-term contract on at least one of the two plants or would you be willing to take a spot for both parts?

That is pretty much how we think about it. I think if you had one plant on short term arrangement that would be okay, but I think having a couple of million tons on the monthly gas projects feels bit too risky to me. So it certainly encourages and if we could on long-term gas contracts, then I would say and then we’re talking to probably five or six different companies. We had some offers on the table that look very interesting. So today I have a high degree of confidence that we will sign a long-term contract, but as I mentioned again in my prepared remarks, if we don’t, it doesn’t really bother me too much I think we certainly as far as this investment is concern, we’re confident that we can get our capital back and make decent returns based on financial hedges.

Okay and just last question. You talked about demand weakness on the derivative side. Are you seeing any demand weakness on the energy side for methanol demand?

Just a strong demand, Ian can you comment on that please?

Yeah, the energy side continues to be quite strong, we did see some decline in DME when we saw oil really decline quite quickly and therefore the relative propane cost also went down. But that return now as oil is backup so still see strong energy applications for methanol.

Thanks. Bruce in your press release you talk about a significant debottlenecking opportunity in the Motunui site; can you give us a sense just in terms of the timing and the cost to do that and whether that’s contemplated in the $150 million of capital expenditures that you have got to the end of 2013?

Yes it is, there is a number of stages that we need to go through with that plant in New Zealand. The first Motunui plant is operating today there is a plant maintenance outage that we need to conduct in sometime towards the end of next year and that we are getting to a point where statutory approvals begin to expire, so we need to take the plant down and do inspections and then some replacement equipment that we need to have in place for that as well. So that’s point number one. Point number two is the Motunui site was neighbor of -- for those of you that have been around a long time will remember the history that was a methanol to gasoline site and the Motunui methanol plant on there was designed to produce crude methanol which into that and converted into gasoline. So those plants were never really designed to officially produce and distill chemical grade methanol, so we have added distillation capacity. We did it in a way that was probably a little bit suboptimal and that was back in the mid 1990s so it was a long time ago. And as the years have gone by, we have recognized that there are always opportunities to improve the energy efficiency on that site. It requires probably $50 million or $60 million of cash at Motunui and we have been reluctant to do that until we had more longer term certainty. So here we have a great opportunity now where we have long life in front of us to do a very sensible investment that improves energy efficiency on that side. And again it’s another one of these projects that has one to two year payback and a very attractive term with returns on investments. And then on the third aspect that we are thinking around the New Zealand is the Waitara Valley plant which is 500,000 ton plant; it’s few kilometers down the road. It was last operated and my guess is three years ago and so it is a little bit of work done that, not too much. We do need more gas before we start that up, so there is more work to be done and contracting further gas. When we got those three projects together debottleneck it appear Motunui 2 and the Waitara Valley it represented a total of about a $150 million of capital that we need to spend and that potentially gives us up to 2.4 million tons of production from 1.5 million tons. So if you look at it incrementally, we are getting another 900,000 tons for a $150 million of capital. Again compared to relocation or bringing fuel to any other sort of methanol investments this is a very attractive opportunity.

Okay. And then just on your comments around lower sales for Egypt and Chile; you’ve got a turnaround and outage you said a major outage in Chile in August….

That’s maintenance that needs to be completed whether we do it in August or not we haven’t finally decided, but it’s certainly there. The current plan and if it’s not in August then we’ll probably do it before the end of the year or early next year. So there's certainly some time in there. But we are going to need to have an outage.

So am I to interpret your comments that Q3 will run lower in terms of production from Chile than Q2?

Probably.

Okay. And then just then on Egypt, this will be the last question. There was some warranty stuff I recall was supposed to be done in Q3, but sounds like a little bit was done in Q2. And then there seems to be some other moving parts in your commentary again was lower sales out of Egypt. So is the Q2 the right way to think about that as a run rate for the next couple of quarters for Egypt production?

It probably is, I did mention last time that the plant has been operational now for about a year and a half and there is a period at which warranties and some of the new equipment runs out. So desirable to shut the plant down, do some inspections and make sure that we can make any claims that are necessary into those warranties. So we have done that. We shut the plant down in late April, sorry, late June and restarted it in mid July and as I mentioned earlier, it's been operating, it's operating at about 70% rates today.

And what is the, just to address the portion of your comments that talk about gas curtailment, is that situation abating or likely to persist?

