Methanex Corp (MEOH) 2010 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by, welcome to the Methanex Corporation's second quarter 2010 earnings conference call. As a reminder, this call is being recorded on July 29.

I would now like to turn the conference call over to Mr. Jason Chesko, Director of Investor Relations. Please go ahead.

Good morning, ladies and gentlemen. I would like to remind our listeners that our comments and answers to your questions 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 2009 annual report for more information.

I would now like to turn the call over to Methanex's President and CEO, Mr. Bruce Aitken, for his comments.

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

Firstly some comments on our results. In the second quarter we reported EBITDA of $57 million and net income of $12 million or $0.13 per share. We sold about 1.7 million tonnes of methanol on an average realized price of $284 per tonne, which is about $20 per tonne lower than the last quarter. And this was the primary reason for the lower earnings compared to last quarter.

Now, second quarter results were also impacted by lower production in Chile and Trinidad, which negatively impacted our cost structure and reduced sales of produced methanol.

I'll comment more on the industry and pricing outlook a little later in the call, but first I would like to provide you with an update on our operations. As I mentioned a moment ago, production in Trinidad in the second quarter was disappointing. We produced 320,000 tonnes of methanol, which is significantly below capacity as the Atlas plant was down for about two months to complete a repair of the reformer, and this resulted in about 190,000 tonnes of lost production to us. The repair was completed at the end of June and the plant has been operating well since that time.

On a positive note, the Titan plant operated well, producing at full operating rates during the second quarter.

In Chile we operated one plant during the second quarter and produced about 230,000 tonnes of methanol. As mentioned on previous occasions, we received less gas supply from ENAP during the Southern Hemisphere winter when more gas is required for residential heating purposes, and this was the primary reason for lower production at our Chile site.

In addition, cold weather conditions caused some issues for gas infrastructure and also we've observed some declines in deliverability from ENAP's gas fields in recent years. Both of these factors also contributed to lower gas deliveries in the second quarter.

And I will comment more on the outlook for natural gas to our plants in Chile again in just a few moments.

Finally in New Zealand the Motunui plant continued to operate well and produce 216,000 tonnes of methanol. And also I'll comment more on the outlook for those operations again in just a few moments.

I just want to switch topics now and address the industry and pricing outlook.

Our methanol demand over the last quarter has continued to increase. And we estimate it has reached all time highs of about 45 million tonnes on an annualized basis.

Traditional chemical demand has shown further improvement in most regions while methanol demand into energy applications also continues to be strong driven primarily be demand in China. Demand for fuel blending in China has continued to grow and currently we estimate about 4.5 million tonnes, or 10% of global methanol demand is used as fuel in China.

We have in the past mentioned that China is reviewing the creation of an M15 national methanol standard. Over the last quarter, Xinhua, one of the official news agencies of the Chinese government, reported that a draft version of the M15 national methanol standard had been completed and after further review the final standard should be issued within this year.

We expect this standard should act as a further catalyst for growth as it will encourage methanol fuel blend to be introduced in a wider scale in China.

And while fuel blending demand growth in China alone provides significant upside to methanol demand, we believe there is also good potential outside of China, and we continue to promote the use of methanol fuel blending in other countries.

It was interesting to read some of the conclusions from a recent study from MIT focused on natural gas, which assessed various options for converting natural gas into transportation fuel and singled out methanol as the best option.

DME in China also continued to be strong in the second quarter and we estimate this market has grown to over three million tonnes of methanol demand on an annualized basis.

As we enter the summer months, demand for DME and LPG in heating in China is typically lower, so we expect some short-term reduction in demand. Also there have been some recent reports of inspections initiated by the Chinese government agencies to address concerns about over blending of DME into LPG, and this may also contribute to some short-term volatility around DME demand.

However longer term, we believe that methanol demand growth into DME and other energy applications in China will continue to be strong, as it has been in recent years.

Many of you may have read about the report that came out at the International Energy Agency last week that highlighted the strong energy demand growth in China.

Reports stated that China's energy use has doubled over the last decade and has recently surpassed the United States as the largest energy market in the world.

With the Chinese government being supportive of methanol as a clean-burning alternative fuel to meet the growing energy needs of the country, this environment is certainly attractive for long-term demand growth prospects for methanol.

Turning to methanol supply over the last quarter. Two new world scale plants in Brunei and Oman started up and supplied methanol to the market. At the same time, we saw some higher cost capacity shut in, and as is typical in the methanol industry, there were significant planned and unplanned outages.

Thus despite new capacity coming onstream, a strong demand environment coupled with supply issues [were] markets into balance and pricing has remained at relatively stable.

For July, our average non-discounted price across the various regions of the world is about $325 per tonne and we've just announced our North American non-discounted price for August at $350 per tonne, which is the same as our July price.

There are two other world scale methanol plants with capacity totaling 2.2 million tonnes which are expected to start up in the second half of this year including our own Egypt project, which I will update you on shortly.

These new plants may cause some short-term volatility in pricing. However, longer term, the industry supply and demand outlook remains very attractive.

Apart from plants coming online this year, there's little new capacity expected to come online over the next few years. This suggests the supply will be challenged to keep up with anticipated demand growth and this should support a healthy methanol price environment over the next few years. This environment also lines up well with our plans of increasing production in Chile and at some of our other locations over the next few years.

On this note, I'll switch topics and provide you an update on the key initiatives we are working on to increase production.

First thing natural gas supplies to our plants in Chile.

We are currently operating one plant in Chile at a site operating rate of about 20% to 25% and expect to operate at a similar rate during the third quarter.

As I mentioned earlier, our gas supply is negatively impacted during the Southern Hemisphere winter and we expect this factor to continue to impact production in Q3. However, we still expect to be back operating two plants at reduced rates later this year after the Southern Hemisphere winter is over.

