Methanex Corp (MEOH) 2012 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the Methanex Corporation third-quarter results conference call. As a reminder, this call is being recorded on Thursday, October 25, 2012. I would now like to turn the conference call to over Mr. Jason Chesko, Director of Investor Relations. Please go ahead, Mr. Chesko.

Good morning, ladies and gentlemen. I would like to remind our listeners that our comments and answers to your questions today may contain forward-looking information. This information by its nature is subject to risks and uncertainties that may cause the stated outcome to differ materially from the actual outcome. Certain material factors or assumptions were applied in drawing the conclusions, or making the forecasts or projections, which are included in the forward-looking information. Please refer to our latest MD&A and to our 2011 Annual Report for more information.

For clarification, any references to EBITDA, cash flow or income made in today's remarks reflect our 60% economic interest in the Egypt project. In addition, we report our adjusted EBITDA and adjusted net income to exclude the mark-to-market impact on share-based compensation, and expenses and charges related to the Louisiana project. We report our results in this way to make it a better measure of underlying operating performance, and we encourage analysts covering the Company to report the results in this manner. I would now like to turn the call over to Methanex's President and CEO, Mr. Bruce Aitken, for his comments.

Thank you, Jason, and good morning to everyone, and welcome to our third-quarter investor conference call. I've got a number of colleagues with me here in the room, and they'll be here to help answer questions a little later. We reported adjusted EBITDA of $104 million and adjusted new income of $36 million or $0.38 per share. EBITDA was slightly lower in Q2, as the average realized price in Q3 reduced by about $11 per tonne. Sales of produced methanol were up slightly over last quarter, as we benefited from higher production from our second plant in New Zealand. However, this was offset by lower production from Egypt.

While I would characterize our third-quarter results as okay, I think -- I don't think they are a good reflection of the earnings capability of the Company. We sold a little over 1 million tonnes of Methanex-produced methanol in Q3; however, today we have capacity to produce and sell 1.3 million tonnes of our own production on a quarterly basis. I think the issues impacting our current production causing this difference are short-term, and I expect we should be able to post significantly better production and earnings in the near future. And with the several initiatives we have in place to increase capacity, we've significantly more upside potential to our earnings over the next few years. I'll be commenting more on the expectations for Q4 and the industry and pricing outlook a bit later in the call, but before I do that I'll make some comments regarding our operations during the quarter.

In Trinidad, our plants operated at 86% capacity and produced 441,000 tonnes of methanol. Gas curtailments continued to impact our Trinidad operations in the third quarter, and we'd lost some production as a result of maintenance outages. For the last couple of months, two large natural gas platforms have been undergoing maintenance, and we've used this as an opportunity to take down the Atlas plant and perform some repairs. We expect the plant to restart in early November, which should equate to about 85,000 tonnes of lost production in Q4, based on our 63% equity position. As I've mentioned on previous occasions, we are engaged with key stakeholders to find a solution to the gas curtailment issue in Trinidad. We understand that the major platform repairs that commenced in September are now substantially complete, and we would expect this to lead to improved gas delivery reliability in coming quarters.

In New Zealand, the second Motunui plant started at the beginning of the quarter, and both plants operated well in Q3 and produced 346,000 tonnes of methanol. The Motunui site now has capacity to produce an annualized rate of 1.5 million tonnes, and we have initiatives in place to increase production further in New Zealand, which I'll comment on later in the call.

In Chile, we continue to operate one plant at low rates, and produced 59,000 tonnes. The short-term outlook for natural gas in Chile continues to look challenging, and I will also comment more on this in just a few moments.

The Egypt plant produced 62,000 tonnes during the quarter, based on our 60% interest. The plant was down in the first couple of weeks of Q3 to complete planned maintenance and inspection activities. During the remainder of the quarter, natural gas constraints impacted our operations, and the operations of other industrial uses in Egypt. Our observation is that ongoing uncertainty in the country has prompted many changes within key ministries, and in this environment a lack of timely decision-making has led to short-term issues in many parts of the economy, including energy infrastructure. With respect to the gas grid, maintenance issues have temporarily reduced deliverability at a time of incremental electrical demand, associated with hot summer weather. These factors have led to erratic gas supply from the grid. The Egypt plant is currently operating at about 70% capacity, and while it's difficult to provide certainty on the near-term outlook, we are expecting gas deliveries to improve. We continue to believe that gas disruptions are a short-term issue. The country has more than 70 TCF of proven reserves, and it's reserve-to-production ratio is more than 30 years.

Finally, our plant in Medicine Hat, Alberta, operated very well, producing at full capacity of 117,000 tonnes in Q3. The restart of this plant has been an excellent investment for shareholders, and we are looking -- we are working on a debottlenecking project that could increase capacity by about 20% by mid-2013.

