Good day, ladies and gentlemen. Thank you for standing by. Welcome to the Methanex Corporation Q1 2016 Earnings Call. I would now like to turn the conference call over to Ms. Sandra Daycock, Director of Investor Relations. Please go ahead, Ms. Daycock.

Thank you. Good morning, ladies and gentlemen. Welcome to our first quarter 2016 results conference call. Our 2016 first-quarter report, along with presentation slides summarizing the Q1 results can be accessed in the Events tab of the Investor Relations page on our website at www.methanex.com. I would like to remind our listeners that our comments and answers to your questions today may contain forward-looking information. This information by its nature is subject to risks and uncertainties that may cause the stated outcome to differ materially from the actual outcome. Certain material factors or assumptions were applied in drawing the conclusions or making the forecast or projections, which are included in the forward-looking information. Please refer to our latest MD&A and to our 2015 annual report for more information. I would also like to caution our listeners that any projections provided today regarding Methanex's future financial performance are effective as of today's date. It is our policy not to comment on or update this guidance between quarters. For clarification, any references to revenue, EBITDA, cash flow, or income made in today's remarks, reflect our 63.1% economic interest in the Atlas facility and our 50% economic interest in the Egypt facility. In addition, we report our adjusted EBITDA and adjusted net income to exclude the mark-to-market impact on share-based compensation and the impact of certain items associated with specific identified events. We report our results in this way to make them a better measure of underlying operating performance, and we encourage analysts covering the Company to report their estimates in this manner. I am pleased to report to you that commencing in Q2 2016, we will be changing the format of our quarterly results press release. The press release that you receive by Newswire will be in a summary format that includes the key financial, operational, and industry highlights for the quarter. The release will include a link to our website where we will simultaneously post our full Management's Discussion and Analysis and financial statements. By focusing the reader on the main issues of importance for the quarter, we are striving to improve our communication with the investment community. We are also optimistic that the change in process will allow for a more timely dissemination of the results. I would like to now turn the call over to Methanex's President and CEO, Mr. John Floren, for his comments and a question-and-answer period.

Thank you, Sandra. Good morning, everybody. The first quarter of 2016 was a challenging quarter for the methanol industry, and we continue to experience a tough environment in the second quarter. Despite the current situation, I'm encouraged by some positive industry and Company trends, which I'll discuss today. Q1 2016, we recorded adjusted EBITDA of $36 million, and an adjusted net loss of $24 million, or $0.27 per share loss on a diluted basis. This compares to adjusted EBITDA of $80 million and adjusted net income of $15 million dollars, or $0.16 cents per share, in Q4 2015. The lower EBITDA in Q1 is primarily the result of lower average realized price, which decreased from $277 per tonne in Q3 to $230 per tonne in Q1. Methanol prices now seem to have stabilized and spot prices in Europe and North America have rebounded as anticipated. Spot pricing in China has also risen, and today is in the range of $230 to $235 per tonne. We estimate the current cost curve to be in a similar range. We posted our April Asia contract price at $265 per tonne, up $10 a tonne from the previous month, and we rolled our North American price at $249 per tonne. We recently announced our Asia contract price for May would remain at the same level. We set our European contract price on a quarterly basis, and our Q2 contract price is EUR225 per tonne, which is down EUR50 per tonne from Q1, now in line with the Asia and North American prices. Improving oil and olefin prices have contributed to higher affordability for methanol into methanol to olefins or MTO, and into other energy application, which has led to somewhat higher operating rates for MTO operations in the second quarter. The first quarter was…

[Operator Instructions] Our first question is from Cherilyn Radbourne from TD Securities. Please go ahead.

Thanks very much, and good morning. I wonder if you could start by commenting on whether traditional demand for methanol in China has strengthened seasonally as expected, and what insight that gives you about the health of the Chinese economy.

Yes, we usually experience a little bit of a downturn in Q1 on traditional demand. We have seen a rebound in Q2. And we see the Chinese economy doing okay, certainly not like it was some years ago, but we characterize it as okay.

Okay. And then, can you give your view on olefin pricing in China? And I guess what I'm driving at there is that there are some who have suggested that their recent increases are associated with cracker turnarounds and, therefore, may not be sustainable as those plants come back online.

