Methanex Corp (MEOH) 2012 Q2 法說會逐字稿

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 forecasts or projections, which are included in the forward-looking information. Please refer to our latest MD&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 it 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 their results in this manner. I would now like to turn the call over to Methanex Corp's President and CEO, Mr. Bruce Aitken, for his comments.

Thank you, Jason, and good morning, everyone, and welcome to our second quarter investor conference call. I've got a number of colleagues with me here in the room and they will be available to answer questions a little later on.

I'll 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 $0.47 per share.

The average realized price in Q2 was similar to Q1, however we received -- we achieved higher production and produced methanol sales and lower logistics costs. And these factors drove the higher EBITDA. With the recent start-up of a second plant in New Zealand, we now have annual operating capacity of over 5 million tonnes and our cash generation capability has improved.

I'll be commenting more on the expectations for the third quarter and the industry and pricing outlook a little later in the call. But before I do that I'll make some comments regarding our operations for the quarter. In Trinidad, our plants operated at 90% capacity and produced about 460,000 tonnes 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 were 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 rates and produced 210,000 tonnes in the second quarter. The restart of the second plant in Motunui was completed on schedule at the beginning of July. I'll comment more on the restart and the further initiatives to increase production in New Zealand, again, later in the call.

In Chile we operated one plant at low operating rates and produced 82,000 tonnes. We have received reduced volumes of natural gas over the past quarter, as we were in the southern hemisphere winter and residential gas demand in that area is at its peak.

We are planning a maintenance outage in August and expect to receive larger quantities of gas after this turnaround is complete. I'll comment on the outlook for Chile in just a few moments, also. In Egypt the plant operated at 86% during the quarter and produced 164,000 tonnes based on our 60% interest.

The plant was shut down late in the second quarter to complete planned maintenance and inspection activities. In addition, we experienced some natural gas curtailments as a result of outages at upstream platforms and strong seasonal domestic demands in natural gas for our electricity generation.

The plant is currently operating at about 70% and we expect to be back consistently operating at full rates in the coming months. Finally, our plant in Medicine Hat, Alberta operated at full capacity and produced 118,000 tonnes in Q2.

In the current pricing environment for natural gas in North America, Medicine Hat is a particularly valuable asset and we're working on a debottleneck of that plant that would see capacity increase by about 20%.

Turning now to industry conditions. Despite softness in some derivatives in the current economic environment, overall global methanol demand has remained good. And current indications are for relatively stable demand in the third quarter.

There have continued to be a significant number of planned and unplanned outages impacting methanol supply across the industry and around sanctions have continued to negatively impact the level of production in that country.

Balancing this, the Beaumont, Texas plant and our New Zealand plant started up earlier this month, adding 1.4 million tonnes of new capacity and we've recently seen moderating coal prices and higher methanol production in China.

These various factors have led to a modest increase in methanol prices over the last couple of months. In July, contract pricing was down by about $20 to $25 per ton and this morning we announced a roll in pricing in North America for August.

Pricing in July and August is back to the level that prevailed for the first quarter of 2012. So, overall pricing through this year has been quite stable. Methanol fuel blending in China has continued to grow at double-digit rates over the last few years and is currently about 6 million tons per annum or about 12% of global methanol demand.

As we continue to see new initiatives being put in place to support further growth, recently it was reported that the Hebei Province on the coast of China is planning to increase sales under its M15 blending program as M15 gasoline is expected to be introduced at a number of Sign Sinopec petrol stations in that province by the end of this year.

Methanol fuel blending outside China also continues to attract interest. Recently an M15 fuel blending trial program was initiated in Israel, with parties involved in the project citing attractive economics and environmental benefits as the key drivers for adopting methanol fuels.

Other countries that currently use methanol in fuel blending or are testing methanol blends include The Netherlands, UK, Iran, Trinidad, Iceland, South Korea, and Australia. Methanol to olefins, or MTO demand, has also experienced a strong growth in China.

There are three integrated and one merchant MTO plants operating and a large merchant plant, in Ningbo, on the coast of China is expected to start up at the end of this year. This project is expected to consume up to 2 million tonnes of merchant methanol and could have a notable impact on the market.