At this time we also expect to be receiving more gas supply from the two gas-producing blocks, GeoPark's Fell block and the Dorado Riquelme block, where we have a joint venture with the Chilean state-owned oil and gas company, ENAP.

These two blocks continue to generate new gas discoveries and today they're supplying us with about 70% of the total gas supply to our Chile site.

However, in part due to the weak economic environment over the past couple of years, the overall pace of gas development in Southern Chile has been slower than expected.

Reflecting this, we have recently reduced our expectations for Chile production over the next couple of years and are now forecasting about a 10% improvement to our annual production in Chile in both 2010 and 2011. After 2011, we continue to expect a more significant improvement in Chile production.

By this time, several of the international oil and gas companies that are exploring in the region are expected to shift their exploration activities from seismic work and regulatory approvals to drilling more development wells.

Our current expectation is that about 200 wells will be drilled between now and the end of 2012.

In addition, the Chilean government announced that over the last quarter their interest to assign additional areas to the private sector over the next year, which should further increase the level of E&P activity in Southern Chile.

In short, while the pace of development in Southern Chile has been disappointing, based on the success we have seen to date and the significant increase in drilling activity expected in the next few years, we continue to believe that we can increase our operating rates in Chile considerably in the next few years.

Nothing has changed our medium to long-term views about prospectivity and the potential to substantially ramp up our production facilities in Chile.

The next project I wanted to provide you an update on is our new methanol plant in Egypt.

Construction of the Egypt project is essentially complete and the plant is currently in a commissioning phase. As mentioned on the last quarterly conference call, we have experienced some delays in construction but these are now largely resolved.

In the last few weeks we have met important commissioning milestones giving us more confidence in the forward schedule, which should result in methanol production in the fourth quarter.

We are very excited about the prospect of adding this first-class asset into our supply chain, which will increase methanol supply to our customers and increase our cash generation significantly.

Turning to our operations in New Zealand, I am please to report that over the last quarter we have finalized gas contracts with a number of gas suppliers, which will underpin production at our existing 900,000 tonne Motunui plant until the end of 2011 with some options for further gas in 2012.

In addition, with the improved gas supply and demand outlook that has developed in New Zealand, we are seeing a more competitive gas pricing environment and better potential to contract increasing quantities of gas to supply our plants.

Also as I have mentioned on previous calls, we were involved in an initiative with Kea Petroleum, or Kea Exploration in New Zealand, to fund some natural gas drilling activity in the Taranaki region near our plants.

Over the last quarter, Kea began its drilling program and while the first well drilled did not prove to be commercial, it tested positive for gas, which was encouraging results.

Together with Kea we are reviewing the data from this well to decide on next steps and we expect further information on this prospect during this quarter.

The (inaudible) that I wanted to provide you an update on is our project to potentially restart our plant in Medicine Hat, Alberta.

Our goal has been to secure a commercially acceptable gas contract with a supplier in the region who would underpin the restart of the plant. To date we've had little interest from gas suppliers to support a longer term contract. But we continue to explore options including contracting on the spot and forward markets.

In the current Alberta spot gas market of about $3.50 per MMBtu, the economics of the Medicine Hat plant would be quite attractive. If we were operating the plant today, we would recover the capital required to restart the plant in about 12 months. However, the forward market for gas in Alberta is more expensive and make the economics more challenging.

We're completing some site preparation work at the plant site that will put us in a position to restart the plant by mid-next year if we are successful in securing gas supply. And we expect to make a final decision on this project later this year.

I'll change topics now and make a few comments regarding our liquidity and capital allocation.

During the second quarter we generated $44 million of cash from operations before changes in working capital and we continue to be in a strong financial position.

We have considerable leverage, a $200 million undrawn operating facility, no refinancing requirements until 2012, and a cash balance of $178 million at the end of the quarter.

Our immediate priority for the use of cash is to take advantage of the excellent opportunities to increase production at our existing sites that require only a modest amount of capital.

Specifically we continue to-- we plan to continue committing capital to accelerate gas development in Southern Chile, and if we proceed with our projects to restart capacity in New Zealand and Canada, we would commit some capital at these sites in coming months.

We are in a strong position to satisfy these initiatives, completing the Egypt project and our planned maintenance expenditures.

Before stopping for questions, I will comment on our expectations for the third quarter.

[Directly] as a result of the Atlas outage and lower production levels in Chile, we start the third quarter with lower than normal inventories of produced methanol and higher than normal inventories of higher cost purchased methanol.

So while we expect sales to continue to be strong in the third quarter, we also expect a lower level of produced methanol sales which will result in reduced margins.

Secondly spot methanol prices have moderated a little early in the third quarter, but there are many variables that affect pricing and we're reluctant to even suggest the trend. However, taking both levels of produced sales and selling prices into account, we expect earnings to be lower in the third quarter.

I hope that you've gathered from my comments a level of frustration and disappointment over the current lower levels of production and earnings.

We set ourselves high standards in operating our plants and delivering against our plans and our performance falls well short of our expectations. However, while these short-term issues are frustrating, nothing has changed longer term.

The demand/supply outlook for our industry looks very promising and this together with strong energy prices can be expected to support strong methanol pricing.

And Methanex is in the unique position of being able to increase production capacity with only modest capital expenditures. This combination of pricing capacity addition can be expected to be a significant driver of value.

So at this point, ladies and gentlemen, I'm happy to stop and take any questions that you might have.

Thank you. We will now take questions from the telephone lines. (Operator Instructions) The first question is from Jacob Bout with CIBC. Please go ahead.

Hello. First question would be on Chile, so you talked about lower production outlook. Maybe just help us, when do you expect to have the second plant fully operational?

Well the words we've used, Jacob is later this year. It's -- I think it will be September or October, one of those months. But we have got some work going on to debottleneck some infrastructure and as soon as that work is completed, there is gas behind pipes that will come into the system.