We're certainly not experts in olefin industry. But we've observed the increases, and I think those increases were predicted because of increased demand in some turnarounds. But for me to predict the future on methanol pricing is hard enough, never mind olefin pricing.

Okay. Very good. That's my two. Thank you.

Thank you. The following question is from Daniel Jester from Citi. Please go ahead.

Hi, good morning. Maybe just on the comments you made about trade flows in the first quarter being impacted by the startup of some new capacity in the Atlantic basin. In your sense, have trade flows fully adjusted or is there still a period that we should expect in the second quarter, maybe into the third quarter, in which trade flows are still adjusting to this new capacity?

Well, based on our observation, it took a few more months than we were anticipating for these flows to adjust. But through the quarter, we saw a significant amount of product from the Gulf Coast we exported to Asia, mainly China. And then we saw product from Trinidad, as well as Venezuela finding its way to China. So we believe the trade flows have adjusted and we're in a more balanced environment. And I think the spot market kind of reflects that as well. We've seen spot markets in both Europe and North America rocket recently on the 220 to 230 range. So it appears - and again I'll reemphasize, there's very little liquidity in this market, so it doesn't take somebody needing a few barges to really impact the market on the way up, and somebody wanting to sell a few barges impacting the market on the way down. So we anticipated this in the spot market, and that seems to be what's happened. And our view is that trade flows have adjusted.

Okay. And then two quick ones on your operations, if I can. First, on Geismar, can you comment on the relative performance of the two plants in the quarter? I know last year when Geismar 1 started up, it was able to run above nameplate capacity for a couple quarters due to the catalyst. So did G2 kind of had the same performance? And then on Egypt, you called out the pipeline and sabotage issue. Do you have any insurance to cover that?

Yes. On Geismar, we're extremely pleased with both those plants and how they've operated and how they came up so seamlessly. We're riding them just around 3,000 tonnes a day. I mean, the G2 startup went seamlessly, few small needling issues, but really nothing that really gives us any concern at all. So you're right. I mean, we're still gauging the catalyst life, and we do expect the catalyst to go down somewhat over time. But we're pretty happy with how both those operations are running. And just probably under 3,000 tonnes a day is a good measure. But I'll remind you, when we budget, we use about 350 days a year, not 365, to allow for some unplanned downtime. So again, just homerun projects and really happy with our safety performance and how those plants are operating. Yes, we don't insure as normal course pipelines of our suppliers. So, no, we didn't have insurance on that pipelines.

Okay. Thanks, John.

[Operator Instructions] Our following question is from John Roberts from UBS Securities. Please go ahead.

Thanks for taking my question here. There always seems to be this uncertainty on the MTO operating rates for existing plants and the ramp of the new plants, the consultants have estimates, the olefin guys get asked to comment. Do you think your position in methanol gives you a better view into what's going on with those facilities or do you think there's just as much uncertainty in your look as what we get from others?

Well, in our historical view, suppliers to customers have a much better view than competitors to competitors. I think that's how I would characterize it. We're supplying a couple of these plants. We have excellent relationships with them, and we really are getting good at understanding their economics, not only including the ethylene and propylene, but all the other products they make. So I think we have a special window into some of those operations that others wouldn't have. And I'll remind you this is all pretty new for the industry, so people are speculating. People are guessing at what the operating rates might be, what the economics might be. And I think it'll take some time for all this to work itself out.

That's very helpful. And then among the traditional methanol applications, are you seeing any significant diverging trends between any of the applications in - terms of demand trends?

Really I mean, MTBE in China continues to be quite attractive. It's great octane and clean-burning fuel. And we all know that China has an issue that they're trying to help with clean up the air. So MTBE continues to grow in China. And, but the other derivatives that, as I've mentioned many times, really track GDP and IP growth. So whatever numbers you're using, 2%, 3%, that's how you should expect those derivatives to grow. So really, that's what we plan and that's what we see.

Great. Thank you.

Thank you. The following question is from Jacob Bout from CIBC. Please go ahead.

Good afternoon. I had a question on the Chilean gas supplies. You talked about the U.S. Geological Survey talking about 8.3 tcf. What is your sense as far as how much is accessible by traditional gas drilling versus fracking? And what do you think the cost would be to extract that gas?