Well, it’s a complicated situation. We are in the middle of Ramadan and in the middle of summer. So and I think in Egypt we are clearly in a very uncertain political environment, so that's not a surprise or news to anyone. What has transpired is that there have been a number of changes in some of the key ministries that hasn't really helped decision making in the last year and a half and what's that leading to is a breakdown in some of the infrastructure. There have been electricity burnouts in Cairo over the last three of four months. And you can see that breakdown is occurring in that country in lots of different areas. And part of this is in the natural gas distribution system unfortunately. I guess our take on it, there is no shortage of natural gas to my country, yet. I think the reserve to production ratio is about 36 years. So this is not an issue as the natural gas is available. The issue is all around maintenance and of infrastructure. So we are assured that it's been worked on and will be resolved, but we still continue to operate in a very uncertain political environment and if you look at what's the recourse, I think that's the recourse of the challenges we are having.

The next question is from Hassan Ahmed from Alembic Global.

You know again just wanted to revisit this relocate versus build decision. I was trying to get a sense of where you think greenfield replacement value is currently because I mean from the sounds I have heard, you are guiding to around $550 million as the expense associated with the relocation which obviously means $550 a tonne. My guess was that greenfield replacement value was maybe $600 to $650. I mean I guess what I am trying to sort of understand is that, would the real juice of the savings be generated from indeed a second plant move?

No, so I think you are understating replacement costs today, Hassan. What we are learning out of this process is that costs are more expensive than we anticipated. So some of the labor costs we are finding and some of the equipment costs are still somewhat higher than we were anticipating. We can’t really ever answer your question until we do a greenfield project ourselves. I reflect back on Egypt. We spent between $700 and $800 per tonne in Egypt. There was plant in Oman that was built, that was quoted as a million tonne plant for $900 million, so that is $900 per ton. That project was built pretty much at the peak of construction costs and we saw the cost at probably off a little from that point. But I think our learnings over the six months that costs have tended to be quite a bit higher.

I think that’s right when you say this. Correct, Bruce. What we obviously are seeing is that the engineering contractors are filling up. So one of the advantages we think of the relocation right now is somewhere ahead of the wave in terms of new construction in the United States on the back of (inaudible) gas. So we think that --

I think that makes kind of sense, yeah.

That’s a good environment for us to be going into. The other observation I'd make is that many of the reported numbers that we see for other projects, really only relate to the EPC costs and don’t include the [earnings] cost and we transpire and we show all of those costs. And so it’s pretty difficult sometimes to really get a benchmark of what others are seeing in the market place because they don’t include the substantial [earnings] cost and total capital.

And Bruce, is it fair to assume that you briefly mentioned you know, maybe for a greenfield facility five years, start to finish is being sort of a rough guide. Again, how much of that is decommissioning side of it because as I understand it, that’s taking a while as well. And then you know, my guess would be as we start marching towards call it the middle of the decade or so, you know, you have a flurry of other sort of activity, greenfield plant wise happening in the US or may be a new facility has got delayed even more?

Well I think as a rule of thumb is that we think 36 months to construct and commission a methanol plant as a reasonable outlook for schedule. And then so the other two years comes from engineering, permitting, land acquisition. There are lot of other things that have to be done in that two-year period. You know in some locations you can probably do it quicker than that. But all of those things take a lot of time. We were certain – we tend to spend a lot of time in engineering. Michael again it’s very much a very cautious approach to being sure that we specify the project very accurately. So that we know exactly what we are going to get, which is why we have a very good record of delivering projects on time and on budget. And I think that’s because we spend a fair bit of time upfront making sure that we know, we scope the project very, very well. And then Michael, any other comment.

Yeah (inaudible) I'll just add to that, that with the relocation that most all of the long laid items that are normally associated with the projects, heavy oil reactors, compressor those sorts of things. Those are all the equipment items that are being relocated in this project. And so the project doesn’t incur those risks and so we don’t have the shop risks and delivery risks and so forth. So I think again that goes to Bruce's comment around sort of the robustness of the faster schedule for this particular project.

Got it. And one final one Bruce if I may, just changing gears a bit. Your comment about some weakness in certain derivatives, I mean as I understand it you had a fairly large [Seatech] facility in Singapore which was down through the course of Q2 and another one that recently, that was clearly planned, now you have had another unplanned outage in Taiwan, a [Seatech] again. I am just trying to get a sense of how much of this derivative weakness is kind of call it a blip because of some of these outages versus you know real issues in those end markets?

Well I think one of the issues as it sounds has been a lot of capacity overboard in Asia. So the operators in that industry are needing to look around it how can they make those businesses make sense. I think the fundamental drivers underneath the (inaudible) derivates are actually haven’t been to bad. John do you have any comment?

