Methanex Corp (MEOH) 2011 Q2 法說會逐字稿

(Operator Instructions)

Welcome to the Methanex Corporation second-quarter results conference call. As a reminder this call is being recorded on July 28, 2011. I would now like to turn the conference call 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 2010 annual report for more information. In addition, with Egypt now having a significant impact on our financial results, I want to clarify that any references to EBITDA, cash flow, or income made in today's remarks reflect our 60% economic interest in the Egypt project. I would now like to turn the call over to Methanex's President and CEO, Mr. Bruce Aitken for his comments.

Good. Thanks, Jason, and good morning, everyone, and welcome to our second-quarter investor conference call. I have a number of colleagues with me in the room, and they will be available to help answer questions a little bit later. So firstly, some comments on our results. We reported EBITDA of $104 million and net income of $41 million, or $0.43 per share.

We are in a stable pricing environment during the quarter. EBITDA was up 33% over the last quarter, as we reported higher sales of produced methanol as a result of production coming on line from our new plants in Egypt and our Medicine Hat operations. However, our Q2 results only reflected some of the Egypt and Medicine Hat production, as much as the methanol produced in those assets in Q2 did not flow through inventory in the quarter. So we expect to see further upside to our cash flow and earnings in the second half of the year when the production from these plants is fully reflected in our results.

I'll be commenting more on our expectations for the third quarter and the industry and pricing outlook a little later on the call, but before that I wanted to provide some brief comments on our operations. Firstly, as a general comment, with the addition of Egypt and Medicine Hat, it's pleasing that we have achieved our highest level of quarterly production since the first quarter of 2007. Our Trinidad operations produced 449,000 tonnes of methanol in the second quarter, compared to production capacity of about 500,000 tonnes.

The Titan plant was down for some maintenance for a couple of weeks, and this was the primary reason for production being below capacity. In September, we were planning a turnaround of the Atlas plant, which was expected to last for about a month, resulting in reduced production of about 150,000 tonnes. However, this plant has suffered an outage in the last week, and we are currently contemplating a repair strategy on how this should be integrated with the turnaround.

Our Motunui plant in New Zealand operated at full rates during the second quarter, and we produced 207,000 tonnes of methanol. In Chile, we operated 1 plant at half-capacity and produced about 142,000 tonnes of methanol. Gas supplied to our site in Chile continues to be challenged, and this is particularly the case today as more natural gas is used for residential heating purposes during the Southern Hemisphere winter. I will comment more on our outlook for our operations in both Chile and New Zealand again in a few moments.

The Egypt plant operated very well during the second quarter, running mostly at capacity, with our equity share of production being about 178,000 tonnes, and so while it is normal for a new plant like Egypt to run at reduced rates in the early months of operation, this has not been the case for us here. The plant has operated very well, and has recently passed all contract of performance tests and the reliability tests required under the project financing. The excellent operating performance achieved is a reflection of the strong team in Egypt, who has done a great job in bringing this plant on in a challenging environment.

Finally, our team in Medicine Hat in Alberta has also done an excellent job in restarting the plant. The plant started up in late April and produced 74,000 tonnes of methanol during the quarter, which reflects close to full operating rates since the startup. In recent weeks, the plant has demonstrated performance slightly higher than our expectations, and we are continuing to fine-tune the operation to optimize both efficiency and cost. We expect strong operational performance to continue in the second half of the year. We currently have gas supply underpinning the production of this asset until the end of 2012, and are confident that the long-term natural gas dynamics in North America will support the long-term operation of this facility in the future.

Turning to industry conditions over the past quarter, markets have been relatively balanced and pricing fairly stable, despite the recent startups of Egypt and Medicine Hat plants. China drove demand higher in Q2 and imports into that country to the end of June were up by more than 20% compared to the same period in 2010. Demand in other regions has also remained firm or improved. In addition, and as is normal, there have been quite a significant number of planned and unplanned outages across the global industry.

Strong crude oil prices and increasing Chinese coal prices over the past quarter have also supported tighter conditions. So with constrained production in China, 5 of the world's largest methanol plants currently not in production, and inventories at lower than normal levels, there is significant upward pressure on methanol prices. Yesterday we posted Methanex's North American non-discounted price of $1.38 per gallon for the month of August, which is up $0.10 per gallon from July, and we announced an increase of $50 per metric tonne in Asia, also for the month of August.

Methanol demand in the fuel blending, and China continues to be strong, and high crude oil and gasoline prices, and affordable methanol prices have been a key factor driving strong demand growth. There are now 11 provinces in China with methanol fuel blending standards in place, and more under development in other provinces. Most of the provincial standards in place are low-level blends, typically about M15, or 15% methanol.

High-level blending programs are also being developed, supported by national standards that are in place for the M85 and M100. As an example, earlier this month, there was an article in the China Global Times newspaper that reported on taxi trials in Shanghai running on M100, or 100% methanol. In addition to the environmental benefits of using methanol as a fuel, the article highlighted the economic benefit of methanol, estimating that each taxi would save close to $400 per month in fuel expenses using M100 compared to gasoline.