Yes. Jacob, it's all tight gas, so none of it is conventional. I was down there in December. And what's happening in the basin is quite different than what was happening a couple years ago. You've got Weatherford in the basin now with very sophisticated hydraulic fracturing equipment like we would see in the U.S. and Canada, upwards 50, 60, 70 trucks onsite with water and sand and fluids, et cetera. So, yes, the cost will be the issue on that gas. And that's what we've been saying for some months now. I think when they started the cost was $8 to $10. And I think they've got it down just north of $5, and they believe they can get it to $3 to $4. And I'd say their accessing technology in the U.S. that has taken years to develop and proven, and time will tell. But they certainly are making solid progress. The reserves are there. Can we get at them in an economic way? That's to be found out here in the next months. But we're pretty optimistic that things are headed in the right direction.

Okay. Thanks for that. And then my second question here is just on the verbiage in the MD&A talking about events that led to restrictions on shareholder distributions for the Egypt entity. So what conditions were not met? And when will the cash payments be made?

Yes. We really don't want to disclose that at this time. But there are certain covenants within the agreement that we have to meet. And some of them weren't met, so there is a restriction on cash distributions at this time.

Thank you. The following question is from Joel Jackson from BMO Capital Markets. Please go ahead.

Hi, good morning, John. So you chose not to raise the dividend in this report for the first time in I think six years. I think you chose not to do any share buybacks in the quarter for the first time in two years. So you seem to have a conservative tone. Can you maybe give a bit of color here what you're thinking on capital return and what signposts or what things you need to see to get back to maybe a dividend increase or some share repurchases, just so we can get a sense of that?

Yes. So I think we went through a pretty volatile period where the bottom wasn't clear. We do believe in cost curves and the cost curve did again work this time, and we do believe we hit the bottom and we'll start to move up. At what speed? Who knows? Yes, we have around, I mentioned, $250 million of cash, some of it, like we just mentioned, is restricted in Egypt. And we need 100-plus to run the business. So there is a little bit of excess cash. But we'd like to continue to be a little prudent. We want to maintain and protect the dividend. We want to keep a little bit of cash for unforeseen things that might occur. But every $10 increase in the methanol price now on an annualized basis adds $50 million in EBITDA. So you don't have to see too much of an increase in methanol pricing for us to start generating additional EBITDA and cash. And I'll remind you we have very little needs for maintenance or growth capital at this time. So again, we look at our dividend usually once a year around the AGM, which is today, and we make a call. So you're right to point out that we didn't increase it. But we didn't cut it either. So I think that's a very positive sign. And I think that the relative share price, based on our replacement cost, it's still very prudent for us to buy back shares, and we'll continue to do so as we believe we have excess cash in order to do so.

Okay. Thanks for that. And my second question is on North America and the May contract price. So Southern Chemical, I think this morning or overnight, released their price at $249 a tonne. They came up $32 a tonne from April. They came up to your level. Can you give us a sense if we should expect a similar order of magnitude increase in the May contract price that you'll set? Or would we expect less?

Yes, I don't really want to speculate on what we're going to do before we announce to the entire world, which we do on our website. So I think that would be the wrong thing to do. I think I mentioned earlier that when you get these dislocations between boasted prices, it affects our discounts, because there's competitive factors in the marketplaces. And we're thinking long term. We want to be a long-term viable supplier to our great customers who have supported us over the years. So there are times when we have to do things to support them, and that's what we've done. So if Southern has come up, which we understand, $33 a tonne, which is pretty close to where we're at, if not bang on, then if we roll or we increase modestly, then you would expect our discounts to be impacted inaudible positive nature. But until we actually announce, I wouldn't want to speculate on what we're going to do.

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

Good morning, guys. John, just a quick question on the inventory build in the period. It was certainly larger than we've seen over the past four or five years. Just trying to get some better color on that and how we should think about sort of the similar cadence going forward here for the balance of the year.