Turning now to industry conditions, over the past quarter markets have remained relatively balanced, and the pricing environment has been quite stable. Entering Q4, demand is generally steady, with some seasonal pick-up. Energy demand in China continues to be strong, and we anticipate with colder temperatures in Q4, demand for DME should increase. In addition, a large merchant MTO plant in Ningbo on the coast of China is expected to start up by the end of November, and we expect production to be phased in over the coming quarters. This facility will require about 1.8 million tonnes of methanol annually to operate at capacity.

The impact of MTO on the methanol industry is significant. Including this upcoming plant, we estimate there is merchant MTO capacity under construction in China requiring 8 million tonnes of methanol per annum, a very significant amount relative to the size of the global methanol market of about 50 million tonnes. In addition to the merchant MTO projects, there are number of integrated coal to olefins projects in China that could also draw on merchant methanol supply.

The outlook for methanol fuel blending in China also continues to look strong. Last month, at a methanol gasoline summit in Xian, the China Association of Alcohol and Ether Clean Fuels presented on the progress of methanol fuel blending in China. They reported that China consumed about 7 million tonnes of methanol and gasoline blends last year, and they expect this to grow to 15 million tonnes by 2015. And while there about a dozen provinces in China today with provincial fuel standards in place, it was interesting to see the Association report that 26 provinces have been doing the research and development on methanol fuel, and there are currently about 160 enterprises involved in the methanol gasoline industry.

Turning to methanol supply, there have been -- continue to be a significant number of planned and unplanned outages affecting methanol supply across the industry. Markets have tightened, and in recent weeks we've seen a significant upward pressure on spot pricing, particularly in the Atlantic Basin. Yesterday, we posted our North American numbers non-discounted price for November at $482 per tonne, which is up $43 per tonne from October. Longer-term, the outlook for the industry and pricing environment looks very attractive, as demand growth is expected to significantly outpace new capacity additions over the next few years. This implies that a strong pricing environment will be needed to entice high-cost industry capacity in China and other locations to operate. The outlook matches well with our plans to increase production over the next few years.

So on this note I'll switch topics, and provide you with an update on our key initiatives to increase production, and capitalize on the favorable industry outlook. First thing in New Zealand, the recent restart of the second Motunui plant has added 650,000 tonnes of production capacity at a modest capital cost. And we have further initiatives in place to increase capacity in New Zealand by debottlenecking the Motunui site, and potentially restarting the Waitara Valley plant. These projects have the potential to add up to 900,000 tonnes more capacity by the end of next year, with a modest outlay of capital. We were a little disappointed with the progress on agreeing commercial terms on new gas contracts. We continue to observe strong availability of natural gas in the coming years, but before we make a decision on a Waitara Valley restart, we need more certainty in the form of a gas contract.

We continue to make good progress on the Louisiana project. We have about 300 contractors on the Chile site progressing the dismantling activities, and about 40 on-site in Geismar involved in early site preparation. We expect the key permits to be in place in Q4, which will allow us to proceed with our full work plan on the Geismar site. Overall, the project remains on track to be producing methanol in Geismar by the end of 2014. This project offers significant schedule savings in comparison to a similar greenfield methanol plant that we think would take up to 5 years to design, permit, construction -- construct and commission.

We continue to make progress in discussions to secure a long-term gas supply agreement for the Louisiana project, and are quite optimistic that we will conclude a sensible outcome in the next few months. However, if we are not successful in reaching agreement, we are confident that the fundamentals of the North American gas market, and our ability to hedge using financial instruments, will support a timely payback of capital and provide attractive project economics. Assuming a natural gas price of about $4/MMBtu, the plant would generate about $200 million of EBITDA per year in the current methanol price environment, and have a cash payback period of less than four years. We were also evaluating the potential to relocate a second plant from Chile to Louisiana. Our site in Geismar is large enough to accommodate multiple methanol plants, and we believe there will be significant cost savings through moving a second plant. We expect to make the decision on a second relocation in the first half of 2013. This timetable will allow us to learn from the first relocation, and move the second plant sequentially, which keeps resources mobilized and lowers costs.

Turning to Chile, as I mentioned earlier we continue to operate one plant at low rates. So the short-term outlook for natural gas continues to be quite challenging. We've been maintaining a workforce in southern Chile appropriate for a two-plant operation. However, as it is unlikely we will return to a multi-plant operation in the near-term, we reduced our workforce in Chile earlier this month but about one-third. This has a one-off cost of $5 million, which will be recorded in Q4 earnings, and on a go-forward basis will reduce our fixed costs in Chile by about $8 million per annum. This was a necessary step to keep costs down, and preserve the optionality of our Chile assets. We continue to believe that there is potential to increase natural gas supply that could underpin a multi-plant operation in Chile over the long-term. With the improvement in weather in the Southern Hemisphere, increased drilling activity has started in several blocks in the area near our plant, and we're working on initiatives to bring new technology and encourage broader participation to more quickly unlock some of the reserve potential. There are also several prospects involving unconventional reserves currently being evaluated in southern Chile, that have the potential to supply multiple TCFs of gas, and we expect to learn more about the technical and commercial viability of these prospects over the next year.