Today the fuel blending market in China represents around 5 million tonnes of annual demand, and there's a lot of potential for more growth supported by strong automobile sales and increasing gasoline consumption. High crude oil prices have also continued to support healthy DME demand in China, which today represents another 3.5 million tonnes of annual methanol demand.

On the last call, I also mentioned the increasing interest in using methanol for olefins production. Similar to methanol fuel blending, these projects are driven by the competitiveness of methanol relative to crude oil-based alternatives. There's already 1 methanol to olefins plant in Inner Mongolia operating, while 1 other facility is operating the olefins unit and purchasing merchant methanol. In addition, 1 further NPO plant is expected to be producing later this year.

There are many other projects in the planning or construction phase, and a number of these are contemplating the use of merchant methanol as a supply source. These projects have the potential to consume a substantial amount of methanol and provide a lot of upside for methanol demand. To put this demand potential into perspective, the plant which is operating today consumes around 1.8 million tonnes of methanol to produce around 600,000 tonnes of olefins.

Looking at longer term, we expect the market to be quite tight over the next several years. Methanol demand growth is anticipated to continue to be strong, and there is little new capacity expected to come online to meet this demand growth. This implies a strong pricing environment will be needed to entice higher cost industry capacity to operate to meet demand growth, and this outlook matches well with our plan to increase production.

On this note, I will switch topics and provide you with an update on some of the key initiatives that we are working on. Firstly, in Chile. As I mentioned earlier, we are currently operating 1 plant at about 50% operating rate, and the short-term outlook for gas supply through the rest of the Southern Hemisphere winter continues to be challenging. We are still faced with the short-term risk that gas deliveries could fall below the levels required to operate 1 plant for a period of time. However, we believe that gas supply should improve further during the fourth quarter to alleviate this risk. Longer term, we continue to believe that there is upside production from new gas development in southern Chile.

Development activity has been accelerating, and we expect that trend to continue as international oil and gas companies step up their drilling activities in the region. We also understand that the Chilean government will be awarding additional exploration blocks in the region in coming weeks. However, the reality is that the pace of development has not been fast enough, and the level of gas discoveries has not been significant enough to support a timely return to high capacity utilization at the site. As a result, we remain committed to supporting gas development in Chile.

We are also looking at other options to create value from our Chile operations, through both capacity relocation and installing coal gasification as an alternative, utilizing coal from a local supply source. We believe both of these opportunities have the potential to increase competitive cost production at a lower capital cost and in less time than a new Greenfield plant. The potential economic return from both of these options is significant. We are aggressively pursuing these projects and are targeting to make a decision on them by the end of this year. With limited new supply entering the market over the next couple of years, our Chile assets offer a unique opportunity to bring on capacity relatively quickly and in a favorable industry environment.

Finally, turning to our operations in New Zealand, as I mentioned on previous occasions, we currently have gas contracts with a number of gas suppliers which will underpin our production at our existing 850,000 tonne plant through 2012. And, based on the improved natural gas supply position that has developed in New Zealand, we believe that we will be able to secure more natural gas to enable us to restart a second plant. We are continuing to work with gas suppliers in New Zealand to meet this goal, and are targeting to have sufficient gas contracts in place by Q4 of this year which would allow us to restart a second plant. If we are successful, we anticipate the restart of that plant would occur in the middle of 2012.

I will change topics now and make a few comments regarding liquidity and capital allocation. During the second quarter, we generated $86 million of cash flow from operations. We have conservative leverage at $200 million undrawn operating facility which we recently extended to 2015, and a cash balance of $246 million at the end of the second quarter. We're also in a much stronger position to generate cash flow with the Egypt and Medicine Hat plants now operating, and this improved cash generation potential allowed us to increase our dividends by 10% during the second quarter.

We plan to continue committing capital-to-gas development in both southern Chile and in New Zealand, and we're planning for a modest amount of capital for the restart of the second plant in New Zealand. We're well-positioned to satisfy these initiatives and planned maintenance expenditures. And as mentioned earlier, we are targeting to reach a decision by the end of this year on relocating capacity from Chile and installing coal gasification as an alternative feed stock. And we are maintaining financial flexibility to execute these projects. Longer term we expect to build on our strong track record and return more cash to shareholders, through both dividend increases and share repurchases.

So, before stopping for questions, I will briefly comment on our expectations for the third quarter, and as ever, there are lots of moving parts and assumptions that will evolve over the quarter so it's difficult to provide precise guidance. Firstly, I have commented on price increases in August, and with the methanol pricing trend being upwards, we would expect that higher prices will at least be maintained through this quarter. So compared to Q2, we expect to realize a higher price in Q3.