Yes. So we've grown our sales. When you grow your sales, you're going to grow your inventory. Some of our shipping channels are a little longer. We're shipping product from the Atlantic basin in the Pacific like others. So it's an extra 20 days on a ship. But the biggest change is what I've been signaling for years now is, as we add our own productive capacity, which is three million tonnes in three years, we will be buying a lot less spot product. So the change-out in the inventory's really spot product for produced product. And that's kind of a one-time adjustment, as our inventories will stay around $900,000 to $1 million. As we get that ratio of spot to production more on the 80/20, which is our kind of guideline, then you would expect the flow-through and the accounting basis to be around that. And there will be times quarter to quarter where a ship scheduled to go on the 29th of March might go into early April, and that does impact things. But I think we are adjusting our inventory from the amount of purchase product to the amount of produced product. So that was really evident in Q1.

Okay. That's helpful. And just a second question, if I may, on the Chilean opportunity. So the way I sort of view it is there seems to be sort of a shorter or nearer-term opportunity with the ENAP having better progress on its drilling success here. Solid progress, I think you describe in the release. And then there's this longer term bigger opportunity which is bigger dollars, bigger development, timelines, et cetera. I'm just trying to get a sense for what the near-term expectations are for your sort of internal workings or your budgeting for Chile. And we've had a nice bump in the quarter, be it off a small base. But if we're thinking about next year and beyond, should we expect modest bumps at this point in Chile or should we just decide to right now to leave it flat until we see the progress?

I'm conservative, so I'd leave it flat until I see the progress. But you would see the amount we produced in Q1 would have been higher. But on order of magnitude, this is rounding errors. But I'm very optimistic about what I see happening in the basin. And also, on the Argentinean side, there's a lot of interesting things happening as well. So I think in Chile, as Jacob pointed out, it's going to come down to economics. We're optimistic and ENAP's optimistic they can get those economics down in that $3 to $4 range. I think there's others that are interested in the basin see the same thing. So I think there's a lot more to play out here in Chile. And modest capital, we can get a much higher operating rate. Modest capital, we can get a second plant running. But like I said before, I think it takes about 18 months when we make the decision to get the second plant up and running. We can certainly run the first plant at higher rates if we get gas. So I think if I was modeling it over the next few years, you'd do it on a slow ramp-up basis. Having said that, I wouldn't have thought sitting here three, four months ago, we'd be able to run very much at all during their winter. And there looks to be enough gas supply in order to do so. It just depends on the economics, which is what we're in discussions with now. So the current methanol price is limiting our ability to pay a lot more for gas. We're not going to, obviously, just run the plant and lose a lot of cash. So it needs to make sense from an economic perspective. And we're optimistic we can get there and run at parts of the Chilean winter, which is, to me, a huge milestone. And I'll reiterate what we said in the release, that the plant has run 100% on Chile gas, which is the first time in a long time. So early days, cautiously optimistic about the economics. The reserves are there. ENAP continues to spend hundreds of millions of dollars developing those reserves. And very modest capital to get higher operating rates. So it's certainly something we're going to pursue in an aggressive way.

[Operator Instructions] Our next question is from Hassan Ahmed from Alembic Global. Please go ahead.

Good morning, John. John wanted to revisit some of the comments made earlier about traditional methanol demand, in particular, the asset yield side of things. Q1 in particular, we've had Lyondell report earnings. We've had Seronese report earnings. Obviously two big players within the asset yield chain and the volume numbers that they disclosed in Q1 were materially higher than 2%, 3%. So the first part of the question is, did you not see similar sort of methanol volume growth from that end market? And if you didn't, what do you attribute that to? Do you think that it was these guys sort of growing down inventory? And maybe you could sort of also give us some color around the inventory side of things as it relates to customers.

To get specific on derivative by derivative, we saw modest growth. But we didn't see it flow through to us like you're talking about those numbers. So there are inventory adjustments that happen all the time. What I would say, based on our experience, when prices are going down, customers tend to limit their inventories to the extent they can because they think the next quarter is going to be cheaper than the last one they bought. And that's just normal behavior of any buyer in a commodity or other industrial environment. As prices start to go up, I think you'll see demand and inventories be replenished. So it's hard for us at the top of the chain to understand the 100% of the movements on the inventory through the chain. But in general, we would say in a price environment that's dropping, the chain does get destocked somewhat. And in a rising price environment, we see a little bit of it restocking.

Fair enough.

Nothing more than that for me to give you color on.

Fair enough. And now changing gears a bit, as I look at sort of in talking to a variety of investors and the like, there seem to be highly divergent views for the near to medium term in terms of natural gas pricing. So how are you guys thinking about, be it a longer-term contract or not as it pertains to G2?