That's -- some of that work is a little bit weather dependant and its equipment dependent, so I don't have an exact timing for that but we think it's around the end of this quarter and the beginning of the next quarter.

So is that a partial restart or is that a full restart?

No, no it was the two plants were operated at lower rates. I think it will be similar to the situation we had in Q1 of this year.

Okay. So to have it fully up and running would be third, fourth quarter 2011?

Well, I expect so. I think what we've -- what we're learning is that GeoPark and Dorado Riquelme can be a really helpful additions to our gas supply and I think you can take from my comments that ENAP is becoming a smaller and smaller supplier of natural gas to our plants in Chile.

And it's not so long ago that they were our only supplier, so we've seen declining rates of production coming from the state-owned company and increasing rates of production coming from the private investment that's been made.

What we need is to begin seeing gas coming from some of the other prospects. So I think lots of work had been in the Fell block and Dorado Riquelme is very positive, it will continue to support the operation of 1.5 plants, if you like, but it's the incremental production that will get out of other areas that will really help us ramp up production.

And in that regard, we have seen Pan American have drilled a couple of wells this quarter and are currently testing them. I know Apache Corporation have drilled some wells and they're contemplating future plans.

A company called Greymouth Petroleum, they've -- they have been drilling and they've got another well that's currently being drilled right as we speak.

And in the Tranquilo block, which is a block that we have a small interest in, we have a drilling plan that starts up in I think in the fourth quarter this year.

So there is a lot of activity occurring but we've seen no concrete results from any of that yet and I think that's symptomatic of the fact this takes a while to assemble our resources and to go through the process of getting regulatory approvals and doing the work and then eventually building the infrastructure to deliver gas to our plants.

Okay, that's helpful. Maybe my second question would be just on the M15 standard.

I know that the -- there was the press release that came up that suggests there was a draft in May. Has there been anything new since that time period? And when you look at this, is it -- is this going to be a function -- or will the announcement be part of that five-year plan that they're -- I think they're going to sit down and start working on that in October.

I don't know, Jacob, and we don't have any particular insight. We talked obviously to lots of people in China who are better informed than we are and we're told by a number of parties that it's likely to be the end of this year, before the end of this year.

Now if you remember back to the M85 standard, there was talk of that for a long time before it eventually came out. So it was slower coming out than everyone anticipated, but it eventually came out and it's now a national standard.

So it just seems that there is a process that we don't particularly understand that occurs in China. And that that process is making good progress and there's nothing to suggest that the M15 standard will not be published in -- later this year.

Okay and then maybe just last question. Can you comment a bit on what your thoughts are on inventory levels for methanol throughout the industry?

We think they're very tight and it seems an extraordinary thing to say. We've had -- our new supply coming on stream. I think demand has been very good in the second quarter and continues to be quite strong.

I'm thinking of all the customers that I've met in most of the regions over the last two or three months and all of them would describe their businesses as being better quarter-over-quarter and seeing continued improvements in demand and pricing for their products as well.

So we've certainly seen our customers taking maximum volumes under their contracts and you can see that in their sales volumes. Their sales volumes are very strong and we're expecting the same thing in the third quarter.

Because we're so dependent at the moment on purchased methanol, we're obviously an active participant in the spot markets and it is increasingly difficult to find surface molecules.

So there is not a lot of spot methanol around, which suggests that the inventories are low and that's being reflected in pricing as well. We've seen increases in spot pricing in I think all markets in the last few weeks.

And I mentioned a moment ago we've rolled July prices into August and I think that's several months of price stability in North America or Indonesia. So it all suggest that there's a reasonable balance of supply and demand and not too much inventory around.

Okay, thank you very much.

Okay.

Thank you. The next question is from Hassan Ahmed with Alembic Global. Please go ahead.

Hi, Bruce, how are you?

Hi, Hassan, good, thank you.

Good, thank you. Another quick question regarding the gas situation in Chile, if I may. There are some people who are raising concerns about the shallowness of the gas fields in Chile, coupled with let's call it higher decline or depletion rates.

My question is that if that really is the case in Chile, would that require sort of constant drilling of wells and a high degree of sort of recurring capital outlay?

And additionally, if that is the case, how should we think about the gas supply there as well as the medium and longer term pricing of that gas there?

The -- we think the prospects of finding a monster field in Southern Chile would seem to be quite low. There's been enough work done to suggest that the accumulations of natural gas in that region tend to be smaller and tighter.

Now that said -- so that would suggest reasonably high decline rates and that's what we have observed, and we've observed that from ENAP's fields and we've observed that from GeoPark as well.

So, yes, there is a need for continual drilling. Now the good news is the wells are not particularly expensive, we think around $2 million per well is our recent experience.

And of all the economic analysis we've done, would suggest that a gas price between $2 and $3 provides a pretty decent return on investment for an upstream company.

And the other aspect is that a lot of gas has got related oil, so there is oil in the region as well. Now it's gas-prone, so it tends to be -- you tend to find more gas than oil. But oil revenues at $70 to $80 a barrel is a nice increment to gas revenue.

So I think the good thing about that region is the companies can look for oil, which is probably what they're doing, and know that there's a viable market for natural gas.

And I think that's what will underpin out of long-term operation, that there is an economic prize there. It's a very stable part of the world. I think the politics and the regulatory regime is excellent.

So I think you see companies like GeoPark talking very positive about their experience in Southern Chile.

So there isn't -- so getting specifically to your question, there isn't a need for ongoing capital expenditure.

But when I've looked at what we've invested, I think $70 million to $80 million over the last couple of years. The return on investment we've made on the money that we put out is extraordinary, it's in the 20% to 30% range.

So as long as we can find investments that make those sort of internal rates of return, we're going to be -- continue to be encouraged to invest in looking for further natural gas.