As I mentioned earlier, while the Egypt and Medicine Hat plants were producing at high rates in the second quarter, we did not see the full impact of this volume in our Q2 results. In Q3 as more production from Egypt and Medicine Hat flow through our sales, we expect to see higher levels of produced methanol sales. Offsetting this a little is the current outage and turnaround planned for the Atlas plant. We have not finally determined the repair and maintenance strategy, and while we expect lower production from Atlas in Q3, the impact on our results will probably be greater in Q4. Higher prices and increased sales volumes of produced methanol should generate stronger earnings in the third quarter compared to the results we've just reported in the second quarter.

So at this point I'm happy to stop and take any questions that you might have. Are you with us, Operator?

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

There's been some local press reports talking about a gas find, I think it says 165 kilometers northeast of Puntarenas, basically Pan American Energy and ENAP, and they are saying that it could be as much as 3 million cubic meters, per day I guess. What are your thoughts on this, and is this realistic as far as gas supply for your plant, and what would be the negotiated price for gas for something like this?

Sure. Thanks Jacob. We've been aware of Pan American's activities for some time, and we've been in dialogue with them and doing whatever we can to support their activities, but the news release was a bit fresh for us as well. I think there's two things that it really underscores for me is, one, we've been saying for quite a long time that we are convinced that there's a lot of natural gas in southern Chile. So I think this is further affirmation that there's no question that there is gas that exists in that part of the world. The challenge is spending the capital to get it developed, and I think that's part of the challenge with this particular discovery. I think all oil and gas companies look at their portfolio around the world, and today they favor anything that is liquids-rich and it is not hard to understand that. You can secure $100 a barrel for liquids and somewhat less on a mmbtu basis, for natural gas, then it is not hard to understand why they are motivated to spend their limited resources securing liquids revenues. However, that said, as I say, we've been in discussions with Pan American and with ENAP. This gas discovery, there is some oil there as well. It is a little bit off the pipeline but not too far. So there is some development that will be needed in terms of gas processing and pipelines.

So we are very hopeful that, and as part of our discussions with Pan American, that we can secure this gas supply to our facilities. It represents 3 million cubic meters a day. To run our total our facility at capacity we need about 10 million cubic meters a day. So this is one small block in a much larger area that apparently has a capability of delivering 30% of our total gas needs. So clearly it is something that's attracted our attention and we are enthusiastic to see that development occur. As far as gas prices are concerned, I have said for a long time that our gas contracts have these methanol-related sharing elements to them, that rewards gas suppliers when methanol prices are higher. And as we've seen today, methanol prices are robust and trending higher. So that is reflected in the gas price that goes back to the gas supplier, and I think offers an attractive return on that gas.

But to be fair, I mean, using the rule of thumb that you've given us, historically even at 4, 450 methanol price, the gas price they'd be receiving would be, say, somewhere in that 4 to 450 range. Would they be happy with that?

Yes, that's right. I think that would be a very acceptable price for us and a very attractive price for the gas supplier. So yes, that's about the range that we think is reasonable.

Maybe just a quick follow-up. Has there been any renego -- or in Egypt, them trying to renegotiate the gas contracts?

No, not at all. We've have a lot of conversations with the various authorities in Egypt in the last few months, and we keep being told that they're really pleased with our project, that it represents a tangible example that Egypt is open for business, and it is a real success story that we, together with our partners in Egypt, have started up this plant and run it so well at a time when there is so much political uncertainty. So I think we get lots of kudos for the work that we've done there to bring this plant up and run it, and I'd say no suggestion whatsoever that there should be any change to any of the terms that are being negotiated by previous governments, and the Egyptian authorities have talked about the enthusiasm they have to create an environment that's conducive to foreign investors. So I know that messing around with contract terms and changing conditions is not something that makes a country conducive to foreign investments. So it would be very inconsistent with what they are saying, if they were to change their contract terms, and again, there's a methanol price sharing arrangement in place in Egypt and in the current pricing environment, the returns on natural gas in that country I think are pretty decent for the gas supplier. So I think that to the extent there was any pressure for gas prices being too low, the fact is that the high methanol prices takes that pressure away anyhow.

Just a comment there, though, would be that with some of the nitrogen producers in that area, we have heard that there has been the reopening of some of these contracts.

Some of those contracts, as I understand, were fixed price so they weren't related to the commodity. So the ruling that the government made, and this was before the revolution, this was some time ago, is that fixed price contracts were to be realigned to the market, but those contracts that had a reference to the commodity price, they were okay because they had their alignment to the market by reference to the commodity price. So that's been the rule of thumb that has been applied in Egypt over the last few years.

Thank you.

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

Hi Bruce, how you?

I'm very good, thanks Hassan

Question around China. Obviously the Chinese government seems to have finalized its five-year plan in May of this year, and just sifting through that, there seems to be obviously a fair bit of focus on energy-intensive industries, obviously petro-chemicals being front and center. So if you could just talk about what your views are about this five-year plan as it pertains first to the supply side of things, meaning could we see some rationalization of inefficient facilities, methanol facilities, out in China? And then on the demand side of things, as one looks at the backlog and the planning phase of a variety of facilities, the MTO activity seems to have picked up substantially. So if you could give your views about these two aspects?