Just we have seen in the last few months slow down in China that's been widely reported. So we are not seeing the growth in China that we would have expected, still year-over-year some growth but not based on what our forecast would have been earlier this year. What happens in China in the second half there is two camps, one says that it is going to come back based on stimulus etcetera and on the other one says it's going to continue at the current rate. So we are watching it very closely. And I would say throughout the team of Methanol and probably other chemicals as well people are being very cautious, so inventories are really low whether it is our own inventories or inventories we are seeing in China or at other customer level people are being very, very cautious. So if we did some uptick in China as some are predicting, you know we are expecting to see quite healthy pulls on inventories throughout the team. So we are watching it very closely.

Very helpful

I think there is coastal (inaudible) and the end of 13 or 14 days. It's almost unsustainable but that’s the environment we are in.

The next question is from Steve Hansen from Raymond James. Please go ahead.

Mr. John should we provide a bit more color on what you are seeing or hearing about our production plans over the next several months and why do we sanction and probably it has been little bit handicapped to fleet but just trying to get your sense for the next sort of three to six months and their ability to skirt some of the sanction in place?

It's hard to predict Steve but I would say when the sanctions came in place there was immediately reaction. I would say over the last few months there is more radiant product coming out of Iran than we could have anticipated three months ago. We still understand one of the large plants is down, the other three are running at some level less than full capacity. We are seeing quite a bit of product, more product than we would expect to come out, a lot of it is going to India, some of its being transloaded in Gulf of Oman by ship to ship to skirt the sanctions in place on the P&I and we are also seeing some of the Indian product re-exported to China. So I think the Iranians are finding ways to get the product out of Iran. Is it going to more or less in the next six months, it’s a bit of a guess Steve, but I would say unless there are further sanctions or further things that happen to tighten up what's currently happening I would expect similar levels of what we see today for the next six months but that's a bit of a guess.

I have just seen in the last few days that imports into China in June were 261,000 tonnes and they are typically 400,000 to 500,000 tonnes so that's a complete reflection of a good turn of normal activity from Iran. As John said some of it's getting out and its improving but there are production disruptions that are occurring at reduced supply.

And then Bruce I just wanted to follow-up on the potential for long-term gas contract in Louisiana, how should we think about the economics of the contract. You've got some potential offers on the table now, presumably they have all sorts of different terms but you've historically favored this sliding price mechanism at a little base price, I mean are we just, can you give us some sort of benchmark or goal post to think about how a contract will work if it was redesigned in the next month or so, I am not say it will be but just to give us some goal post and how we think about, would the economics be better than the long-term strip today, whether it would be worst whatever you can provide as usual?.

That depends on your outlook on methanol prices and oil prices frankly. So I think our sales to gas suppliers is that methanol dries up and now with crude oil. So if you like your gas price to be more like that of crude pricing than tying it to the price of methanol is a smart thing to do. So on the one hand, we could go and do financial hedges today and that’s our full grade position. So if you want to model it, what we think of that is can we achieve the sort of prices over a 10-year period that we could achieve on the financial markets today over a four, five year period. And the advantage of a contract is, you don’t need to worry about liquidity and into some other contractual advantages you get of having an association with a substantial counter party. So I don’t Ian any other kind of commentary on it?

No, I think you described it well, Bruce.

And then just last one if may on the gas situation in New Zealand, you suggested adding additional capacity there and getting ramped up to the 2.4 overtime but I’m just trying to get a sense for the last contract you signed, gave you a bit of future clarity on supply. You know, would the same type of contract be available today on the gas situation, does it take more time, is it a price issue you are waiting for, I am trying to get a sense what the push backs it would be as whole backs on getting new contract overtime?

Well the market is complicated down there. It’s very different than North America. It’s a contract market and they tend to be two or three large players and a handful of smaller players. So life has gone lot more complicated first by needing to have multiple gas contracts with multiple suppliers and need to have them all integrated with each other. So there are similar sizes in term contracts that we’re discussing with a number of different counter parties. So I would rather not take too much more of them on. We need to get those finalize before we are able to push the button on some of those projects we’ve talked about. But I would say, I have a high degree of confidence what seems to me that we’re completely in line with the natural gas industry and these are surplus gas available and we are the sensible market for that natural gas.