In addition, there are several other MTO projects currently under development in China, which are expected to come on line over the next few years. There was also increasing interest in using methanol in new energy applications.

While methanol fuels are often cited for their economic benefits, the environmental benefits of using methanol for fuel are less publicized. However, this is a key driver for a project we recently became involved in. We are working with some other parties on a pilot program in Europe to test the use of methanol and DME as a marine fuel for ships.

Northern Europe has put new standards in place, which come into effect in 2015 that regulate emissions and will lead to the introduction of cleaner burning marine fuels. While there are different fuel options being considered, the total market size being impacted by these regulations equates to equivalent of about 40 million tons of methanol.

So, even a small penetration into this new application could have significant impact on global methanol demand growth. Turning to the longer term supply and demand outlook, there is only a modest amount of new capacity expected to come on line over the next few years relative to demand growth expectations.

This implies that a strong pricing environment will be needed to entice high cost capacity in China and other locations to operate. This outlook matches well with our plans to increase production over the next few years.

So on this note I'll switch topics and provide you with an update on our key initiatives to increase production and capitalize on the favorable industry outlook. Firstly in New Zealand, our team did a first class job in restarting the second Motunui plant.

The plant started up on schedule at the beginning of this month and has been operating at a high rate over the last few weeks. The start of this plant increases the capacity of our Motunui site by 650,000 tonnes to 1.5 million tonnes.

Our success in increasing production in New Zealand is underpinned by the improved natural gas supply position that has developed in that country.

We are currently working with gas suppliers in New Zealand to secure more gas supply and we have initiatives that could increase capacity in New Zealand by a further 900,000 tonnes by the end of next year through debottlenecking the Motunui site and potentially restarting our Waitara Valley plant.

We expect to have more clarity on natural gas supply position to make a decision on these projects by the end of this year. Yesterday we announced that we've made the final investment decision to proceed with the relocation of a 1 million-ton plant from Chile to Geismar, Louisiana.

We completed a detailed engineering study for the project, which includes an estimate of capital costs for the relocation and construction of the plant, including all owners and pre-start up costs of approximately $550 million.

The study reaffirmed our initial view that the relocation would result in substantial cost savings compared to a similar greenfield plant and that it can be executed in much less time.

We've recently commenced dismantling work at the plant site in Chile, moving the plant is planned to commence in the first half of next year and the project remains on track to be producing methanol in Geismar by the end of 2014. We think that a similar greenfield methanol plant would take up to five years to design, construct and commission.

We are very excited to be moving forward with this project, which we believe will create significant value for our shareholders and improved reliability for our customers. The proliferation of shale gas in North America has resulted in a structurally low natural gas price environment, which underpins the very attractive economics of this project.

The US, and Geismar specifically, is an excellent location for a methanol project. It is in a jurisdiction which offers an excellent business environment to operate in, has world class infrastructure and skilled workers and is in a large methanol consuming region, which minimizes logistics costs both for us and our customers.

We continue to be in discussions with several natural gas suppliers to secure a long-term gas supply agreement for the project. However, if we are not successful in reaching an agreement, we are confident that the fundamentals of the North American gas market and our ability to hedge using financial instruments will support a timely pay back of capital and attractive project economics.

For example, based on the current forward curves of natural gas of about $4 through to 2016, the plant would generate about $200 million of EBITDA per year in the current methanol price environment and have a cash payback period of less than four years. And we have further potential to increase production from our Chile assets.

As I mentioned earlier, the short-term outlook for natural gas in Southern Chile continues to be quite challenging. However, longer term we continue to believe that there is the potential to increase -- increases in natural gas supply to underpin higher production.

Drilling activity has started in several new blocks in the area near our plant and we are working on initiatives to bring new technology and encourage broader participation to unlock some of the reserve potential in the region. We are also studying moving a second plant to North America.

Our site in Geismar, Louisiana large enough to accommodate multiple methanol plants and we believe that compared to the first relocation there would be significant cost savings in moving a second plant. Over the next year we will learn more about the gas outlook in Chile and the Louisiana project and this will help guide our future decisions.