Very helpful. Thanks.

Okay.

Thank you. The next question is from Sam Kanes with Scotia Capital. Please go ahead.

Yes, It has to do with Argentina. I've been reading I guess there might be preliminary or trial balloons, but there's been talk about gas discoveries in Tierra del Fuego on the Argentina side and possible ammonia/urea plant construction developments, which maybe brings an old wound back on, what if anything, you've heard about that or what if anything you would do about that to the extent that that gas is somewhere nearby and you were still owed that gas under long-term contracts?

Well, there's been lots of speculation around plants in Tierra del Fuego for a long time, Sam. And it's not a particularly easy place to build or pitch a chemical plant.

One, it's extremely remote. Two, shipping is a big challenge. It's really exposed to the south Atlantic and there are no decent ports on -- in Southern Argentina in that area.

So it would not be a very easy decision for someone to make. I understand it's a Chinese company that's been quoted.

Yes.

We've seen nothing particular to know how serious it is, but certainly we take seriously the fact that there -- that we have contracts for large quantities of that gas in Southern Argentina.

And we would have to think very carefully about how we reacted if a plant was built that started to consume reserves that we felt had already been contracted to ourselves.

Now, it's being a little bit speculative because I think it's a long way from making any decisions on that.

Okay. In terms of speculation, maybe we can stay with that for a follow up.

BP they've announced a lot of different assets for sale and sold a significant chunk already in Canada. Obviously you share a plant in Trinidad and MHTL, not sure if that was ever resolved, I'm just wondering of the status of play on those two things to the extent you can give some thoughts?

And in general whether or not hypothetically if they both came to you looking for a solution of exit strategy, is anything stopping you from being the one and only methanol producer in Trinidad?

Well, lots of speculation this morning, Sam.

Well, stay in the theme.

I'll just get my crystal ball out. We've had a relationship in Trinidad with BP now for eight or nine years, and I'd say it's an outstanding relationship.

We've really -- we feel as though we've really gained from having BP as a partner in that country. And longer term, we're interested in natural gas clearly in Trinidad and BP are the big producers of natural gas in that country. So we like the relationship, we like the alignment what we have with them. So we're certainly not anxious to see them depart.

To the extent that their share on the methanol plants that they want to monetize it, then we want to be the 100% owner of that plant, there's no question. But we're not going to do anything to accelerate that decision. I'm sure that they have much bigger things to worry about today than worrying about their share holding in the methanol plant.

So it's something that might come up in the future and as I say if it does come up, we want to be the 100% owner of that site.

As far as the MHTL is concerned, the messages I get from the government in Trinidad is that they want to continue to be a significant owner of that -- those operations. And I think that's just fine with us as well.

I think we're very comfortable with the investments that we had in Trinidad, they've worked very well. And we've got no particular ambition to become the only producer of methanol in that country.

Thanks, Bruce.

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

Yes, good morning, everyone. Just first question on Egypt, I'm not trying to be too specific but I just want to make sure I understand the role out of Egypt or at least the plan for Egypt.

I think if I recalled in the past you said you were going to start commissioning in sort of the later third quarter and have commercial product available in Q4.

Are you -- is it a slight shift here, or are you expecting product early Q4? I'm trying to get a sense for the commercial volumes that might be available for Q4

It is a slight shift, Steve, and I think one of the things that's tough for us we never quite know how our -- how methanol flows in and out of inventory, so we certainly expect to be producing methanol in the fourth quarter. How much of it ends up flowing out of inventory and into our sales volumes, that remains a bigger question.

So I guess I would encourage the analysts who follow that company to be a bit conservative on those volumes and I'd hope that we can surprise you on the upside but these are big complicated plants and they will take a bit of time to -- we want to make a really good job, we want to do it safely and have a really long, solid long-term reliable operation.

So we're not going to indecently rush the process, but we certainly expect to be producing methanol in Q4, but probably have less volumes of commercial sales than I would have suggested three months ago.

Okay, good. No, that's very helpful. Just a hypothetical situation. I've just been reading this morning on the new Iranian sanctions imposed by I guess the U.N., the US and even the EU now and the impact that has on their petrochemical complex, it doesn't sound like there's been any impact on methanol exports from the country to date, but is that a situation that you're monitoring or it's on the radar at all?

Yes a couple of things we're observing in some of our customer in Asia who've traditionally taken product from Iran now having a lot more trouble in -- with the banking systems.

So it's not so much the dealing with Iran that seems to be difficult, it's dealing with the shipping companies who won't ensure -- who won't take insurance on Iranian cargoes and the banks who clearly won't handle remittances this time for Iran.

So it does seem that the sanctions are making, I think, more and more difficult for the Iranians to distribute their product in the market.

We've also -- I don't know if you've also picked up, there's been an explosion in Kharg Island where there's a 600,000 tonne methanol plant and -- which we understand has had a quite a negative impact on the ability to operate that plant.

We don't quite know for how long but again, sanctions will not make it very easy for them to get that plant back online quickly. So -- it's hard to point to specific instances and certainly there's been no blanket impact on methanol per se, but I think sanctions won't make it easy for the methanol industry in Iran to continue to operate at the levels they're operated at or to export at the levels they have historically.

Okay, that's interesting. Just -- I should maybe while I'm still on Iran, I know you've talked in the past with other countries hypothetically looking at methanol fuel blending. I understand these sanctions also impact the country's ability to import gasoline, which they apparently need, is there -- does this type of event have perhaps the impact of accelerating their evaluation of methanol fuel blending or is that something that's way down?

I would certainly hope so. Through the methanol institute, we've been working with some of the Iranians on educating the decision makers on the benefits of methanol blending.

So I think that it's a really great solution for that country to help them make up for any shortfalls in gasoline. But again, I don't have any -- we don't do business in Iran, we're not there. So everything we know is a little bit second and third hand, Sam.