I'll change topics now, and make a few comments regarding our liquidity and capital allocation. During the quarter, we generated $103 million of cash flow from operations. We have conservative leverage; a $200 million undrawn operating facility and $403 million of cash. As mentioned on previous occasions, we have several initiatives to increase production over the next couple of years with the Louisiana project, and initiatives in New Zealand and Medicine Hat. We're in a very strong financial position, and capable of funding all of these growth projects from cash on hand, further debt capacity and cash generation. In addition, as our production and cash generation improves, we expect we can continue to increase our dividend over time, and longer-term return excess cash to shareholders through buybacks.

So before stopping for questions, I'll comment briefly on our expectations for the fourth quarter. As ever, there are lots of moving parts and assumptions that will evolve over the quarter, so it is difficult to provide precise guidance, but firstly, the pricing environment has improved, and we are currently expecting to achieve a higher price realization in Q4 compared to Q3. We expect produced sales volumes to be similar or a little higher in Q4, as the two-plant operation in New Zealand will be fully integrated into our sales. However, this will be offset by lower production in Trinidad due to the Atlas repairs, and sales from Egypt will be lower than normal due to the recent gas constraints. And as I mentioned a few moments ago, we will be taking a $5 million restructuring charge related to Chile in Q4. Taking all these facts into account, we expect improved adjusted EBITDA and improved adjusted net income in the fourth quarter. So at this point, I'm happy to stop and take any questions that you might have.

Thank you, Mr. Aitken.

(Operator Instructions)

Jacob Bout with CIBC.

Hi. A question on Trinidad, and how much capacity has been down in October? And not only your capacity but others in Trinidad, and when do you expect that to be resolved?

We don't really know, Jacob. We took the Atlas plant down because there was a -- it was apparent that the repairs to the platforms were ongoing during October, so during that period Titan has operated quite well, but not quite at capacity, but it has operated at high rates of utilization, so our site has been operating at least on half rates. We expect that the other methanol producer has also lost some production during October, and we know that the ammonia sites have been operating at less than full capacity. We think those two large platforms that were down, they are either up or they are close to being up now, so it feels like we're coming to the end of this -- quite a significant shortfall of supply. I think it represents something like 17% of total gas supply to the island was out as a result of the repairs to the two platforms that have been worked on.

And how much is Trinidad of the global methanol supply?

Heavens, I guess we've got 2.5 million tonnes, and MHTL would have, John, 4 million to 5 million? So, say, 7 million tonnes, Jacob, of 50 million tonnes, so it's the single-largest country contributing supply to the global market.

A significant portion. And your understanding, so once the work on the platforms is complete, this should rectify the situation? So this is not a pricing issue at all or --

No this isn't -- for the most part, this has been maintenance on platforms, but there is, I think I have explained before, there is something of a pricing issue that the -- there is a mismatch between the upstream supply contracts and the downstream to [loan] contracts, and whenever there is a disruption, there tends to be a shortfall of supply coming into the system. And there is no shortage of gas, this is about pricing between the upstream and the government entity that manages gas supply, and I think that is an issue that we've been working on quite diligently, and I hope we can be part of the solution to that in the coming months.

So then the tightness in this market should be relieved in the US and Europe as we get into November/December, once this gas comes back on?

Well, I think that is a broader question. I think global inventories are really short, and maybe I'll ask John to make some comments about the global market, but I wouldn't just be looking at Trinidad and saying that everything will be okay once Trinidad starts operating, but I don't know, what do you think, John?

So just to talk about Trinidad just for a sec, so we took Atlas down in October for some unplanned maintenance that we had to do to match what was happening with the upstream. So I think once the platforms are repaired, you would expect more normal operations, but even when those platforms are running we saw restrictions ongoing up to 15%. We don't think that going to change until this upstream/downstream mismatch is resolved. You know, we would think if you get back to an 85% operating rate in Trinidad, and nothing else happens globally, and the demand stays where it is today, which I would characterize as steady, you should get back to a more normal situation getting into 2013, but it's hard to predict what else might happen in the world between now and then.

Okay. And then just a quick follow-up here. When you are talking about --

This is number three or four I take it, so last one, yes?

Okay. Moving the second plant from Chile to Geismar, would you do that without a gas contract?