I'll change topics now and make a few comments regarding liquidity and capital expenditure. During the second quarter we generated $110 million of cash flow from operations. We have conservative leverage, a $200 million undrawn operating facility and about $400 million of cash after taking into account the repayment of the $200 million bond coming due in August.

As mentioned, we recently made a final investment decision to proceed with the Louisiana project and the capital required for this project will be spread out over the next few years. And if we proceed with the various projects in New Zealand, we would spend about $100 million to execute these projects.

We also plan to continue committing capital to gas development in Southern Chile. With our strong financial position, we expect to be able to fund all of these initiatives, end up paying capital maintenance expenditures internally from our balance sheet and cash generation and to continue distributing excess cash to shareholders.

Before stopping for questions, I'll comment briefly on our expectations of the third quarter. As ever, there are lots of moving parts and assumptions that will evolve over the quarter, so it is difficult to provide precise guidance.

Firstly, the pricing environment has moderated a little and we're currently achieving or expecting to achieve a lower price realization in Q3 compared to Q2. We expect the restart of the second New Zealand plant to have a positive impact on produced methanol sales in Q3. However, we expect this will likely be offset by lower production and sales from Egypt and Chile.

Taking all these factors into account, we expect lower adjusted EBITDA and adjusted net income in Q3. There is one further adjustment that will impact Q3 net earnings. As we have worked through the accounting for the Louisiana project, there are certain costs that cannot be capitalized and there is some value from these in the Chile plant that needs to be written off.

These two items will result in a $60 million pretax charge to net income in Q3. This adjustment has no impact on economic value and merely reflects the accounting treatment we are obliged to follow. So at this point I'm happy to stop and I will take any questions that you might have.

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

I had a few questions on Geismar. Just to clarify your comments on the payback. So you're 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?

The assumptions we gave you is that the -- it's about the current price, around $380 per ton and then if we look at the forward curve for natural gas it is 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 if we're starting up at the end of 2014, then we will be -- the payback will be by 2018.

And then this -- the $550 million to move the plant, what is included? Is the engineering and all of that included in that?

Yes, 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 costs that an owner typically experiences and all of our pre-startup costs.

Most of the -- there is about $50 million of pre-startup costs which are in two buckets. One of them is to recruit an organization, which we're actually starting to do that right now. We will have employees on board well in advance of the plant being operational and we needed to do that so that they are well trained and ready to operate the plants.

And the second bucket is just the commissioning costs, the sort of gas you consume during early-stage commissioning, which is often offset by revenues but we take no account of that. This is all of the cash that we will spend in moving this plant from A to B and getting it operational between now and the end of 2014.

So all in even including the permanent costs then.

Exactly.

The last question here just on Chile. Just, it sounds like the gas exploration continues to be not where you're hoping it to be. How much have you invested to date and how much are you willing to invest going forward? And at what point do you look at this and say, maybe we should look at moving all of these plants to Louisiana.

Well, we've invested to date about $150 million, Jacob, and when 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 has paid back remarkably quickly.

So when we count the amount of margin that we make on the methanol that we produce at that site, these have been strong investments that have provided a decent return for our shareholders. So that's why we're inclined to continue making those investments.

Looking at what is disappointing in Chile, we haven't seen others spending at the levels that we anticipated. Companies like Apache had a couple of blocks down in Southern Chile, and they elected to surrender those blocks after spending a small amount of money.

I think that is just the reality of 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 that 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 the things that makes me more confident is we are seeing it across a broader array of exploration blocks.

Just in the next couple of months there is a well being drilled in an area called East (inaudible) that is a conventional gas reservoir, that could be quite game changing. Now, I've probably said that a few times.

There's a number of potentially game-changing opportunities down in Southern Chile. And if one of them comes in, our outlook would change tomorrow.

But, really we think -- and when we sit back and think about Chile, if we could run two plants there at capacity, medium to long term, we would be very, very happy. That would be a very nice outcome for us that matches the market need quite nicely.