Okay, sure. And then just one last, if I may, I'm just -- on your inventory situation, can you remind us what your inventory storage capacity would be and approximately sort of where you're sitting at current inventory levels?

Heavens, that's a tough one because we have inventories in ships, at our plant sites, and in the marketplace, and the inventory that we really take account of is the inventory that's sitting in the marketplace and there we typically, in most of the big markets, we have about 30 days of storage capacity.

We would -- at the end of the quarter it's probably hard to tell from our numbers, but we're sitting right near the bottom of where we'd like to be. Our plants are working better so we're beginning to rebuild our inventories but we've got a bit more work to do to get our own inventories back to a level that we're comfortable with.

Okay, great, that's it for me for now. Thanks.

Thank you. (Operator Instructions) The next question is from Charles Neivert with Dahlman Rose. Please go ahead.

Hi, guys, how we doing?

Good, Charles, thank you.

A couple of quick questions. Egypt and the dimethyl ether initiative, so to speak, how does -- how is that going? Are they continuing to meet and --?

Yes, it's going remarkably well. It's been again very slow. And we've been completely focused on the methanol plant and that's the big prize for us.

We're a, I think we're a 20% share holder, we've got a minority position on the DME plant and it's really been driven by the Egyptians themselves. They continue to be very enthusiastic about it. They've done -- within Egypt they've done cooking trials and experimentation with DME to make sure that they understand the characteristics of DME.

We've also -- we've been undertaking some cooking trials here in Vancouver as well just to -- so that we have confidence around the viability of the product. And everything that we've determined is consistent with what has come out of China that the blending rates that are used are -- this is a viable, clean fuel. So nothing other than kind of positive results there.

I think we've now committed to the [front-end] engineering design -- is anybody in the room -- yes. We all think that that's the case. So we're now spending money, getting close to a decision to -- as to how to build this plant.

You'll recall, well you might recall from our investment in China, it doesn't take long to build these plants, it's 12 to 18 months. So we'd expect some time probably in 2011 that plant would be in production.

Okay. And what's the capital cost on one of those plants approximately given -- I assume it's about the same size as what you -- what's been built in China?

I think it's around $50 million to $60 million. That's a wee bit of a -- a wee bit speculative. Yes, so I'm getting some nods around the room.

Yes, that's what I seem to remember. Okay. Also on methanol markets, just the different markets, are there any in particular that are maybe sort of lagging the recovery?

We know the fuels are doing well and we know that some of the others that you mentioned, but is there any particular market, large or small, that's sort of not really gotten moving yet, formaldehyde for instance or anything else like that?

Formaldehyde has recovered I think extremely well. And again just thinking back to the discussions I've had with our big formaldehyde customers, and I think 2009 was a really, really tough year for them. And as they've come out of that, in both North America and Europe, they've seen good recovery.

Markets like silicones and methyl methacrylate, they're extraordinary. The growth rates continue to be very strong, the prices are good and our customers are very happy with their position.

Like acetic acids again -- seems to continue to be demand is quite strong, prices area bit volatile but the downstream derivatives of acetic mostly seem to be doing quite well.

So, no, I would say, Charles, there's nothing really that is not -- that hasn't more or less recovered from the decline in 2009.

Okay.

And of course we know the icing on the cake for our industry is the energy demand, as you mentioned, just continues to boom away.

Okay and last question, in the repayments that you've gotten on the gas investments you've made in Chile, have they been in gas? I mean it wasn't -- I think that was insinuated early on that you would take some of that back in gas, is that what it's coming as or is it coming as cash?

Our arrangement with GeoPark is a more or less a gas prepayment. So as we take gas, some of that comes to us at no cash cost. And that's the repayment of our loan.

Okay, and that's how it shows up as that sort of repayment on the investment, that's where it's showing up?

Absolutely, that's correct, yes.

Okay, just wanted to make sure of that. Thank you.

Okay.

Thank you. The next question is from Paul D'Amico with TD Newcrest. Please go ahead.

Hi, Bruce. Most of my questions were asked and answered. Let me just sort of extrapolate a bit on the EMethanex. You mentioned in terms of the conservatism for Q4 and I'm just wondering if I can go a bit further then.

Would you have the same view with respect to Q1 in terms of that gradual ramp up or is it fair to say that the conservatism sort of extends just to Q4 at this point?

Yes, I think just to Q4. The uncertainty is around the start up period and making sure that everything is working as it's supposed to and we -- in the Company we've had a pretty good track record that when we start the plants up they tend to operate at quite high rates of utilization from an early stage.

But there are always those little gremlins there that you're never quite sure about. So, I just want to be a little bit cautious around being unduly optimistic in sitting high expectations that we may not be able to deliver to.

Okay. And I don't know if this is pushing it a little too far but just to avoid any missed sort of communication here, when you're saying Q4, are we talking like late November/December or are we talking any time in Q4?

Well, I guess I was talking about the level of commercial sales in Q4. So we expect the plant will start up in either late Q3 or early -- it will start producing first methanol late Q3 or early Q4.

But it's how much methanol do we produce and then how does that flow through inventory and what shows up in sales, what impacts our earnings. So that's where I was suggesting to be a little conservative on that as you're forecasting Q4 revenues.

I was referring to sales, but that's fine. Second question, just a bit of understanding here. In terms of the Q2 realized price versus Q1, the discount being higher sequentially despite lower pricing, is there any way you can sort of reconcile that for me?

Well it's very hard, there are lots of moving parts. The level -- the explanation we've given in the past is around these fixed price contracts. Now the level of fixed price contracts has declined quite significantly this year, so that now has less impact.

So it does seem -- the discount is driven more by volumes in different markets so, we do see in different markets, different levels of discount. And I think as we went through 2009 and came into 2010, we have seen increasing levels of discount and we've needed to react to competitive situations.