We prefer to have a gas contract for sure, and as I intimated we've got -- we're quite optimistic that we are going to have a gas contract. We've had very good discussions with a number of gas suppliers, and I think there is an appetite out there, so that part of the reason we feel quite positive about the opportunity to move a second plant.

Thank you very much.

Thank you.

(Operator Instructions)

Laurence Alexander with Jefferies.

Hello, this is Rob Walker on for Lawrence.

Hi there, Rob.

Hi, guys. Can you give us a better sense of what is going on in China right now, specifically kind of whether you've seen the Chinese producers increase their production much at all, given lower coal prices, and whether the sequential increase in DME you were talking about in Q4 could pressure spot prices higher? Thanks.

Certainly we observe, as most others do, the Chinese economy is flat. There's not much excitement going on there, and I think until the change of leadership occurs it's unlikely that anything much will change. I think there's lots of things going on in China. One, the impact of Iranian sanctions have impacted imports into the country, and they been up and down a little bit. They were quite low, I think, in June and July, they came back a bit in August, and I see that they are down a bit again in September. So that's been another factor that has influenced the volume of supply in China. I think lower coal prices will help Chinese coal producers. We have seen a bit of increased production. I think the rate they were at 4 -- 1.4 million tonnes per month at the moment, and a few months ago that would've been close to 1.2 million tonnes per month. So we have seen some increase in domestic supply. Most of that flows into either fuels or MTO, so it doesn't really impact the traditional markets. John, anything to add there?

Let me just add a couple points. So on the coal pricing at around RMB710, we've seen imports of coal back out, and seems to be on the cash break-even, so we've seen Australian coal back out, and we've seen US production, whether it be in West Virginia or Wyoming, shut down as well. With regard to DME, we are seeing the substitute propane and LPGs trade at a discount to their normal oil ratio, so that is putting, let's say, a ceiling on DME pricing, with the affordability of methanol. As we get into the winter months in China, there is still quite a bit, as you know, of gas production -- methanol gas production in China. That becomes under pressure, and I think about a quarter of the methanol produced in China is still from natural gas, so in the past we've seen that shut down in preference for heating and electricity. We'd expect that to happen again this fall. So there is still some new production coming on in the quarter, mainly coal-based. So all the puts and takes, we wouldn't expect the production to be much different than what Bruce mentioned at 1.4 million today.

You know, prices are edging up, import prices in China are edging up, they were over $370 in the last day or so, and they were down in the $360s not so long ago, so there is -- apparently there is some upward pressure on pricing, but certainly not to the same extent as North America or Europe.

Okay, great. Then can you talk a little bit about your expectations for production from the Egypt facility in Q4? And just maybe in general, I know it's early, but can you talk about sort of -- if you think about modeling it for a few years out, what kind of would be a reasonable utilization rate as the infrastructure in that region gets built out? Thanks.

Well, it's really hard to answer this question with any clarity, Rob. I think the guidance we offered at the Investor Day was if you put 70% in for next year, that is probably a fairly conservative number. What we've observed in the last few weeks is, I see the Prime Minister making comments around the importance of the petrochemical industry, and the importance of getting these industries operating because they were key for the growth of the economy in Egypt, so there are lots of statements being made that are very supportive of increased gas supply, and more reliability and more stability. But as I intimated in my comments, there isn't -- there's an element of uncertainty that remains in that country, and it will take a while for them to get back on their feet and find stability. In the meantime, we are -- our plant is operating, and has been quite reasonably steadily, over the last few months. And we certainly expect it to continue to do so, so around the kind of 70% to 80% level I think is a reasonable estimate, until we see I think a bit more stability coming into the gas grid system.

Great, thank you.

Hassan Ahmed with Alembic Global.

Hi there, Bruce.

Hi, Hassan.

A question -- I guess a strategy-related question. Thus far it seems that what you are trying to do is, I guess, optimize or boost production at existing facilities. Now on its Q3 call, Celanese recently talked about how they would consider looking for partners, with regards to the 1.3 million tonne Clear Lake facility that they are considering. I mean is that -- greenfield capacity adds and the like, is that something that you would consider in the near- to medium-term?

Well, I don't know. Philosophically, Hassan, I think most companies prefer to own 100% of things. Then you've got complete control, and you can exercise all the flexibility you have. It's just a better way to bring your business. With that said, sometimes joint ventures work better as well, and we have a joint venture in Egypt that we are very happy with our partners, and I think it improves alignment. A similar thing in Trinidad. BP has been outstanding partner for us, and we've really enjoyed that relationship. So there's certainly circumstances where having partners is the right thing to do, and so we are always open to the idea but I think philosophically we prefer to own everything, but we would never say no.

But I mean in line with some of your other joint ventures, it would be a majority stake if you were to consider such a thing?