Sure. That's good questions, Hassan. So the five-year plan has got lots of principles in it that are very supportive of consolidation of the industry, a real concern about emissions, and managing and controlling emissions, and improving air quality, and improving environmental performance, and encouraging the development of greater energy efficiency, which I think that's code for shutting down less efficient capacity. So I think we will continue to see, and we have seen in recent past, we will continue to see smaller, less efficient plants being shut in. The other, I think, significant factor is that they want to ensure maximum value for the raw materials that they are consuming in their country, and so we've seen lots of enthusiasm for methanol to olefins and the belief is that if you're going to turn coal into methanol, then the highest value use for that methanol is to turn into olefin, and that's part of what's driving the large number of projects that are currently on the drawing boards.

The one project that's operating today, the Shinwa project, uses Chinese technology, and what we've been told is that project has been quite successful, and now demonstrates the commercial scale of that technology, and having reached that point, they are now enthusiastic to expand the footprint of MTO plants throughout China. So when I put all those things together, and you look at the capital that's been invested in methanol, and the demand for olefins, I think we're going to see a lot more merchant methanol that's produced today, and perhaps some of this idle capacity that sits around today that will be directed towards olefins manufacture. For anyone who might have been concerned that there was surface capacity in China that was going to overrun the world market, I think that concern has well and truly been put to bed, which, by the way, I was never concerned about that. I just think it is no longer an issue. So, in my mind, there's two things. One, this gasoline blending is going to continue because blending methanol with gasoline is also a very high value use for coal and for methanol, but an even higher value use is olefins. So I think that's the trend that we've been seeing, and I think the five-year plan underscores that trend in the future.

Very fair, and as one looks at consultant numbers and the like, I really don't think -- as best as I understand them -- MTO in terms of the demand side of it, people have really baked in much demand coming from the MTO side of things. So that could really be a pleasant surprise, no?

Yes. They haven't. I think, and even in our own analysis, Hassan, we've tended to just leave MTO out because these early plants, the Shinwa plant is an example, there's an integrated coal mine to poly olefin chain of investment. So I think, from memory, it is an $8 billion to $10 billion, so a lot of money. So it is not really methanol to olefins. It is coal mine to poly olefins, is what that investment is. What's emerged, I think, in the last year are people voting merchant -- olefins capacity that is dependent on merchant methanol. So now people are wanting to purchase methanol on the market in order to support the investment they've made in the methanol to olefin process. So I think that's the change, and none of that demand is reflected, I don't think, in industry forecasts. So yes, all it does, and you know what happens when you increase supply in a commodity -- increase demand in a commodity industry, it implies the price is going to go up.

Fair enough. Thanks very much Bruce.

Okay.

Thank you, The next question is from Bert Powell from BMO Capital Markets. Please go ahead.

Thanks. Bruce, I actually just wanted to pick up on that last question. The MTO in China, where they have captive self-supply and they are using Chinese technology, is that interchangeable with the methanol in terms of, if the olefin side goes down, can that stuff make its way into the merchant side, or is it not of sufficient quality to make its way into the merchant side?

So there's no one answer to that question. Some of these plants produce what we call crude methanol. So it has water in it. So you need to distill it and refine it in order for it to supply the chemicals market. Some of them don't. Some of them have a higher quality and you can certainly use some of that methanol in the fuels market. I think the challenge is that these coal mine-based projects are not in a location and don't have logistics set up to suddenly switch from shipping 5000 tonnes a day of methanol to the market, when they're set to deliver 5000 tonnes of their methanol to a downstream unit. So I think the logistics of that represent a significant barrier to that occurring. So we've seen exactly the opposite occurring, that there's a desire to use coal for an alternative use then we've seen sales of merchant methanol to Shinwa and to the other developers. So they've been consuming merchant methanol rather than shipping their methanol into the merchant market. So I don't know. I think there's some more water to flow under this bridge yet, Bert, but I don't see that as being a significant threat.

Okay. In terms of Chile, with what's turned in to be some stranded capital, is it possible that you could pursue a dual track, Bruce, where you would move some of the capacity and contemplate changing the other over to coal, or is it an either/or?

No, it is both. I think both projects look really interesting, and we've really focused a bit more now in the US Gulf, and we have lots of opportunities. Hardly a week goes by when someone isn't calling us to suggest a different location or some other ideas around where and how to locate some of our idle capacity in the US Gulf. So we are working hard on that.