So it certainly seems to me that we have one, another redundant plant down in Southern Chile that we could relocate. As I mentioned in the prepared comments, we will make a decision on that probably towards the end of this year, or the beginning of next year.

Whether it is to Geismar or somewhere else, we haven't made that decision yet either. But I think we certainly have another opportunity to relocate one more plant.

Thank you very much.

The next question is from Ben Isaacson from Scotia Bank.

First question is on the potential relocation of a 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?

It's probably the biggest aspect, Ben. Clearly, we have done a lot of site preparation. This project has something akin to a greenfield project, in that we're starting with a green, truly a greenfield. That is what it is today. So we do a lot of site preparation. We've built a lot of buildings, admin buildings, storage facilities, warehouses, those sort of things that you never need to repeat a second time.

So a lot of those ancillary pieces on the plants are very incremental and you don't need to start from scratch. So we don't really have an idea of what the number is, though I think it would be certainly in the tens of millions and maybe 100 million.

I think if I could add, Bruce. It's Ian Cameron speaking. If you think about land costs, building costs, organizational build up. There is some costs in building an organization, which we wouldn't have to do. Things like gas tie-ins, engineering, a whole bunch of things that we wouldn't have to spend and you can quickly add up. It adds up to quite a large number. It is sort of in the $80 million to $100 million range.

Okay. That is very helpful.

We're also not planning to demobilize our crew in Chile, so if this works the way we currently think about it, it is that we will continue from one deconstruction to the second without demobilization or remobilization. So there is cost savings there as well. So, yes, 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 plants?

That is pretty much how we think about it. I think if you had one plant on shorter term arrangement that would be okay, but I think having 2 million tonnes on a monthly gas price, that feels a bit too risky to me. So, it would certainly encourage us if we could sign a long-term gas contract.

And I would say in that vein, we are talking to, I don't know, Ian, probably five or six different companies.

Yes.

We have some offers on the table that look very interesting. Today I have a high degree of confidence that we will sign a long-term contract, but as I mentioned again in the prepared remarks, if we don't, it doesn't really bother me too much.

I think we can certainly, as far as this investment is concerned we're confident that we can get our capital back and make decent returns based on financial hedges.

Last question, you talked about demand weakness on the derivatives side. Are you seeing any demand weakness on the energy side for methanol demand?

I'll just ask John Floren to make a comment on that, Ben.

Yes, 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 costs also went down. But that's returned now as oil has gone back up. So, still see strong energy applications for methanol.

Okay. Thank you very much.

The next question is from Bert Powell from BMO Capital Markets.

Bruce, you in your press release 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 is contemplated in the $150 million of capital expenditures that you've got out at -- to the end of 2013?

Yes, it is. There is a number of stages that we need to go through with our plants in New Zealand.

The first Motunui plant that is operating today, there is a planned maintenance outage that we need to conduct in sometime towards the end of next year and we're getting to a point where there are statutory approvals begin to expire, so we need to take the plant down and do inspections and some replacement equipment that we need to have in place for that, as well.

So that is point number one. Point number two is the Motunui site was never, for those of you that have been around a long time will remember the history, it was a methanol to gasoline site.

The methanol plants on there were designed to produce crude methanol and -- which ended up in being converted into gasoline. So those plants were never really designed to efficiently 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. That was back in the mid-1990s, so this is a long time ago. And as the years have gone by, we've recognized there are always opportunities to improve the energy efficiency on that site. It requires probably $50 million or $60 million of capital, Michael, 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 a long life in front of us, to do a very sensible investment that improves energy efficiency on that site. And, again, it's another one of these projects that has a one to two year pay back and a very attractive returns on investment.

And then the third aspect that we're thinking around in New Zealand is the Waitara Valley plant, which is a 500,000 tonne plant. It is a few kilometers down the road. It was last operated, my guess is, kind of three years ago. So there's a little bit of work to be done on that, not too much.