Well the market is complicated down there. It’s very different than North America. It’s a contract market and they tend to be two or three large players and a handful of smaller players. So life has gone lot more complicated first by needing to have multiple gas contracts with multiple suppliers and need to have them all integrated with each other. So there are similar sizes in term contracts that we’re discussing with a number of different counter parties. So I would rather not take too much more of them on. We need to get those finalize before we are able to push the button on some of those projects we’ve talked about. But I would say, I have a high degree of confidence what seems to me that we’re completely in line with the natural gas industry and these are surplus gas available and we are the sensible market for that natural gas.

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

Just on the Gulf Coast relocation side, our analysis is just the plan is quite profitable at higher gas prices but I am just wondering at what point if gas prices do continue a bit of a move out. Do you start to feel like comfortable about committing capital?

That has to be a lot higher than that today. It is about 35 units of gas to make a ton of methanol. So even at $8 natural gas, your gas cost is around $280 a ton. So at that point, most of you imagined this is not a very attractive investment anymore. You probably are still making positive cash flow. So I don’t see too many people forecasting it on the natural gas in the next five years or 10 years in North America but who knows. So I do think there is a pretty nice cushion that allows us lots of flexibility and to return capital make it a piece of return.

Okay. Just on that because of the way the curve is shaped do you feel the need to hedge out for that longer term just given you have that margin safety?

I am not believer in the long end of the curve. It’s a very thin liquid market out there, so the liquidity in that market tends to be I guess four to five years Ian?

Yeah, that’s right.

I think from a practical point of view Robert I think if you were going to use the financial markets to secure the gas price you are probably below four years or so and as Bruce mentioned in his prepared remarks that cover our payback period at the price in the curve. So I think that would be the practical way of thinking about it.

Makes sense and just a last question somewhat related I know in the past you have mentioned that you didn’t have a lot of interest in actually directly getting into reserves. I was just wondering if that’s changed with respect to potential joint venture or the gas producer where you can kind of lock in the costs long-term and control the production a little bit at least?

We would rather do it contractually. I think that keep the parties aligned much better. We are not an upstream company despite the fact we have spend a bit of money in upstream and in some geographies at the end. We are at the end, we are a methanol company and that’s what we good at. And companies that are good at drilling for oil and gas that’s what they good at. So I think its better we would prefer to have contractual relationships where we sign contracts that where the benefits are shared and that’s been a track record in most countries around the world and I think there is some proven success with that.

Okay. So that structured pretty much off the table than from North America.

I wouldn’t say it’s completely off the table. I would say strong preference to have contractual relationships rather than trying to be an expert in someone else’s business.

The next question is from Paul D'Amico from TD Securities. Please go ahead.

Hi Bruce, most of the questions actually been asked and answered, let me just try and clarify here so; in the long term North America gas contracts that you’re looking at, you’re seeing; you’ve got something interesting or something that is interesting there. Just to be clear so, do you have some that are structured similar to the current arrangements with revenue share component?

That’s right exactly; for the most that’s what we’re talking about; its base price plus some element of the gas price that moves with the methanol prices.

Okay, and are the thresholds similar to what we are used to already on the current arrangements?

No, not really I think if you look at what was gas supply was, we need to get something better than the forecast and it already has been what’s the forecast around oil prices and if they have an aggressive forecast on oil prices, so generally our country will deliver a lot more than the forecast; if the future is for low oil prices then we’re taking some risk around that, but those are the conversations that we have.

Okay and then in terms you were talking about, in terms of durations are five to 10 years would be fair to start?

Yeah, it continues, it is what we are looking for.

Okay and in terms of the amount, are we talking inclusive of Medicine Hat or is that something separate?

It’s separate but we think about that as well and I would mentioned that we have debottleneck opportunity in Medicine Hat so we are getting a little bit larger there as well. So to the extent that we could do some sort of a longer term contract at Medicine Hat we are over mandate there and clearly today gas prices are in $2.50 in Alberta this is appropriate to be heads staying short on gas and that problems.

Okay and if I can get a gas hedge update on the Medicine Hat; last update you were basically still through 2013 at about $4 on average this is at we’re we at or are we further now?

It’s hard to tell because we’re not -- we're only partially hedged and we tend to hedge more during the winter time because we are a bit afraid of price spike from the winter time. We have got a little bit of hedging going on into 2014 but quite small. That's probably a little bit less than that as we mentioned.

Okay, and in terms of the maintenance CapEx, after the plant moves what could we see in maintenance CapEx increase?