I think we will be in a position to make some decisions on that by the end of this year, and then alternatively, coal in Chile is a really interesting opportunity. There's lots of coal. The coal mines today supply only a domestic market for electricity generation in the north of the country. The coal is kind of stranded and trapped. I think there is little or no opportunity to export that coal into global markets. One, it's relatively low heat value so it doesn't attract premium prices, and two, southern Chile to the major markets would be a major transportation issue. So I think the large quantity of coal in that area is significantly [chetcraft] which makes it quite inexpensive, and I think one of the things that's always put me off coal a little bit is the emissions characteristics and the environmental consequences. And one of the interesting things we have in Chile is that when you put a coal-based plant alongside a natural gas-based plant, there are lots of efficiencies there, which substantially reduce the CO2 emissions from a coal-based facility. So we can certainly contemplate building a coal-based plant in southern Chile that has similar CO2 emissions to the natural gas-based plant, which is hugely more efficient than the coal-based capacity that we see in China. So what coal gasification looks like to me in Chile is an investment of capital for sure, but what you end up with is a very competitive cost structure and you can do it a lot quicker than you can build a Greenfield plant anywhere. And it would be the same as relocation, that I think we could relocate a plant in, let's say, a couple of years, whereas I mentioned before, five years from start to finish on a project like Egypt. We have a lot more enthusiasm to charge on with projects like that then think about the next big greenfield project.

What's the capital cost to do the coal? I think the last call you said sort of $500,000 a tonne to move and up to three years. So you've got some cost and time advantage, on the coal side. What does that look like?

It is really hard for me to answer that question. We have a lot of facility in Chile that we can reuse, but some clearly need to buy a gassifier and we need to invest in some of the coal handling and coal management systems that we really don't have much of a feel for. All I can say is it's a significant discount on replacement capacity. Now, is it half, or less than that, or a bit more than that? I don't quite know but I'd say it is probably of that order. So I'd rather not get specific about it other than to say the capital is very inexpensive relative to replacement cost and the operating costs, once you've got it, are very, very attractive. So the payback is quick and the returns are high.

Thank you.

Good.

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

Good afternoon guys. Quick question on Trinidad, the Titan operation. It isn't back to full bore operations yet, based on the second quarter. Are we likely to see in 3Q something back in the middle upper 90s again?

(Multiple speakers) Charles, that the maintenance we had in Titan was in the month of April so Titan has been operating very well and very stably since that. I think we had two weeks in April. So then there are no issues with that plant. It should operate at high rates of utilizations in the quarter.

So we should see that back up well north of the 200,000-tonne line for the quarter going forward?

That's correct, yes.

The other thing is on your debt line, how much of your current debt is not really your -- is Egypt's piece of the debt for the Egypt plant? I'm just trying to sort out the debt that's really yours.

It is complicated, and thanks to IFRS, our accounting reports are becoming more and more complex. So that question confuses me as well.

Charles, it's about $200 million, approximately

Okay.

Yes. I would think the $200 million as being our gross debt, and I think the number in our balance sheet is more like $900 million.

That's right.

Got it, okay. Yes, that's when I was after, that's helpful. Okay, and given the way Egypt is running and how fast it has come up, and that you have a history of running some of your larger plants at numbers that are actually above rated capacity, is it reasonable to consider that Egypt might conceivably run above rated capacity somewhere as you move up the learning curve, get it sort of lined out and -- ?

It could a little but I wouldn't want to over-promise and under-deliver on that. I think we're being very cautious with Egypt. It is a new plant. You typically have some issues with them, and (inaudible) what we've had, almost nothing. That plant has run really, really smoothly since the day we started it up, and I think it speaks volumes of the quality of the equipment that we've got and the people that we have running that site, and the work that we've done in designing and preparing for the operation. But I think continued caution and just treating the plant very carefully and very slowly. So I think the short answer is yes, we can, but we are not going to be very aggressive with it. We are going to take it very easily.

And then, same being true for Canada. I'm assuming the Medicine Hat operation is going to run somewhere toward the low 90s being a somewhat older plant, but again, what you're talking about seems to indicate it might get closer to where, or something close to what the Trinidad plants might be running at from an operational --

That's right. It is been running at above our expectations. When we compare the operation at Trinidad -- of Medicine Hat to our original forecast, we've been running at higher rates than we anticipated. So, and there's a little debottleneck opportunity in Medicine Hat, nothing much we can do on that in the next six or eight months but it is something that's on our radar screen as well.

And then you talked again about the Atlas plant and what's going to go on there. We don't have any idea how long the combination of outage/maintenance is going to take and what the plant is going to be, but if we go with the original assumption, you said you were going to lose, you thought, about 150,000 tonnes of production out of that plant. Is it likely to be a little bit larger than that given the current situation?

I think it is going to be a little bit less than that, frankly, Charles, in this quarter, but what it probably means is that we will have some downtime in the fourth quarter to complete the [turnaround] so we probably will not have completed the turnaround in the next quarter.

Okay. Got it. So right now what you're contemplating is fix the problem and then go to the maintenance at the same time frame you had originally expected to do it?

That's right. There is a longer term fix to the equipment issue that we've had and we'd like to coincide that with the turnaround, and that will probably occur in the fourth quarter.

Okay. Got it. That's helpful. Thank you.

Okay.

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

Yes, good morning everyone. Just looking at the coal conversion option for a moment. Bruce, do you have a sense for what type of feed stock contract you would be able to strike on the coal front? Would it be some sort of quarterly or termed price point, or would you be able to strike some sort of variable price mechanism that you pursue for gas in the region or even (multiple speakers)?