We do need more gas before we start that up, so there is more work to be done in contracting further gas. When we put those three projects together, debottleneck, the repair of Motunui two and the Waitara Valley, it represents a total of about $150 million of capital that we need to spend and that potentially gets us up to 2.4 million tonnes of production from the current 1.5 million tonnes.

So if you look at the incrementally we're getting another 900,000 tonnes with $150 million of capital. But again, compared to relocation or greenfield, or any other sort of methanol investment, 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 or an outage, you said a major outage in Chile in August.

There is some maintenance that needs to be completed. Whether we do it in August or not, we haven't finally decided, but that is 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 sometime in the -- 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.

And then on Egypt, and this will be the last question, there was some warranty stuff, I recall, was supposed to be done in Q3, but it sounds like a little bit was done in Q2.

And then there seems to be some other moving parts and 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 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 on some of the new equipment runs out.

So it is desirable to shut the plant down, do some inspections and make sure that we can make any claims that are sort of necessary under those warranties. So we've now 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 has been operating -- it is operating at about 70% rates today.

Okay. 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?

It is a complicated situation. We're in the middle of Ramadan and in the middle of summer, so I think in Egypt we're clearly in a very uncertain political environment, so that's not a surprise or news to anyone.

What that has transpired is -- what has transpired is that there have been a number of change in some of the key ministries that hasn't really helped decision-making in the last year and a half. And what that's leading to is a breakdown in some of the infrastructure.

There have been electricity brownouts in Cairo over the last three or four months. And you can see breakdowns 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 in the country. I think the reserve to production ratio is about 36 years. This is not an issue, is there natural gas or is it available. The issue is all around maintenance of infrastructure.

So, we are assured that it's being worked on and it will be resolved, but we still continue to operate in a very uncertain political environment. And if you look at what's the root cause, I think that's the root cause of the challenges we're having.

Okay. Perfect. Thanks, Bruce.

Okay.

Thank you. The next question is from Hassan Ahmed from Alembic Global.

Again, just wanted to revisit this relocate versus build decision. Was trying to get a sense of where you think greenfield replacement value is currently because, from the sounds that say that you're guiding to around $550 million as the expense associated with the relocation, which obviously means $550 a ton, my guess was that greenfield replacement value was maybe $600 million to $650 million.

I guess, what I'm trying to sort of understand is that would the real juice of the savings be generated from, indeed, a second plant move?

No, Hassan, I think you're understating replacement costs today, Hassan. What we're learning out of this process is that costs are more expensive than we anticipated. So some of the labor costs we're 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 ton in Egypt. There was a plant in Amman that was built that was a million ton plant for $900 million. That's $900 per ton.

That project was built pretty much at the peak of construction costs and we thought that costs had probably backed off a little from that point. But I think our learnings of the last six months are that costs have tended to be quite a bit higher.

So, I'll just ask Michael MacDonald, who is in charge of our project here, what would you say about capital costs, Michael.

I think that is right, what you're saying is correct, Bruce. What we're also seeing is that the engineering contractors are filling up, so one of the advantages, we think, of the relocation right now is that we ahead of the wave in terms of reconstruction in the United States on the back of shale gas. So we think (multiple speakers)

I think that makes a ton of sense, yes.

That is a good environment for us to be going into. Bruce, the other observation I'd make is that many of the reported numbers that we see for other projects really only relate to the EDC costs and don't include the owners costs and we are transparent, 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 marketplace because they don't include the substantial owner's cost and other capital.

And, Bruce, is it fair to assume that you briefly mentioned maybe for a greenfield facility five years start to finish as being sort of a rough guide. I mean, how much of that is the commissioning side of it, because as I understand it, that is taking a while, as well.

My guess would be as we start marching towards, call it, the middle of the decade or so, you have a flurry of other sort of activity, greenfield plant wise happening in the US. So, maybe a new facility is get delayed even more.

I think as a rule of thumb, Hassan, we think 36 months to construct and commission a methanol plant is a reasonable outlook for schedule. And then so the other two years comes from engineering, permitting, land acquisition. There are lots of other things that have to be done in that two-year period.

Now in some locations you could probably do it quicker than that. But, all of those things take a lot of time. We also tend to spend a lot of time in engineering, Michael.