Yes. So we're happy with where we're at on G2. What we've done is hedged 40% of our position, which allows us to run G1 and G2 at 70% rates, if we do get a blowout on gas. I think there's lots of debate about pricing on commodities, and nobody knows at the end of the day. So that's what makes markets, different views.

And you're hedged out until what - what sort of duration are we?

Yes. So I think the current environment looks to be unsustainable at the prices that we see based on the relative economics to develop a new gas and even complete existing gas, and there's more demand coming on. So, I mean, we just looked at the North American market over the next 5 to 10 years. We have a number of around $4 in our mind. But it'll probably be very volatile throughout that period. But we believe the current low price environment is unsustainable in the United States. Certainly, western Canada's a different market altogether with what's happened with the gas being backed up into Canada. And we've look to and we are looking to cover additional hedges for our Medicine Hat facility at current forward curve prices. If we had a supplier that wanted to do a long-term contract with us at terms that are similar to some of our other contracts, we'd entertain that. But we're certain satisfied with our current gas position in Geismar.

Perfect. Thanks so much, John.

Thank you. The following question is from Laurence Alexander from Jefferies. Please go ahead.

Good morning or good afternoon. Can you give a bit of perspective on sort of the degree to which you think [indiscernible] projects are being either delayed or permanently taken off the nets of what's going to be added over the next few years? And secondly, can we talk a little bit about how far out you think we'll be before the newer sources of demand, either marine blending or bio-based or biogas DME would be relevant for the methanol market?

Yes. So first on the supply, I think you would have seen a lot of projects canceled. I've said many times to get a double-digit return on an investment based on the last few projects we've seen, they'll be between - around $1,100 a tonne in capital, you know you need to see gas prices in the $3 or $4 range and methanol price at $400-plus. So if these projects didn't get financed when methanol prices were $400-plus, I don't know how they get financed in an environment where we're experiencing $225, $230, $250 methanol. So we would expect the OCI plant to complete. They've spent a lot of capital. They've recently got a new partner into the operation. So we would expect that one to complete. Beyond that, in the United States, in our planning horizon, we wouldn't expect anything to be completed at this time. Doesn't mean some won't FID and maybe start over the coming 12 to 18 months. But we're certainly looking at a 40-month construction period. So I think there's going to be a long-time before we see additional production in the United States post the OCI plant. They're continuing to say third quarter 2017. What we would say is we'll see. We'll see how that moves forward. Outside of China, we'll probably see a little bit come on in Iran. But beyond that, really nothing, nothing else. So we still see this dynamic of demand outstripping supply, which we believe will lead to higher cost methanol having to run or some substitution based on affordability. That's still our view. As far as these other applications, I think that we're starting here at the infancy stages of marine fuels, but three years ago we didn't even talk about it. Stano was the first. And we…

Thank you.

Thank you. The following is from Robert Kwan from RBC Capital Markets. Please go ahead.

Good morning. John, if I can ask about Medicine Hat and, certainly, kind of current pricing isn't really supportive of this. But you've got the Alberta government out talking about support for value-added processing. I'm just wondering if you have any updated thoughts on that, kind of pursuing that and talking to the government around that. And maybe frame that including the comments you made earlier on the ability to finance things with the current methanol prices.

Well, we think the Alberta government's doing exactly the right thing, investing in, trying to transform their gas into other products in the province, creating jobs and economic activity. So we applaud the Alberta government for being creative in what they're doing. We've made an application for some money for Medicine Hat second plant, application just recently gone in. We'll here, I guess in some months. But when we look at the economics, by them giving a royalty grant payment is actually good business because it's a positive generator for the province. So our view is I think they've allocated $500 million, but if they get great projects that make sense, they'll probably continue to allocate funds to that kind of program. So we're really encouraged by what they're doing. But there's other factors there that we still have to overcome, including rail and capital cost, mainly labor. So we have a team working on that. Certainly with a lower Canadian dollar and the stranded gas in western Canada, makes us a lot more optimistic than, let's say 12 months ago. But I'll remind you, the modeling we're doing on that project is for 100% of the product to leave North America. So that means railing it to the coast and putting it on ships, which has a bit of a penalty to the project. But if you have a lower gas price, you get some royalty credits and you can get the economics to work on the construction labeler and capital cost, it could look very, very interesting because we have a brownfield site. We've got a team there. We've got land. We've got water. We've got a very supportive government in the city of Medicine Hat, so a lot of really positive things. Having said that, in the current environment where we're realizing $230 methanol, it's really hard to be ponying up to spend a billion-plus dollars on a project. But we'll continue to pursue that project because we again have a long-term view here on methanol and methanol pricing. And I think that's an ideal project to have a partner. And we'll continue to pursue those discussions as well. So I think that the announcement and our application is just another positive step towards us having additional production in a great part of the world in Alberta, where we've been operating for years and really like doing business in that province.