That's exactly what we are after, Steve. That we have a term sheet with the coal supplier that is variable priced based on the price of methanol. So it very much follows the pattern that we've developed with our natural gas suppliers.

Oh, okay, brilliant.

And again I think it is offers a nice upside to the coal supplier. I think we can provide a base price that is very attractive to them, and higher methanol prices then provide some super returns for them.

Okay. That's helpful and just a broad little macro question. Have you seen any new developments on the blending front, the gasoline blending front, outside of China and Southeast Asia areas, Middle East areas?

There's lots of little things going on. There's nothing big that we can really point to, and illustrate that large volumes of methanol are flowing in that area. I think Iran is one country that is short of gasoline, they've got lots of methanol. So they are running methanol gasoline trials, and we understand working quite closely with the Chinese on blending agents and anticorrosion agents, and picking up some of the Chinese technology. So we would certainly expect to see more Iranian methanol flowing into gasoline in the coming months and years. Mostly other things around the world, and there aren't lots of them. They're mostly trials where people are looking at methanol as an option, but nothing huge that we can point to in terms of large volumes.

That's it for me. Very helpful, thank you.

Thanks Steve.

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

Good morning. I just wanted to follow up on the potential relocation issue. When you opened Medicine Hat, you went in and you got enough gas for a certain period of time to recover your capital and get an option going forward, but obviously that was a plant that was in place. As you think about relocating a plant, let's argue US Gulf Coast for a sake. It takes you some time to move it. Then it is moved. Would you be kind of thinking it will be capital re-allocated, but do you also want a longer term contract to make you go through all that hassle? So what I'm saying is, do you go and get a 5-or 10-year contract to make you relocate the plant, or would you just be willing to do it for a coverage of all the hassle? How should I think about that?

Well, I think when we look at the natural gas dynamics in North America, we are persuaded that the low natural gas prices are a reality for the, I'd say, the medium-term, and what do we mean by low? I think $4, $5, $6 is probably the reality, and I think at those levels you can sustain a, certainty a Brownfield investment in the natural gas-based methanol plant in North America. However, so from the big point of view, if we could not be successful in signing a long-term contract, we'd be inclined to go ahead anyhow. However, we are talking to a number of parties and we would prefer to sign a long-term contract so we have some certainty around natural gas pricing for a longer period of time, and I'd say we are having some success with that. I think a year ago there was no receptivity at all from the natural gas industry to sign long-term contracts, and I've seen a number of them being signed lately, mostly with utilities.

So I think the industry is getting itself to a point where they understand the growing demand for natural gas will only occur to the extent that they are able to attract long-term customers, and people are not going to spend hundreds of millions or billions of dollars building new assets without some certainty around feed stock pricing. So I think the market is changing. It has changed dramatically in the last few years and it's still changing, and I think there is a broader, deeper market for contract gas in the US Gulf today than there was even six months ago.

Right. You feel pretty comfortable. It wouldn't be just like a two-year or three-year deal, you could get something longer than that?

We are talking about 10-year deals, and I would say, I think a year ago you'd receive little or no interest in those contracts, and today, and to my knowledge, we're talking to three or four different parties who all expressed an interest in longer-term contracts.

Okay then switching back to the New Zealand problem, because we work through it. You have one plant through the end of 2012. We're going to have a decision on a second plant by fourth quarter, but I've got to spend capital for my second plant to come back. Should I assume you're talking about getting enough gas to run both plants through for another two to three years, or is it I'm going to extend the current plant and I'm going to get a contract long enough to cover the capital for the second plant, or how do you -- I could argue you don't open a second plant, I just get longer gas and have more certainty for four years with that gas on one plant. How are you factoring that all into the thinking?

So that is a consideration for us. We've looked at natural gas balances in New Zealand, we've convinced ourselves that the market is long, that there's more gas available, and we're the ultimate sink for surface natural gas supply. So we think the big picture is that there's enough gas to keep our two plants operating for a three, four, five year period, and in any country, the reserve to gas ratio typically is six, seven, eight years. So that's what New Zealand looks today, more like 12 to 15 years. So there is a surplus of gas availability, we think, underpins that plant, so thinking around the second plant is a bit like Medicine Hat. We tend to be a bit conservative, and we if we need to spend some capital we like to think we can get the capital back. So, the thinking here is if we can secure enough gas to assure ourselves that we can recover our capital, then we've just bought ourselves an option to operate two plants for a longer period of time.

So my own view is I think there is five to six years of a two plant operation based on what we know today. And what we see happening in that country today is a lot of exploration activity. Most of the natural gas is condensate rich. So people are not drilling holes looking for gas, they are drilling holes looking for a condensate and oil. So gas needs to find a home and we are that home. I think the combination of circumstances in New Zealand, I think are quite favorable for us. It's taking us a bit longer to get to the point where we want to get to, and we are putting a lot of emphasis on trying to close some things in that country quickly. And we'd like to think we can get incremental capacity started up very soon. The market is short, where we could sell a lot more methanol today if we had more capacity available. So we are incentivized to really be quite aggressive in pushing for capacity, and again, whether it is in the US Gulf or in New Zealand, the same incentive exists.