Yes, I think so. That's certainly our preference. We don't have a track record of taking minority interests, and I think it would be only in a circumstance where maybe we're supporting a large off-take or something like that, then maybe we would think about taking a small minority position. But I think philosophically we prefer to have -- to own 100%, and then we run the plants and with -- to our own standards, and we [toil hours] off the safety processes. So philosophically, that's where we prefer to be, but we never say never to other opportunities.

Fair enough. Now slightly separate topic, you know, over the last week or so there was this IRS ruling that came out here in the US, which essentially talks about if you convert NGLs into petrochemicals, you could actually list yourself as an MLP. Now, clearly, I do understand that [meeting in] isn't a part of the mix right now, but as you guys consider the relocation of the Chilean facilities, is something that you've looked into maybe sort of --

Yes. No, no, certainly we're looking into it right now, Hassan, and you're right, the ruling that came out was very specific to a company and an industry, but you would think that if it was applicable to ethane it would be equally applicable to --

I would imagine so.

Yes. So it's early days. We have put some structure in place around the ownership of our assets in the United States to manage our tax position, so we need to consider what we currently have relative to the benefits of an MLP structure, and we're doing that work at the moment.

Very good. Thanks so much, Bruce.

Paul D'Amico with TD Securities.

Thanks. Bruce, so I've got two clarifications, and then I'll ask my one question. First on the Egypt operate, so I heard you say it was 70%. Can you just confirm? So it's 70% operate currently, and it's been uninterrupted at 70% since the most recent restart?

Is been operating at around 70%. I don't want to get sucked into talking about every up and down, Paul, because --

That's fine. I just wanted to know that it wasn't shut down and then -- we have an average so far of 70%?

That's about right, yes, exactly.

And you are expecting that to be the case for Q4, basically?

Yes, in the uncertain we live in, yes, there is nothing to make us think that it would be different, but who knows? It's been the price before.

And the second clarification on -- when you were talking about the Q4 outlook, you were talking about produced volume, and I missed some of it. I understand some of the pullback in the volume on the Trinidad outage, and some of the Egypt on the operating rate; did you say produced volume is expected to be similar or higher versus Q3 after netting out those differences?

They're similar. They will be similar.

Similar.

A bit more from New Zealand, and probably a bit less from Trinidad, and given that we've been operating at a low rate in Egypt in Q3, that flows into lower sales in Q4. So increase in New Zealand, kind of offset by other areas.

Okay, so similar, so no big change?

In terms of produced sales volumes. I've got that right, Jason?

Yes.

Got it, okay. My now my question is a very rudimentary one. In terms of when you talked about the production growth initiatives, or potential production growth with respect to New Zealand and Medicine Hat, so with respect to New Zealand you talked about the decision needs more certainty on the Motunui plant regarding a gas contract. So we've got 900,000 tonnes in overall kind of potential growth in New Zealand. Is there a timeline that we can expect a decision yea or nay on that, or is that just a fluid process going forward? Same thing with Medicine Hat. I'm looking for the a timeline decision on those.

Okay, well there's two primary projects in New Zealand. One is debottleneck of the Motunui plant, and we are well through our engineering of that, but we need to complete the engineering and be sure that we are -- properly understand the capital costs, and we should be in a position to make a decision on that. I guess -- I am looking at Michael Macdonald -- by soon, Michael?

In terms of wider --

No, no, sorry, in terms of Motunui, the Motunui debottleneck.

Yes, end of the year is kind of --

Yes, end of the year, and that's a project that would take about 6 months and so would be --

In coordination with the major turnaround we do --

That's right, yes. So we have got a major turnaround on the Motunui 2 plant in Q3/Q4 next year, which will be a -- it's quite a major one. There's a lot of stuff to be done in a 60-day outage. So what we'd hope to do is have the debottleneck completed probably mid-year, sometime in Q3. Our current plan, what we would like to be able to do is set up the Waitara Valley plant before we shut down Motunui 2 for the major maintenance. Based on the current position around gas contracts, we will not be able to do that. So the decision on Waitara Valley is, we need to make that decision in the next month or so, and we've been working hard on gas contracts, but as I intimated, we have not been successful in concluding those agreements yet.

So I think if you look in -- if you're looking for the guidance, you know, I would think you could either -- you could have Waitara Valley in as a sensitivity. I'm hoping we can still get some conclusion on these gas contracts, in which case it would be started up in Q3 as well. And in terms of Medicine Hat, again we are in the middle of engineering there. We have bought the equipment, so that does imply that we've got some level of confidence, and that's a mid-2013 project as well.

So, sorry, Medicine Hat would be by year-end as well?

No, mid-2013.

No, that would be completion, though, right?