So there has been I would say an overall increase in discounting off of contract prices in the last year to year and a half so that's had some impact. To increase dividends -- to increase discounts on the other hand, as far as our results are concerned, there's been a moderating effect from lower levels of fixed price sales. So is there anything else, Ian or is --?

No, I think it's more -- pricing more stability in the discount --.

Yes, so around this level of 13% or 14% is probably where we're going to see -- with less volatility than we've seen in the past.

Okay, so you're comfortable that that discount rate is kind of stable in the near term at least?

It seems to be. I don't like to be too definitive.

There are a lot of moving parts, Paul but -- and it can change depending on what region the methanol is sold in and things like that. So you're always going to have a little bit of movement around the edges but I think we should see more stability.

Okay, appreciate that. Thank you.

Good.

Thank you. The next question is from Fai Lee with the RBC Capital Markets. Please go ahead.

Thanks. Bruce, I just want to understand the commentary you had earlier about Chile and your outlook for production. It sounds like this year, 2010, overall production in the back half of 2010 will be almost mirror image of the first half, and if I --?

Yes, that's probably a fair estimate.

Okay. So we're maybe looking about one million to 1.1 million tonnes of production and you talk about 10% higher in 2011 and 2012.

It is 2011 I said.

20112, okay, so it's only 2011. And it used to be about 1.5 then or something like that?

Certainly we've reduced our estimates, I'm just thinking of our own budgets, we were a lot more optimistic about increased volumes in 2011 than we are today. So, yes I don't what -- I don't know if we've published the --?

We've never provided guidance on it in terms of actual numbers but the trend is -- or not the trend, I should say that we do believe in 2011 it will be a little bit lower than we thought in the past.

Okay. So now it's going to be about -- okay so it will be what 10% higher than the one to 1.1 this year?

For this year, that's correct, yes.

And now what about 2012, you talked about maybe 2012 might be better than, I guess?

Yes, that's our expectation. And again, we don't particularly want to provide guidance but I -- what I talked about was the number of companies who are exploring and the money that's being spent, the number of wells that are being drilled.

So our insight into that is a little bit better than yours, probably five, but at the end we don't know precisely that the amount of gas that's going to come out of these wells and the amount that's going to be delivered to us.

But I think it's reasonable to say based on what we've seen happening in the Fell block and in Dorado Riquelme, that if there's a similar experience in some of these other blocks, then we'll see similar levels of increase in gas deliveries that we've observed from the new exploration in the last year or so. So that certainly gets you up to two to three plants in 2012.

Okay. All right, because I'm just trying to figure out in terms of the progression in terms of your production, potential production profile that's kind of going to be like at this sort of a 10% increase per year or if there's going to be a more rapid --?

No, I think there'll be a bigger step up. I think what we're seeing is the time it takes for companies to -- I mentioned before they start off with doing seismic surveys and analyzing data and then getting environmental approvals and then getting drilling rigs and people and equipment and after all that's' done, then you need to start thinking about building infrastructure and it just takes time.

And so I remember like very early on when this process started, people were asking me how long it's going to take and we were perhaps naively optimistic that because there was a lot of infrastructure in place that it could happen quite quickly.

Now what we're learning over time is that there's a lot of work to be done here and oil and gas exploration is not something that happens instantaneously. So we've -- it's a bit frustrating but that's the reality of that industry. And I've used the word lots of times in the past that we're using our money to try and accelerate development.

So that's what our focus is on trying to get things to go more quickly. And I think we've demonstrated good success with that with the prospects that are active and that's what all of our focus is on in the future, how can we encourage companies to spend money more quickly and to get gas to us more promptly?

And I think all those things will generate significantly increased quantities of gas, but exactly how much and when, every quarter I hope I've got a little more information for you. But it's really hard. The further out we go, the -- it's the more speculative those answers are going to be.

Right. But given what maybe what you know now and your experience and what you've learned and given maybe your best-case scenario, you've talked about the plants eventually getting back to the four plants operating, what sort of timeframe are you looking at, at that point?

Well in our models we've got (inaudible) 2013, 2014, we've got our four plants operating again. But as I say the further you go out, the more speculative that is. I just think that when we look at how we've assembled that data, it's a reasonable extrapolation of experience to date.

So I think those are reasonable estimates, but they're no better than that, and there's a lot of work that needs to take place to underpin those reasonable estimates.

And no, but that is helpful. It's like -- to help us, because it's not like 2018 that you're thinking about that.

Sure.

Okay, and just a couple of other small questions. The inventory, you had an inventory drawdown of 135,000 tonnes in the second quarter and you talk about rebuilding, is the target to rebuild that difference or do you have to go above that or can you stay below that?

No, it's probably about that level that we would want to rebuild to. We'd like about 30 days of inventory in our entire system and we've got less than that, we've had less on that for much of this last quarter.

And it requires us to do silly things with our supply chain that add cost and add inefficiency, so we know that having a little bit more inventory reduces our costs, so -- and improves reliability and service to customers. So we're really driven to be as efficient as we possibly can.

Okay. And just the last question, you mentioned Medicine Hat, I think you'd have a decision by the end of the year, what are the milestones or what are you waiting for in order to make that decision? Is it the -- I'm trying to understand the cost or is it -- do you expect to you finalize a supply decision or something?

It's really gas more than anything. I -- perhaps I don't understand the market well enough but I look at the daily gas market in Alberta every day and the spot price continues to be in the mid $3 range, I think it was -- it was exactly $3.50 yesterday. And you look out to the summer 2011 and the price is more like $4.50.

Now the last couple of summers, the price of gas has been around today's level, in that $3 to $4 range. At $3 to $4, this is an extremely profitable operation and makes a whole lot of sense. Even at that higher price, it still makes a bit of sense. But it's clear the more we pay for natural gas, the more we're reducing returns on investment.