Again, it is very much a very cautious approach to being sure that we specify the project very accurately so that we know exactly what we're going to get, which is why we've -- we have a very good record of delivering projects on time and on budget.

And I think that is because we spend a fair bit of a time up front making sure that we know -- we scope the project very, very well. Michael, any other comment.

Yes. So Bruce, I'd just add to that, that with the relocation, that most all of the long lead items that are normally associated with a project, say heavy wall reactors, compressors, those sorts of things, those are all the equipment items that are being relocated in this project.

So the project doesn't incur those risks. 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. 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 acetic facility in Singapore, which was down through the course of Q2, and another one that recently, that was clearly planned, now you've had another unplanned outage in Taiwan, acetic, again.

I'm 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 real, real issues in those end markets.

I think one of the issues, Hassan, is there has been a lot of capacity overbuild in Asia in acetic acid (Multiple speakers).

Absolutely

So the operators in that industry are needing to look around at how can they make those businesses make sense. But, I think the fundamental drivers underneath the acetic end of the derivatives, they actually haven't been too bad. I don't know, John, have you any comment on that?

Just we've seen in the last few months a slowdown in China that has 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, et cetera, and the other says it is going to continue at the current rate. So, we're watching it very closely.

I would say throughout the chain 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 our customer level, people are being very, very cautious.

If we did see some uptick in China, as some are predicting, we're expecting to see quite healthy pulls on inventories throughout the chain. So we're watching it very closely.

Very helpful.

Those coastal inventories are down to 13 or 14 days.

12.

Wow.

That's almost unsustainable, but that is the environment we're in.

Very helpful. Thanks so much.

The next question is from Steve Hansen from Raymond James

Bruce or John, just help me provide a bit more color on what you're seeing or hearing about Iran's production plans over the next several months in light of these sanctions.

It's obviously been a little bit handicapped of late, but just trying to get your sense for the next sort of three to six months and their ability to skirt some of the sanctions in place.

Well, it's hard to predict, Steve, but I'd say when the sanctions came in place there was an immediate reaction as tanks filled. I would say over the last few months there is more Iranian product coming out of Iran then we would have anticipated three months ago.

We still understand one of the large Zagros plants is down. The other 3 are running at some level less than full capacity. We are seeing quite a bit of product, more product than we would have expected, come out. A lot of it is going to India.

Some of it is being transloaded in the Gulf of Oman by ship to ship to skirt the sanctions in place on the P&I. And we're also seeing some of the Indian product re-exported to China. So I think the Iranians are finding ways to get product out of Iran.

Is it going to be more or less in the next six months? That is 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 to what we see today for the next six months. But that is a bit of a guess.

I just see in the last few days, John, that imports into China in June were 260-odd thousand tons. And they are typically 400,000 to 500,000 tons.

So there's a complete reflection of a curtailment of normal activity from Iran. What John is saying is some of it is getting out and it is improving, but there are production disruptions that are occurring that reduce supply.

Yes, that's helpful, thanks. And then, Bruce, I just wanted to follow up on the potential for a long-term gas contract in Louisiana. How should we think about the economics of a contract?

You have 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 with a low base price.

Can you give us some sort of benchmarks or goal posts to think about how a contract would work if was to be signed in the next month or so. I'm not saying this thing will be, but just to give us some goal posts on how we'd think about the economics Would the economics be better than the long-term [strip] today? Would they be worse? Whatever you can provide [would be useful].

It depends on your outlook on methanol prices and oil prices, frankly. So, I think a sales pitch to the gas suppliers is that methanol trades up and down with crude oil. If you'd like your gas price to be more reflective of crude pricing, then tying it to the price of methanol is a smart thing to do.

So, on the one hand we could go ahead and do financial hedges today and that's our fall-back position. So, if you want to model it, what we think about 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 or five-year period.

And the advantage of a contract is you don't need to worry about liquidity and there are some other contractual advantages that you get out of having an association with a substantial counterparty. So I don't know, Ian, do you have any other kind of commentary on it?

No, I think you've described it well, Bruce.