Right, thanks, and one last just real quick question. I know Jacob asked in Egypt about renegotiating the gas contract, but if I remember and I just cannot remember, I probably should, there was a tax holiday when that started up, and now I see the Egyptians have increased the tax there from 20% to 25%. Is that whole tax holiday for the year-and-a-half gone and I should just start paying taxes in Egypt at 25% now going forward?

No. We're accruing taxes at 25%. I'd say there is a lot of accelerated depreciations, and we aren't paying any cash back for, what, five years, Ian?

Yes, about that.

So it replicates the tax holiday we had but it is in a different form, but certainly for accounting purposes we are accruing tax at 25%.

Right, but you don't have effectively, I thought originally you had the tax holiday and you had the accelerated depreciation. It's all gone into one now?

Whether it was ever quite like that I'm not sure. It is not like that today. Today we have accelerated depreciation, and probably at least five years where we are not paying cash taxes.

Okay, that's great. That helps very much. Thanks very much.

Thank you, The next question is from Adam Starr from Gulfside Asset Management. Please go ahead.

Hi, how are you?

Very good, thanks, Adam.

I just had a question on the discount, because your plants have changed from a few years ago, and your gas supplies agreements are different with Medicine Hat and Egypt replacing some of Chile. What kind of discounts should we look for going forward, because there's virtually no change in the realized price in the second quarter versus the posted price?

There's two things going on. When some of these fixed price contracts that we inherited when we purchased some of the plants in Trinidad are starting to drop off the table. So we are selling less methanol under these fixed price contracts today than we were last year, and next year we sell a bit less again. So as those contracts drop away, we are replacing those sales with market-based priced methanol, and that has an influence on the discount rate. So that's part of the reduction, if you compare discounts today to a couple of years ago, they've come down by 4%, 5%, 6%. The second thing that's occurring is we are seeing lower discounts to customers in the market that because of the tightness of methanol supply. There is a general trend towards a declining discount, and I think that's beginning to feature in our results as well. So I think the guidance we've been offering, Adam, is around 15%, but I think it's lower than that this quarter, and I think you'll see it quite a bit lower than that in Q3 as well. I think 15% is probably not bad guidance but it is probably quite conservative as well.

Okay. So of the $30, roughly, average price increase that you have, assuming it continues into September, you should realize 85% of that?

Well, when prices go up we also have our sharing with the gas suppliers goes up as well. So some of that incremental revenue goes back to the gas supplier.

And with the change in the mix of plants, is that amount going to be increasing or decreasing?

No, it probably stays about the same doesn't it, Ian?

It's supposed to stay, although Medicine Hat, we purchased natural gas at a fixed price so we don't have a sharing on Medicine Hat production.

So that's relatively the other ones put together? Compared to New Zealand and Egypt?

Okay, thank you very much.

Okay.

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

Hey guys, thanks a lot for the strong quarter and nice call with lots of transparency. I wanted to touch on a few things here. First of all, just to clarify a few things on the Chile coal option. You had touched on the lower quality of that coal, and by my math and doing a little research, I guess it is the packet coal is one of the ones down there and probably a good surrogate for all of them. And it seems like that heat content is like 48%, or roughly half, of the heat content of typical seaborne coal like a Central App coal at 6700 k-cals per kilogram versus that's reported in the 3800 range. So I guess the overall story here is you need to be able to buy this at a discount, and the market's trying to figure out will you be able to buy this at a discount to seaborne coal to make the economics work, and you gave us a little bit of an indication there that you would? Anything that you can firm up there would be helpful. So, are my numbers about right as far as like this is much lower quality?

Your numbers, unfortunately you know more about this than I do, Chris, but your numbers are roughly right. It's around 4000 kilo-cals per tonne. So it is lower quality, and when you think about the distance from Chile to a market, which is -- Northeast Asia is the market, no one's ever going to invest in the infrastructure to transport that distance. So that coal is effectively trapped in the region, which I think is the opportunity for us to buy it at less than international prices, and at a price that provides really decent returns for the developer of the coal mine. So there's a kind nice win-win here, this is not us taking advantage of the situation. It is that we can both make decent money out of the remoteness of the resource.

And so what price do you think they're currently getting for their coal in the local market, which is, I guess, mainly power production in Chile?

I actually don't know, but the electricity that's generated in northern Chile is LNG so, an electricity generator from LNG, which I know is a lot more expensive in that part of the world. So it could be that they get a higher price because they are competing in a different market, but that's quite a small market and coal mine economics improve with scale. So that's one of the things that really interests them is increasing the scale of their mine to improve their own cost structure.

Right. Okay, Well, good. That's good clarity on that. And then a small question that's still in Chile is just tracking the amount of methanol production that you've had due to the Fell and the Dorado blocks, you've been reporting that a percentage of gas supplied from there, and if you back that out into tonnes of production. It seems that was up pretty significantly on a sequential basis. Do you see that as kind of the beginning of a good trend? Are you getting more production out of those blocks? Or is that the same ( (multiple speakers)?