So I think like most companies we're driven to try and maximize our return on investments and we want to try and get ourselves in a position where we can lock on some gas that gives us -- that allows us to recover our capital really quickly and then it's almost as though we have a free option to operate the plant when it makes sense and not operate it when it doesn't make sense.

So I think the probability of proceeding with this investment is more than 50/50. But we want to continue looking at what's happening to the gas price. We are doing -- I mentioned a little earlier we are doing some work to preliminary site works, I think we're spending around $5 million so we're certainly approaching this quite seriously.

And we're doing a lot of planning around what we'll do if -- when we make that decision. So I continue to think it's the right thing for us to do, but we don't want to particularly expose ourselves to a volatile spot market that we don't understand.

Right, but I guess what I'm trying to understand let's say three or four months from now you're going to make a decision, is there -- do you feel you'll have a better comfort with the gas market or is there something in the works on the gas supply?

No, no the -- I think the -- what I've observed is the gas market has been changing constantly so as we've looked out at gas prices for summer 2011, they were over $5 and not too long ago. And today they're, I think they're around $4.30, $4.40 so they've come down a lot in the last six to eight weeks.

Now are they going to continue coming down? I don't know, I don't have great insight. But what I observe is that the price for winter 2010/2011 is about the same as summer 2010/2011. And to me that doesn't make sense. The historical trends in that market have always suggested that winter gas prices are higher than summer gas prices.

So there's something -- there's something that happens in that market that I don't particularly understand and it seems that as you get closer and closer to the summer months, that the price continues to come down. So we continue to [play] a lot of attention to the day-to-day movements and if it gets to a point where we think we can lock in a quantity of gas that allows us to recover our capital, then that's when we'll make the decision.

Okay, I understand now. Great, thank you.

Thank you. The next question is from Brian MacArthur with UBS Securities. Please go ahead.

Good morning. Not to keep on this Chile for too long, but in that assumption of a 10% growth rate, have you assumed that ENAP's gas continues to decline, so there's a factor in there for that continual decline given that's what you're seeing? Or it is still going to be a 70/30 split going forward?

Well, if you go back a few quarters, it's only probably a couple of quarters ago, Brian when that split was 50/50. So that split's been going steadily upwards in recent quarters.

So -- but the good news is that ENAP have just recently begun drilling again on Tierra del Fuego and in some of their older gas fields. And that's been the problem, someone asked the question a little bit earlier about decline rates. But in an oil and gas region like this if you don't continue to drill, then you'll see declines in deliverability.

So there is this continuous requirement to -- if you want to maintain deliverability, you have to invest in capital. But the good news is you can get a decent return on capital based on gas pricing that is available and based on oil prices.

So no, I think their latest plan, if I recall correctly, is about eight wells by the end of this year, Jason, is that -- do you have that number? I thought it was eight or 12, I can't remember. It's something like that.

Twelve.

Twelve wells before the end of this year. So and then I know they're in the middle of that program right now. So we do expect to see at least stability and possibly some increase in gas supply from ENAP in the coming months.

Okay, no that's what I was trying to figure out, whether you're relying more or less on them going forward. You obviously want to rely less on them I suspect given the reliability, but I just didn't know how much you were factoring in because it leads to my second part of the question is given that stuff I still believe is, you get a contract (inaudible) at a base price and you share the up and down portion of it.

But if new gas is going to cost $2 to $3, I assume you want to try and structure it the same way going toward that you share. But yet over time, even if we do get more gas out of other places that base price, or let me put it this way, the risk and the downside goes up because our base price of getting gas, presumably if it's costing $2 to $3 versus what you're getting today is going to get higher going forward. Is that correct?

Well, I wasn't suggesting the base price is $2 to $3, I was suggesting that the overall price of $2 to $3. So I think that the methanol industry or our economy can certainly support an average gas price of $2 to $3 and we can still make a pretty decent return on our investments at that level.

So I wasn't suggesting that the base price goes to that level, I was suggesting the average price goes to that level.

Right but we had with ENAP historically we had a lower base price that basically they supplied it all at one time, you had a base, you had some ups and downs sharing.

We still have that --.

Do you think you -- you still have that on their gas but on the new --?

And with other suppliers as well so there is an element of risk sharing here that -- and it's -- at times of high methanol prices, they get much higher than gas prices that give them great returns and at times when we're in a more difficult environment, they accept a more modest return. So it is that same sort of win/win relationship that we've developed in the past.

Right, now I guess this is where I'm going with this, so but do you think the relatively -- the relative sharing of win/win is going to be the same split in the past as it was before when you just had one, effectively one guy supplying it all, if you see what I'm saying? Or is that moving up?

I think the base price has gone up. We used to quote our base prices as a $1 in all the markets around the world, and we still have some of that gas. But that $1 gas was negotiated when oil was $15 to $20 a barrel and the world's moved on from there, hasn't it?

Right.

So we know that and observe that, but I think what I'm trying to indicate is that the economics for gas in that part of the world is still very attractive relative to the manufacture of methanol.

Right, so you're saying, which is where I'm just going with this is, vis-a-vis where we were expect to say six months ago where we're disappointed that the ramp up is slow on a volume basis, you're okay -- we're still okay on the cost sharing and the profitability equation, we're just getting less of it in the near term than what we thought, it's kind of that sort of thinking is where you are.

It's taking longer, that's the frustrating reality.

Right, but we haven't changed the other part. Okay, just quickly on two other things. Egypt, I just can't remember, if you can just remind me, the tax structure there, there was a little bit a [favorative] tax structure I thought it was over the first two years, is there anything that moves if the thing continues to be delayed that you get to get that preferential or is that related to the start up of the plant or is that just a time period issue?