The decision? Michael, Medicine Hat?

I'm expecting that by the end of this year, definitely.

Yes, so we will decide by the end of the year. But as I say, we purchased the equipment, and I think you were at the site and saw some of the site works going on, so we do need to complete the work, and we do need to be sure that this is the right thing to do, but we are proceeding as how it is.

And tied to this question then, the $160 million CapEx that would be attributable to those projects, can you give us the split?

I don't know, Michael. Do you have the numbers?

We probably had it on the last call.

I think it was $30 million-odd, so the rest is in [dollars], that's okay. Is that all right, Paul? Are you with us, Paul?

Yes, sorry, I missed that. What was that?

Yes, sorry, $30 million at Medicine Hat, so the balance must be in -- $130 million-odd in New Zealand.

But the $130 million, can you split it between the debottlenecking and the restart?

It's about half-and-half.

Half-and-half. Okay, and just getting back to the same question still, the reason I was asking about the timing --

So you're going to follow-up all of them?

No, no, it's the same -- for the timing, I'm just wondering in terms of how it gets communicated to us, is this something that you would actually now, given what had happened with respect to the Egypt operating rate disclosure, is this something that you are going to look to communicate uniformly, or is it something that we should look another way to get that information?

No, I think in the case of when we sign gas contracts, we've typically made press releases, and because I think those key important steps first, so we would -- when we sign gas contracts in New Zealand, then we will certainly notify the market, and I think that will be a good signal of where we're heading. In the case of Medicine Hat, it's probably not big enough. I think you can make the assumption that it's going ahead, and add that into your forecasts.

Got it. Okay, I appreciate it, thank you.

Okay.

(Operator Instructions)

Robert Kwan with RBC Capital Markets.

Good morning. First question here is on DME in China, and John you'd mentioned that as we head into the winter that you would expect increased demand for DME, but on the flipside you felt that some of the lower-cost propane that was coming in might put a bit of a cap on that upside. Can you just talk as we go forward here with some of the major expansions, the propane export capacity in the Gulf that are going ahead, and then some of the proposals to put more propane, or some propane I guess, off of West Coast Canada, how do you see that playing into the overall pricing of DME, and what impact could you potentially see on methanol prices in China?

Well currently, the market in China is split into a southern market and an eastern market. The southern market tends to trade at a higher price, about $20 to $30 higher, because there's not as much refining capacity down there, so it's mainly imported. Today's price affordability for DME in the east market, China east, is around $370, and $20 higher in the south. I mentioned we are seeing this disconnect on liquids and propane, et cetera, from oil, from its historical ratios. I would agree with you, there is quite a bit of new production coming on from LPGs. I'm not an expert enough to know the outlook for LPGs versus oil, and that ratio, but you would expect as more liquids are produced that ratio would be under pressure, but I'm not, like I said, expert enough to have an outlook for 3 or 4 years. What I would say is that today there is about 3.1 million tonnes of methanol going into DME in China mainly for this propane substitution process, so I would say unless we saw something really different on oil/propane that's kind of like a price ceiling, what we might see happen is that as MTO comes on and there is not enough methanol production to satisfy the MTO demand, that our current look at MTO, it looks like it can afford to pay more for methanol than DME. So as this MTO comes on, you could see a situation where DME is forced to shut down because they can't afford to pay as much for methanol as MTO. Early days, we're watching it very closely, but maybe in the coming quarters we will be able to report a little bit more on actually what's happening.

That's great color. And just -- the other question I had was on Geismar, and I know you've been looking to try to get a long-term contract, and directionally what you said is if you were unable to get a long-term gas supply contract, that you wouldn't be particularly interested in relocating a second unit out of Chile, and taking on that spot price risk. If you were able to get that long-term contract, would you then be comfortable bringing a second unit up and maybe not having long-term supply there, or do you just feel that that's going to be too much methanol supply?

No, I think from -- having too much methanol capacity tied to a spot price that moves every day feels a bit risky to me. So that's why we would like to have one contract. That allows us to commit to move a second plant, and then maybe would get a second contract. So we're in a long-term business with these assets, they last for decades, and you prefer to have [feed-stock] certainties that underpins the long-term operation of the assets. So I think philosophically again, you prefer to have contracts supporting all of your assets. But the point we make is when we look at the demand/supply balances for natural gas in North America, we think even if we can't get the contracts, we can get our capital back and make a decent return on the first plant. But the absence of a contract probably would defer our decision on a second plant.

I guess, just to make sure, Bruce, so you are indifferent as to whether it's the first unit or the second unit that's underpinned by a long-term gas supply contract? Obviously, preferably you'd like to have both, but you're okay having two plants producing in North America under one contract?

That's right. Yes.

Perfect, thank you.

Ben Isaacson with Scotiabank.