We've typically quoted before that $50 million a year. That was I guess that was only one-time in New Zealand and Chile and Trinidad and Egypt so we've got another location in Medicine Hat as well, so you know that number is going up and we have got a bit of a lump of maintenance coming up in the next one to two years. I mentioned the plant down in New Zealand, we are replacing tubes; that's a plant that's 25 to 26 years of age; so it’s getting to that time when we need to do some big pieces of maintenance. So that's included in our budgets for 2013. Same thing in Medicine Hat; Medicine Hat 1980s we built this plant and we will be replacing some tubes there during an outage probably in the next one to two years. So I think the number has gone up a little and we've got more plants and there is a couple of biggies coming up. But I think in general long-term and I would think in a $50 million to $60 million is still a reasonable number to assume for.

Okay, just to clarify that a bit Bruce, when you move that plant and its utilized in a full rate compared to being now under utilized the maintenance CapEx doesn't materially increase?

Not really. You know we do a major turnaround every three to four years and that's typically $20 million to $30 million of expenses and when you replace some of the major piece of equipment that I just talked about you can double that fairly quickly, so no, the fact that you utilize it more doesn't increase maintenance.

And last question, you are mentioning in terms of the potential for second plant being moved and a decision being made maybe before the end of this year. I am just curious if you can remind me whether you move one plant or two plants that would have assumed the same decision making process. So why I mean, what is it, what sort of issues are being confronted aside from the end location and then you are permitting or what not; aside from that what's holding you back with respect to saying you are moving in the second plant or finding where?

We don't need to make the decision today. That's probably the primary thing Paul; the most efficient time to make that decision is before we can mobilize (inaudible) and Chile. So we could do a seamless relocation of two plants that would be a good thing to do. So we need to make that decision probably in the next six to eight months would be the optimum time to make the decision. In the meantime, we are going to learn more about relocation, we are going to learn more about gas available as we've done in Southern Chile. I did talk about game changers down there, so we shouldn't dismiss the fact that maybe something happens in the next six to 12 months that causes us to think differently about Chile. We continue to have discussions with Argentina. I am not going to hold my breath on getting gas from Argentina, but there is a lot of gas just across the border that we used to get gas supplied from the large fields in Southern Argentina and there is some discussion going on there. As I said I am looking to hold my breath and I have worked on and I have a promise on it, but there are things that could happen that could change the outlook. So why make the decision before you have to and that's our primary thinking.

Okay, are you saying there will be a likely decision in the next six months or maybe post of that?

No, I think in the next six months as far as what you would expect, six to eight months.

Thank you. The next question is from Charles Neivert from Dahlman Rose. Please go ahead.

A couple of quick questions. One, the CapEx on the move of the plant from Chile, how is that looking like it will spread out over the next 24 odd months to 30 months? And the second question is the China plants, the MTO/MTB plants in China particularly ones that are purchasing both the one that’s running and the one that looks like it will be running shortly. How much of that is likely to be purchased from internal sources versus imported product?

Okay, so on your first question Charles, the timing roughly is about 15% this year, 50% in 2013 and 35% in 2014. So that’s our estimate of how that capital will be spread; I’ll ask [John] to comment on.

The current one that’s running that’s buying merchant methanol is 100% supplied by China. The [Skyford] one I think you are referring to, their plan is to have 60% internal from China and 40% based on imported methanol. They’re building 200,000 tons of storage on the coast to be able to import methanol.

And that particular one is the one you’re anticipating with needs of about 2 million in tons total; is that the one – I got that right, or is that the one that’s running right now?

No, that’s right. It’s the one that’s under construction and that's being built as they do in stages. So I wouldn’t think all of it would start up at the end of the year. You will probably see it staged in and go for months.

Thank you. There are no further questions registered at this time. I would like to turn the meeting over to Mr. Aitken.

Okay, we are right on the hour or so it’s about to (inaudible) in the air. So thanks everyone for participating in the call with your questions. This continues to be a really exciting time for Methanex. We have just started our second plant in New Zealand and really pleased to have that site coming back into production. We expect to have some more good news in the coming months with our final decision to run the Louisiana project another nice hurdle to get over and I have got great confidence in the ability of our team to deliver a first class project in that location. And we are still in this industry, outlook where that looks extremely positive for us where demand is growing and underpinned by the energy applications and supply that is quite constrained. So lot’s of positive for the medium to long-term. We will continue to have some short-term blips and I think we have explained some of those this morning, but I think I continue to be extremely optimistic about the medium to long-term prospect for the company. So thank you for your continuing support and good morning to everyone.

Thank you, Mr. Aitken. The conference has now ended. Please disconnect your lines at this time and thank you for your participation.