Okay. I think I can (inaudible-technical difficulties) Thanks for that. That is helpful. And then just a last one, if I may, on the gas situation in New Zealand. You've suggested adding the additional capacity there and getting ramped up to the 2.4 over time.

But I'm just trying to get a sense for, the last contract you signed gave you a bit of future clarity on supply. Would the same type of contract be available today on the gas situation? Does it take more time? Is it a price issue you're waiting for? I'm just trying to get a sense what the push backs would be or the hold backs on getting a new contract over time.

Well, the market is complicated down there and it is very different than North America. It is a contract market and there tend to be two or three large players and then a handful of smaller players.

So, life has got a lot more complicated for us by needing to have multiple gas contracts with multiple suppliers and we need to have them all integrated with each other. So there are similar size and term contracts that we're discussing with a number of different counterparties.

So I'd rather not say too much more at the moment. We need to get those finalized before we're 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.

It would seem to me that we are completely aligned with the natural gas industry in New Zealand. There's surplus gas available and we're the sensible market for that natural gas.

Okay. Very helpful. Thank you.

Good.

The next question is from Robert Kwan from RBC Capital.

Just on the Gulf Coast relocation side, our analysis is just the plant is quite profitable at higher gas prices. But I'm just wondering at what point, if gas prices do continue a bit of the move up, do you start to feel uncomfortable about committing capital?

They'd have to be a lot higher than they are today. It uses 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 your margin's disappeared. It is not a very attractive investment anymore But you're probably still making positive cash flow.

So I don't see too many people forecasting it on a 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 there that allows us lots of flexibility to return capital and make a decent return.

I guess 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 of safety?

I'm not a believer in the long end of the curve. It is a very thin, illiquid market out there. The liquidity in that market tends to be, I guess, four to five years, Ian?

Yes, that's right. I think from a practical point of view, Robert, I think if you were going to use the financial markets to cure the gas price, you'd probably go out four years or so.

And as Bruce mentioned in his remarks, in his prepared remarks, that debt would cover our payback period at the inferred price in the curve. So I think that would be the product, the way of thinking about it.

And it makes sense. And just the last question somewhat related. I know in the past you've mentioned that you didn't have a lot of interest in actually directly getting into reserves. I'm just wondering if that has changed with respect to a potential joint venture with a gas producer where you can kind of lock in the costs long-term and control the production a little bit, at least the flow to you?

Well, we would rather do it contractually. I think that keeps the parties aligned much better. We're not an upstream Company, despite the fact that we spend a bit of money in upstream in some geographies. At the end we're a methanol Company and that is what we're good at. Companies that are good at drilling for oil and gas, that's what they are good at.

I think a bit of -- We would prefer to have contractual relationships, where we sign contracts that -- where the benefits are shared. And that's been our track record in most countries around the world and that's, I think, there is some proven success with that.

So that's structure is pretty much off the table then for North America.

I wouldn't say it's completely off the table, I'd say it is our strong preference to have contractual relationships rather than try to be an expert in someone else's business.

Okay. That's great. Thank you.

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

Most of my questions actually were asked and answered. Let me just try and clarify here, so the long-term North American gas contract that you're looking at, you are saying you got something interesting or some things that are interesting there. Just to be clear, do you have some that are structured similar to the current arrangements with a revenue sharing component?

That's right exactly. For the most part that is what we're talking about. It's a base price plus some element of the gas price that moves with the methanol prices.

Okay. And are the thresholds similar to what we're used to already on the current arrangements?

Not really. If you look at what does the gas supplier want, they're trying to get something better than the forward curve. It all depends then on what's their forecast around oil prices.

If they have an aggressive forecast on oil prices, then our contract will deliver a lot more than the forward curve. If the future is for lower oil prices, then they're taking some risk around that, but that's the -- those are the conversations that we have.

Okay. And the terms we are talking about in terms of durations are 5 to 10 years would be fair to start.

Yes, I think 10 years probably is what we are looking for.