Great, thank you. Just two very quick questions on Trinidad. I don't want to flog a dead horse, but your conversation with BP regarding their stake in Atlas, is that really still at a bit of a standstill?

That horse is dead, Ben.

(Laughter)

Okay, that's good to know.

I don't think we've had any conversations in 6 or 8 months in -- maybe a year, so it's a long time. So we've withdrawn from any interest in it.

Okay, that's helpful. And then my second question is when you take Atlas down, does that mean that you can divert more gas to Titan, and therefore run it at 100% or greater than 100% for that time that Atlas is down, or does it not work that way?

No, they are separate gas contracts, and we have separate -- we have different gas suppliers underpinning our contracts. So no, there is not really too much that is able to flow between the two plants. But when Atlas is down, clearly there is a bit more gas supply available, so I think -- indirectly, Titan probably is able to operate at a higher rate over the last month as a result of the maintenance we've done on Atlas.

Okay, and then just lastly, you've talked about being engaged with key stakeholders in Trinidad. Can you just kind of talk about what some of the longer-term solutions are or may be, other than once these temporary platform problems are fixed? Is there talk about storage or obviously increasing the price to the gas producers, et cetera?

I think the fundamental issue is that the government company that manages gas supply in the country captures a lot of the upside in gas pricing, so the upstream is not seen as sort of gas prices that we're paying. And I think therefore the incentive to continue exploring and the incentive to continue providing incremental supply is simply not there. So what the solution that's been cried out for is to correct this mismatch between the upstream and the downstream, and it's totally in the hands of the government, and it requires them to have a rethink about how gas is priced and how it flows. And I think there is a realization of what the issue is, and people are working on finding sensible solutions.

Okay, thanks Bruce.

Okay.

Gregg Hillman with First Wilshire Securities.

Hi. I had a kind of question about longer-term strategy, basically whether it makes sense for the Company to get involved in fertilizer production, and particularly ammonia? I was wondering whether, when you are going to -- are thinking about transferring that second plant in Chile to Louisiana, whether it would make more sense and better economics to take that money and build an ammonia plant maybe that could also make urea, because so much capacity in ammonia has been taken out of the United States since 2007?

Yes, I don't think so Gregg. We've thought about this on many occasions. We used to make ammonia, actually, up in our plant in Kitamat, and perhaps sadly we sold out of that in the bad old days when ammonia prices were awful. But I think over the years, we've looked at numerous occasions at should we add to our product portfolio, and every time we've looked at it, we think that there's lots of things that we can continue to do in methanol. It's an industry we know very well, and we can continue to find ways of improving our positioning in it, and just maintaining our focus, and I think that is certainly the position our Board supports, and I think it's the right answer for us as well. So really no interest in diversification.

Okay, thank you.

Arash Yazdani with Raymond James.

Hi guys, it's Arash here for Steve. Just wondering if you can give us any color or any additional color on the Geismar gas contract negotiations? How many parties are you negotiating with, and are you -- have you found that interest has grown from the gas suppliers regarding a contract or has it declined? And finally, do you still think it will be a sliding scale if you do secure a contract?

So we've had conversations, I don't know, with 4 or 5 different parties, and the parties that we've made most progress with we talked about methanol price sharing, so the same sort of arrangement that we have in most of our plants. And I think that's -- we've found a receptive audience amongst the gas industry. We talk about the relationship between methanol prices and the price of oil, so if you want the price of gas to go up and down with oil prices, the best way to do that is to link the price of natural gas to methanol, and I think that is an argument that has a receptive audience amongst a number of gas suppliers. So we're very close with one party, but we have several other conversations going on.

So it is -- in North America is not really signed -- no-one in North American have signed long-term gas contracts for 20 or 30 years, so a long, long time. And this market's developed with lots of financial instruments, but it's hard to justify spending billions of dollars underpinned by short-term financial instruments. So I think we are at the cutting edge of the development of longer-term contracts in this continent, and is a necessary step to get the sort of investments that can increase demand for natural gas, and I think there's a section of the gas supply industry that appreciates that.

Great. Thanks guys.

(Operator Instructions)

Bert Powell with BMO Capital Markets.

Thanks, Bruce. Apologize if I missed this, but what is the expected utilization out of the Trinidadian facilities in the event that there is no sensible resolution to some of the issues between the upstream and downstream that you talked about?