For any of you that follow GeoPack, I'm sure they are talking about their production out of the Fell block and they seem extremely successful and continue to deliver very strong volumes. I think they've drilled another, I think, 12 gas wells in the last three or four months with, again, good success rate, and frankly that's probably the reason that we are continuing to be in operation today, is the success that GeoPack's had. So again it's another example that with a focused investment in an area there is gas there. There is absolutely no question that there is gas there, and those guys have been very, very good at when they make a discovery, they're very efficient at building the infrastructure around it to bring that gets into production. So I think GeoPack and the Fell blocks have been a big success story for themselves and for us as well. So another good win-win arrangement. Dorado's economy has been pretty good. We've had a little bit of disappointment in one of the areas we expected big things, but we've continuing with a drilling program in the second half of this year, and we have a number of really interesting prospects there, where we've drilled and we need to do some fracing, but we are excited about the potential. So that's probably all I can say about Dorado Riquelme.

Okay, great, and then lastly on Medicine Hat, you mentioned the de-bottlenecking opportunity in six months or more out. What sort of size increase would that be? Is it in the like 10% or 20% level of current production?

It's about 100,000 tonnes.

Great. Thanks a lot guys. Have a good day.

Okay, good. Thank you.

Thank you. The next question is from Cory Armand from Rice Voelker. Please go ahead.

Good morning. There were a couple of press articles last month that cited the Chilean government negotiated with the Argentine government to temperately import gas for the southern region of Chile if it was necessary. And I was wondering, does this involve your pipeline capacity, and has this agreement actually been used?

The short answer is no it hasn't been used. I know the discussions continue. I think I understand it is been quite a cold winter in the Southern Hemisphere in both Argentina and in Chile. And I think whenever Argentina is under any sort of pressure from gas supply, they just don't want any political fallout from being reported to be exporting gas to Chile, even though there's lots of capacity and the pipelines exist. It doesn't make any logical sense but that seems to be the circumstance. So I think as long as the current political situation remains in Argentina, we're not holding our breath for any resumption of gas supply. But longer term, there is lots and lots of natural gas in southern Argentina that has no way of getting to the north of that country and is trapped today, and frankly, everyone is a loser out of this.

The problem of Tierra del Fuego, where the gas is, doesn't get tax revenues. The owners of the gas fields have got their gas fields shut in because they can't sell the gas. The government of Argentina loses foreign exchange and tax revenues, and, of course, we don't make money and the Chilean government doesn't receive tax revenues. No one is a winner out of the current policy environment. This is all about politics and emotion, and as I say, as long as the current regime is in power, I don't think any of that is going to be resolved. But longer term, I'm actually optimistic that we will see a more sensible return to energy and politics in southern Argentina at some stage in the future, but whether that's in one year or 10 years, I have no idea.

Right. I saw those articles and I wanted to at least raise the question. In prior calls, you had implied that you may run two plants in Chile next year, in 2012, for at least part of the year, given the shortages during the summer months and may want to run stronger in the other parts of the year. Is that still the case, and how would that work seasonally?

Well, it might be the case, but I think I've been trying to hose down expectations around the capacity utilization in Chile over the last 12 months, and simply based on our experience, but I think there has been a lot of success but you sure as heck can't see it in their results. And what we need to see happening is gas starting to flow out of some of the other blocks that people have been working on. We talked about the Pan American block a few minutes ago. When development plans are finalized for that block, then I think we can realistically look forward to running two plants on a more sustained basis, but as long as we are dependent solely on the Fell block and Dorado Riquelme and whatever remaining gas is in some of the older fields, I think we will be stuck on running one plant.

Just one plant.

Yes. So a lot of our focus is on encouraging development of some of those other acres that exists in that part of the world.

Sure. Okay, thank you very much.

Okay. We're at one hour. I don't know if there's one more question, operator, I'll take that but otherwise it is probably a good time to call a halt to this.

Thank you. This concludes the question and answer session.

It is really good timing. So again, thanks very much everyone for participating in the call. We had a strategy session with our board just a couple of weeks ago, and I described our situation today as probably the best situation I've ever experienced in the methanol industry for Methanex. I think both the industry is in great shape, the demand continues to be very strong. Lots of growth in the energy applications that we've talked about, and clearly supply is quite constrained. So the pricing environment for the medium-term looks to be quite firm. I think we have an outstanding customer mix, and we're very focused on being a good supplier to all of our customers, and that's part of the reason that we really want to try and expand our production. And we have lots of opportunities to do that with taking advantage of the underutilized assets we have in Chile and reselling capacity in New Zealand, and looking for de-bottleneck opportunities and relocations. And so we are really busy looking for opportunities to increase our production. So that's good for our customers and it is good for our shareholders. So that's what has got our focus at the moment, and I hope that we have lots more positive stuff to report to you in the coming quarters. So again, thanks for your participation and good morning to all of you.

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