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. I mentioned we have a debottleneck opportunity in Medicine Hat, so we're getting a little bit larger there as well. So to the extent that we could do some sort of longer term contract at Medicine Hat, we're open minded to that. But clearly today, as gas price is, I think, $2.50 in Alberta, there is lots of profit to be had staying short on gas in that province

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. Is that where we at or are we further now?

It is a bit hard to tell because we're not -- we've only partially hedged and we tend to hedge more during the wintertime because we're a bit afraid of price spikes in the wintertime. We have got a little bit of hedging going out into 2014, but quite small. It's probably a bit less than that number you mentioned, Paul.

Okay, all right. In terms of the maintenance CapEx, after the plant move, what could we see in maintenance CapEx increase?

Well, we've typically quoted before about $50 million a year. That was, I guess, in -- that was when we had one plant in New Zealand and Chile and Trinidad and Egypt. So we've got another location and Medicine Hat as well. So that number is going up. Now, 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 that we're replacing reformer tubes there. It is a plant that is 25, 26 years old -- of age, so it is getting to that time when you need to do some big pieces of maintenance. So that's included in our budgets for 2013.

Same thing at Medicine Hat. Medicine Hat is a 1980s vintage plant and we'll be replacing some reformer 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, I would think kind of $50 million to $60 million is still a reasonable number to assume, Paul.

So just to clarify that a bit, Bruce. When you move that plant and it is utilized at a full rate compared to being now underutilized, the maintenance CapEx doesn't materially increase?

No, not really. We do a major turnaround every three to four years and that is typically $20 million to $30 million of expenses and when you replace some of the major pieces of equipment that I just talked about, you can double that fairly quickly. So no, no, no, the fact that you utilize it more doesn't increase maintenance.

Appreciate that. And last question, you're mentioning in terms of the potential for a second plant being moved and a decision being maybe even before the end of this year, I'm just curious, if you can remind me, whether you move one plant or two plants, I 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 any permitting and what not? Aside from that, what's holding you back with respect to saying, yes, we're moving a second plant? We are finding where.

Well, we don't need to make the decision today. That is probably the primary thing, Paul. The most efficient time to make that decision is before we demobilize crews in Chile. So if we could do a seamless relocation of two plants, that would be a good thing to do.

So we need to make the 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 availability down in Southern Chile.

I did talk about game changes down there. So we shouldn't dismiss the fact that there may be something happens in the next six to 12 months that causes us to think differently about Chile. And we continue to have discussions with Argentina.

I'm 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 say, I'm not going to hold my breath and I don't want to over promise on it, but there are things that could happen that could change the outlook. So why make the decision before you have to? That's our primary thinking.

But are you saying that there will be a likely decision in the six months or maybe post that.

No, no, no, I think in the next six months is probably what you should expect. Six to eight months.

Appreciate it. Thank you.

The next question is from Charles Neivert from Dahlman Rose.

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, 30 months?

And the second question is, the China plants, the MTO, MTP plants in China, particularly the ones that are purchasing, both the one that is 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. And then I will perhaps ask John to comment on (multiple speakers).

The current one that is running that is buying merchant methanol is 100% supplied by China. The Skyford one that I think you're 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 tons total? Is that the one that I've got -- have I got that right, or is that the one that is running right now?

No, that's right. It is the one that is under construction and it'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 would probably see it staged in over months.

Okay. And that's all. Thanks very much.

There are no further questions registered at this time. I'd like to turn the meeting back over to Mr. Aitken.

That's great, we are right on the edge so I was about to pull the plug anyhow. Thanks, everyone, for participating in the call. If you have questions, this continues to be a really exciting time for Methanex Corp.

We've just started up our second plant in New Zealand and you know we're really pleased to have that site coming back into production and we expect to have more good news there in the coming months.

With our final investment decision around our Louisiana project, another nice hurdle to get over. And I've got great confidence in the ability of our team to deliver a first-class project in that location. And we're still in this industry outlook where that looks extremely positive for us.

Demand is growing and underpinned by the energy applications and supply looks quite constrained. So lots of positives for the medium to long-term.

We'll continue to have some short-term blips and I think we've 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 to 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.