That's great. If I can just finish with your comments on maintenance CapEx. I think you mentioned earlier $30 million for the rest of the year. So when you combine that with Q1, that seems a bit lower than some of the directional kind of annual guidance you've given. How to think about it going forward? Is there something specific to this year or is it just kind of, look, it's a tough year and you're just trying to kind of rationalize and maybe push back a bit of maintenance?

Yes, I think I mentioned on the last call - look at the transcript - that our average maintenance cap with eight million tonnes of capacity would be about $80 million, $10 million a year per a million tonnes of operating. We took a scrub at that last fall when we saw things falling on the methanol side. And I think on a one-time basis, we trim that by $30 million. I think that's not sustainable going forward. I wouldn't start modeling that. I think $80 million's still the right number. There are a few things that we can delay. But we need to invest in these plants again. We're looking long term. We need to make sure they're maintained and they're robust. And we spent a lot of money not only in new plants and relocating plants, but in making our existing plants a lot more reliable and robust. And I think you've seen some of that benefit in Q1 with our reliability of 98%. So our team things we can get away with $30 million less on a one-year basis, but I certainly wouldn't model that going forward. I'd stick to that $80 million on average.

Great. That's great. Thank you very much.

Thank you. The following question is from Charles Neivert from Cowen. Please go ahead.

Just two quick ones. One, changes obviously have occurred in Argentina recently, and they used to be the big provider of gas for the Chilean. Is there any chance that Argentina might start shipping in gas at some point considering some of the changes there? And then, as a follow-up, obviously purchase numbers came way down. Is that a number we should start sort of thinking about in that 400,000 to maybe 450,000 tonne range, considering your production capabilities now?

Okay. First on Argentina, there's been a change in government, which the government seems to be very friendly to mending some of the international issues, including bond payments, et cetera. So very positive signs. Also very positive signs in drilling in the Makavorte. Early days, so again, we're seeing the same things you're seeing. But maybe by the time they get around to actually wanting to export gas again, we'll be full. So nice problem to have, but we certainly don't have anything more to say. We were getting some tolled Argentina gas in the past. We haven't been getting it recently. But certainly if it became available again on a toll basis to run the plant at higher rates, we'd welcome it. So lots to plan in Argentina. I don't think I'd be counting on anything in the short term, but certainly the EIA says there's 800 tcf of gas in that basin. And if they ever can develop that at reasonable economics, that certainly would be favorable to our plant. But early days and hard to predict. The second question, Charlie?

Yes. Going forward, obviously there's been a huge decline in the purchase product, which is sort of in the plan with all the new production. But is that a number we should sort of stick with around going forward in that 400,000 to maybe 450,000 range, given what you contractually need in all the rest?

Yes. What I said guidance-wise, which is still applicable, we'd like on our sales about 80% of what we sell to be produced product. And the 20% left will be made up of long-term off-takes and spot, and maybe a few percent either way on any given period. But you won't see us in that 35% to 40% of what we sell being purchased. So we've added three million tonnes in three years. We're not going to add three million to our sales. And so 20% between off-take and purchase product, spot purchase.

Got it. Okay. That does it for me. Thank you.

Thank you. The following question is from Owen Douglas from Baird. Please go ahead. Mr. Douglas, your line is now open. You may proceed. If you are using a speakerphone, please pick up your handset. I'm sorry. Hearing no response, we will move to the next caller. The following question is from Chris Shaw from Monness Crespi. Please go ahead.

Thanks. Good morning. You guys cite a number for unused methanol demand right now or capacity that's not - downstream that's not using ethanol, at six million tonnes, and it's broken down between MTO, MTP, I guess and DME. Do you have any idea how much of that is DME versus the MTO, MTP?