No that's -- the tax rate is 20%, Ian, and there's all sorts of accelerate depreciation. So we wouldn't expect ---.

That's right.

-- much from cash taxes for quite a few years, but it's -- there's nothing that's impacted by the --.

Delay.

-- of the plant, no.

Okay. And finally just sorry, what again Medicine Hat, what do you think in term of capital there, that hasn't changed at all, has it?

I think I've said 40 to 50 in the past. So that's about -- still about right.

Still the same thing?

Yes.

Okay, great. Thanks very much, Bruce.

Okay.

Thank you. The next question is from Chris MacDougall with Treaty Oak Capital. Please go ahead.

Great, thanks a lot. Going back to the Iran thing, one kind -- or a couple high-level questions related to that. One, can you give me an order of magnitude how big Iran is in the methanol market? Is it about four million metric tonnes?

I think it's over just over five million tonnes of capacity.

Okay.

Now they typically haven't -- they've operated at relatively low rates of utilization. Some plants seem to operate a little better than others and I would say they have been improving their rates of operation in the last year or so as well.

So I haven't got a number exactly but it's probably around 60% to 70% would be a reasonable guess of their rates of utilization.

Okay. And then if something were to happen to that capacity, what -- or in any other situation, what is your experience with the elasticity of the methanol markets? So if we loose 10% of the industry capacity, how much does the price go up to balance supply and demand?

Well, that's a tricky question because historically the answer to that would have been there's no elasticity of demand. And that would be the case in traditional markets, so there's no substitutes for methanol and formaldehyde, and there's not many substitutes for formaldehyde that make economic sense.

And then you said the same thing for acetic acids and silicones. So demand will drive up the price. Now the change that's occurred in the last couple of years is the energy markets.

So we observe almost monthly movements in demand and supply for DME based on the price of LPG. So if the price of methanol escalated dramatically, I'm sure that we would see a decline in consumption of DME.

So I think the good news is we've had great demand growth from methanol as an energy product. The bad new is that that has introduced some elasticity of demand, which would potentially would moderate price increases in the future.

Okay. Then moving on, I actually wasn't aware of the long-term contracts with Argentina still kind of existing. Is there anywhere back in the old filings that I can get more some details on that or can you give me the high level if -- and I know it's pure speculation if something where to change there and you would have to go deal with this in the Argentina or international courts, but give me the high level on what those contracts look like.

Yes, so just briefly, we used to get -- well we should be getting today about 80% of the gas that runs our plants from Argentina. So roughly that would be eight million cubic meters a day of natural gas.

And the guidance that we used to provide on those contracts is we had this conversation just a couple of minutes ago, that we paid about $1 as a base price and then we shared about 1/3 of incremental revenues above $150 a tonne methanol price. That was -- from four or five years ago, that was the guidance we used to provide on Argentinean gas contracts. So all of those contracts, they're still alive, they exist.

We've retained legal rights to pursue remedies under them but we've concluded that that's --- they're not particularly easy to get at and we're more inclined to try and work with people to find sensible solutions than waste lots of money in the courts.

So we are not doing it even today to try and recover damages as a result of a failure of people to deliver under those contracts, but we certainly retain the right to do so.

Okay, great sounds reasonable. And then you touched on the change in the cost structure just over time as prices have creeped up. Do you want to help us out with our models and give us some updated guidance on what that is, excluding Egypt, what a reasonable base assessment is?

So the guidance today, the guidance I gave you just a few minutes ago was from four or five years ago, that's changed a little.

Right.

We're now say at about $1.25 is our average base price in all the contracts around the world. And we share about 1/3 of the revenues above $150 a tonne. So it's --.

Okay.

A relatively small change from where it was, but that replicates from our release what our global gas price is.

And then your fixed cost, since you don't break out the SG&A component in your operating, what rough amount or so are your fixed costs and I would say excluding Egypt, because I know you've given that guidance separately?

It tends to vary a little bit, it's around, we think around $20 a tonne to run plants. And the bigger they are, the more economies of scale you tend to get.

So when Chile's operating at capacity, it's a lot lower. And then logistics cost around the world, again it tends to vary by market but all up including in market storage and market transportation it's around $40 to $50 a tonne. So that's kind of more or less the guidance we offer.

Okay, thanks a lot.

Okay, all right so I think we're a little over now. If there's one last question I'll take that but otherwise, we'll relieve everyone to go and think about something other than methanol.

No, so that sounds like the end. That's great. Well thanks again, everyone for participating in the call and for your questions and your interest.

I do feel a real sense of disappointment in the last quarter that the performance we've had from our plants, particularly the Atlas plant in Trinidad, we can find lots of excuses and reasons for it, but it's not the standard that we set ourselves. And I say the same for natural gas in Chile, that when we've -- when we make plans we want to execute against those plans and that's one of the big drivers for our Company in the next couple of years that we want to be able to deliver.

And it's disappointing to me that in Egypt and Chile and in generally just running our plants, it doesn't feel to me as though we've been good at delivery in the last six or eight months.

So that's something you can be assured that we're spending a lot of time and effort on within the Company. And I continue to feel incredibly positive and optimistic about the future.

All of the long-term things that we've talked about are still in place and we're very positive about gas in Chile and the prospectivity there.

I'd like to think of this time next year we'll either be running a plant at Medicine Hat or close to and getting similar to -- with a similar decision made in New Zealand.

So we're on this path to doubling our production volume with competitively-priced natural gas. And again, those of you that follow our Company and analyze the numbers know that we make money when we produce lots of methanol and that's the path we're on.

And the reason we're not making money today in a healthy pricing environment is because we're not producing enough. So we certainly recognize that as the issue and we're driving hard to correct that.

So again, thanks for your input and we look forward to talking again next quarter.

Thank you. The conference has ended. Please disconnect your lines at this time and we thank you for your participation.