Well, I saw the Minister commenting just a month ago or the beginning of October, saying that the shortfall of gas onto the island in the first 6 months of the year has been about 5%, and that doesn't fall equally on all consumers. The electricity generation, for example, gets 100%, and I think LNG gets a bit of preferential treatment as well. So our experience has been around 90%, and I think that's -- somewhere between 90% and 95% is probably what we would expect. It's a very hard question to answer, because if all of the facilities are operating, then there is no -- this mismatch I've talked about doesn't exist. And I think the reason that the facilities haven't been operating, and particularly BP have been going through an extensive maintenance and repair process over the last couple of years, and some of that will continue into 2013 as well. So I think when everything is operating, we will get 100% of our gas. When there are outages for repairs, planned or unplanned, then we will probably -- our experience has been around 90% of our gas.

Okay. And lastly, on Waitara, has your confidence in terms of getting a -- I think you said to do that, you want to have a firm contract. Has your confidence, or have the dynamics, in that market changed, you know, in terms of your thinking on your ability to restart Waitara?

No, not really. I'm just frustrated -- I'm frustrated at how long it takes to reach what I think are sensible conclusions. So, you know, like most things, the gas suppliers want to get as much they can for their gas, and we want to pay what we think is a sensible and fair price for gas, and sometimes it takes a while to agree on what that number is. So this is taking a bit longer than we anticipated.

Okay, so I shouldn't infer from your commentary that the dynamics are any worse then?

No, this is all about negotiation and closing a deal.

Okay, perfect, thanks Bruce.

Winfried Fruehauf with W. Fruehauf Consulting.

Thank you, and good morning. Regarding the gas supply contract or contracts you're hoping to negotiate for Geismar, are you hoping to sign a contract with a single supplier or multiple suppliers?

At the moment, it looks like a single supplier and it's a 10-year contract.

And could you please explain why and how you will be able to compete with LNG exporters from the United States to the Far East, in terms of price?

Well, I think the imminence of demand -- we are starting up our plant in the beginning of -- well, the end of 2014. So by the time someone's permitted and built an LNG export facility, you know, that's going to be, I don't know, 2018, 2019, you tell me. It's a long time in the future. So I think the attractiveness of our offering is that we can begin to consume gas in the relatively near-term.

Yes, but the LNG exporters require longer-term contracts, too, and if they preempt Methanex, how can you expect to be able to get a competitive price for natural gas?

Most of those LNG exporters, Winfried, own the gas themselves, so this is about trying to maximize the value of the molecules they own personally. So we are talking to people who are domestic producers of natural gas in North America, and want to find domestic demand for natural gas, and I think as I say, they're attracted by the imminence of our -- of the start-up of our plants.

I have a follow-up question, if I may. What air emission standards does the Geismar plant have to be -- have to comply with, and are you confident that you will be able to do so?

Well, I think we are in an attainment area, so that's better than being in a non-attainment area, so it reduces the standard. We have invested in NOx abatement on our plant, and that was an advice we had at an early stage that if we invested in NOx abatement, that would make the permitting process easier. I would say we are right at the end of permitting, we have just been through public consultations in the last couple of days. We are not aware of any -- there's been no negative commentary from -- outside of that consultation, so we're expecting the permits to be issued just in due course, and I don't think there's any issues for us with regard to that.

Is there a -- potentially a Co2 issue?

No, that is not something that is an issue for us.

Okay, thanks very much.

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

That's great. It was a good time, I was just about to call an end, anyhow, so thanks very much for that, and thanks to everyone for participating on the call. So, as I'm sure you've all read by now, that it's my intention to retire at the end of this year. I was just commenting to my colleagues earlier, I think this is conference call number 38, so that feels like enough. It feels like a lot of conference calls. You know, I know there's a lot things I'm going to miss about my job and about the day-to-day contact that I have with employees and with customers, and with shareholders, but I continue to be extremely excited about the future of the Company. I'm really pleased that I've been invited to hang around as a member of the Board, and I hope to make a -- be able to make a contribution and really support John into the future. And I'll certainly hang around as a major shareholder as well, so I continue to have a significant personal interest in the future prosperity of our Company.

I know I've said on a number of occasions, and I reiterate it again today, it's hard to think of a time in the past that has been as positive as we are at the moment, where the industry looks in great shape, where demand continues to grow strongly, and there's limited new supply additions over the next few years. In that environment, we have lots of great growth opportunities. So I think we're sitting in a really, really nice position. I think the Company is in great hands, and we have a very good succession process. I'm sure that John's going to be just an exceptional CEO. He has had 25 years experience in the chemical industry, and lots of knowledge of the global methanol industry. And internally, the transition so far has been completely seamless, and that's exactly what we expect on a go-forward basis as well. So I'm confident that with John's capabilities and passion, and the dedication to Methanex, that the Company is headed for great success, and all of us shareholders are going to be well-rewarded in the future.

So just in closing, I'd like to thank you all for your support over the years, and over the recent quarter, and say good morning to all of you. Thank you very much.

Thank you. The conference call has now ended. Please disconnect your lines at this time. Thank you for your participation.