Yes. These are our estimates, obviously. Just get the numbers out here. Okay. On the DME side, latent is about 600,000 tonnes, methanol to gasoline about 100, and then between MTO and MTP about 873. That's on a quarterly basis, which totals 1.573, which gets you to 6293. That's our estimate.

Right. Okay. Then is there any sort of level of oil or diesel where the DME starts - people start using DME again, where's the - do you guys have any internal number you use when you think people start demanding methanol again to make DME?

It's really propane that drives that, and propane trades - on a ratio to oil. But with all the PDH units that have come on, those ratios have been kind of blown up. I think where we are today on methanol pricing, it's marginal, and that's why we see operating rates in the 20% range. So I think you'd have to see something happen on propane more than oil, and you'll get some reaction. But even if you saw really large increases in propane, I think you're never going to get probably more than back to that 40% operating rate, which is what we've seen historically. So we're certainly never - we're big bulls on DME substituting for propane. I think the market that we saw, which had the real potential was the diesel substitution. But as I mentioned earlier, that'll take some time.

And can I just ask, you mentioned before that the cycle, the cost curve worked. Was there any capacity that was taken out permanently in this downturn?

Well, permanent capacity, I think nothing's permanent. I think it'll come down to capacity is taken out. You'd have to have a view that pricing is going to be X for some time before you make the investment to restart that capacity, whether that be people or capital. So capacity, unless it's actually dismantled, I think it is always available to restart in the right environment.

Okay. Makes sense. Thank you.

Thank you. The following question is from Edlain Rodriguez from UBS Securities. Please go ahead.

Thank you, good afternoon. Just one quick question. If oil prices stay at current levels in the mid-40s, do you see prospects for supply/demand dynamics to improve over the course of the year that would support higher prices? I mean, essentially trying to figure out, now, what's going to drive methanol prices higher from where we are right now.

Yes. Oil is certainly the precursor to a lot of what happens on the energy side. But I think it's a lot more complicated than just oil. You have to follow ethylene, propylene and all those derivatives, because MTO is really the demand that's driving the growth in the industry. So it's more what are those prices going to do, and the derivatives like ethylene glycol and PET. And those are the things we do on a plant-by-plant basis on those MTO plants. So what we've learned over the last 12 months is the historic ratios between those products have kind of blown up. And when are they going to be going forward? Who knows? I said earlier I have a hard time predicting methanol price next quarter, never mind 16 other commodities. So we will watch it very closely, but currently, based on the current oil price and the relative derivatives, the affordability is much higher than what we see the current methanol price in China at. So is that sustainable? Who knows? But something that we'll certainly watch.

Yes, that makes sense. Thank you very much.

Thank you. The following question is from Douglas Lee from FTN Financial. Please go ahead.

Hi, good morning guys. Thanks for hosting the call. I noticed on Slide 4 of your slide deck you discussed an amendment to your senior credit facility covenants as it relates to the EBITDA to interest coverage ratio. Can you please clarify for us exactly what that new threshold is and how that compares to the measurement of that metric as most recently reported?

So, Douglas, first of all, what we have negotiated is an option if we fail the standard test of two times interest coverage on a four-quarter trailing basis. If we do that, we have an election where we can elect into a sort of a secondary regime where we have total relief on the interest coverage ratio through to until the end of 2017.

Okay. And that provision would come at an additional interest cost on the amount outstanding?

No, there's no additional interest cost.

Okay. It's - okay. And can you please remind us what is the latest measure of that metric?

It's at EBITDA --

Correct. What is the value of it currently?

We don't disclose that. But we're hopefully onsite.

Okay. Understood. Thank you for that.

Thank you. There are no further questions registered at this time. I would like to return the meeting to Mr. Floren.

Well, thanks for all the interest. It's a difficult time in the methanol industry. And Methanex assets portfolio's in very good shape. We're committed to maintaining a solid financial position while allocating excess cash in a manner that we believe is optimal for shareholders. We're expecting other record production in Q2, which underscores the leverage we have to the recovery in methanol pricing. Thank you for the interest in our company.

Thank you. That concludes today's conference call. Please disconnect your lines at this time. And we thank you for your participation.