Methanex Corporation (MX) Earnings Call Transcript & Summary

Good morning. My name is Kate, and I will be your conference operator today. At this time, I would like to welcome everyone to the Methanex Corporation First Quarter 2025 Results Conference Call. [Operator Instructions] I would now like to turn the conference call over to the Director of Investor Relations at Methanex, Ms. Sarah Herriott. Please go ahead, Ms. Herriott.

Good morning, everyone. Welcome to our first quarter 2025 results conference call. Our 2025 first quarter news release, management's discussion and analysis and financial statements can be accessed from the Financial Reports tab of the Investor Relations page on our website at 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 first quarter 2025 MD&A and to our 2024 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, adjusted EBITDA, cash flow, adjusted income or adjusted earnings per share made in today's remarks reflect our 63.1% economic interest in the Atlas facility, our 50% economic interest in the Egypt facility and our 60% interest in Waterfront Shipping. 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. These items are non-GAAP measures and ratios that do not have any standardized meaning prescribed by GAAP, and therefore, unlikely to be comparable to similar measures presented by other companies. We report these non-GAAP measures in this way because we believe they are a better measure of underlying operating performance, and we encourage analysts covering the company to report their estimates in this manner. I would now like to turn the call over to Methanex's President and CEO, Mr. Rich Sumner, for his comments and a question-and-answer period.

Thank you, Sarah, and good morning, everyone. We appreciate you joining us today to discuss our first quarter 2025 results. Our first quarter average realized price of $404 per tonne and produced sales of approximately 1.7 million tonnes generated adjusted EBITDA of $248 million and adjusted net income of $1.30 per share. Adjusted EBITDA was higher compared to the fourth quarter of 2024, primarily due to a higher average realized price and higher produced sales. As we entered the first quarter, methanol markets were very tight with numerous supply constraints across the industry, leading to pressure on global inventories. In the Atlantic Basin, supply was restricted by planned and unplanned outages, gas feedstock constraints and restricted flows from the Middle East caused by the conflicts in the region. In the Pacific Basin, supply was restricted primarily from very low operating rates in Iran, which we estimate at well below 50% through the first quarter. These conditions led to pressure on global inventories and high methanol pricing through most of the first quarter. Conditions in the Atlantic Basin improved through the first quarter as plants returned from planned and unplanned outages as well as increased supply flows from the Middle East into Europe. And as a result, we saw a decrease in methanol pricing in the Atlantic from high levels as we moved into the second quarter. In the Pacific, we've seen some improvement in operating rates in the basin with increased production from Iran, although coastal inventories in China remained well below prior year average levels through April. In China, we've seen methanol spot pricing decrease by approximately $20 per metric tonne from Q1 levels, which we believe is driven by the anticipation of increased supply into the market and some moderation in global energy pricing impacting marginal production cost and MTO affordability. We estimate the current marginal cost of production in China in the $270 to $280 per tonne range. We posted our second quarter European quarterly price at EUR 625 per tonne, representing a EUR 75 decrease from the first quarter. Our posted prices for North America, Asia Pacific and China were flat in April and decreased in May. We're closely monitoring the impact of potential tariffs on global economic activity and are cautiously managing our business through this period of uncertainty. Although the direct impact of tariffs on our business currently is limited, an economic slowdown would impact methanol demand. To date, we have not seen an impact on methanol demand and we expect demand in the second quarter to be higher than the first quarter given increased seasonal activity in construction and mobility as well as higher MTO operating rates. MTO operating rates are expected to increase given increased supply availability in the market from seasonally higher operating rates from the methanol industry in the second quarter. Now turning to our operations. Methanex's production in the first quarter was lower compared to the fourth quarter with lower production from Geismar, Trinidad and Egypt. In Geismar, production was lower due to a planned turnaround at G2 and an unplanned outage at G3 at the end of February. G2 successfully restarted in March and is operating at full rates. We announced this morning that G3 has successfully restarted and has begun producing methanol. Our team worked closely with Johnson Matthey, the technology provider, during the outage to complete a root cause analysis and a revised start-up plan, which was successfully executed by the team. In Chile, I'm very happy to share that both plants have been operating at full rates and production was higher in the first quarter due to better reliability and the technical constraint being removed during the outage that occurred in November 2024. We have gas contracts in place with Chilean and Argentinian producers until 2030 and 2027, respectively, which underpin approximately 55% of the site's gas requirements year-round. We continue to expect seasonality in production but are seeing positive developments, making full gas supply for a 2-plant operation available for longer periods. In Egypt, the first quarter production was 20,000 tonnes lower than the fourth quarter due to gas curtailments that were driven by gas supply-demand balances in the country. We're monitoring the gas market closely and would expect to experience some curtailments in 2025, particularly in the summer months, depending on gas supply and demand dynamics. Now turning to our current financial position and outlook. We ended the first quarter with $1.031 billion of our share of cash and continued access to our $500 million undrawn revolving credit facility. As a reminder, in the fourth quarter, we executed our OCI acquisition financing plan, including issuing a $600 million bond and securing $650 million Term Loan A commitments from our banking partners. The completion of these financing arrangements gives us financial capacity to complete the OCI acquisition and flexibly achieve our deleveraging plan. We are continuing to progress the regulatory process and expect the transaction to close in Q2 2025. Our 2025 priorities are to safely, reliably and efficiently operate our business, close the OCI transaction and achieve the identified synergies and direct all free cash flow to reduce leverage. We do not anticipate significant growth capital over the next few years and remain focused on maintaining a strong balance sheet and financial flexibility, paying particular attention to the prevailing economic environment. Based on our second quarter European posted price, along with our April and May posted pricing in North America, China and Asia Pacific, our April and May average realized price range is forecasted between approximately $360 and $370 per metric tonne. Based on this lower forecasted average realized price coupled with lower produced sales due to the G3 outage, we expect lower adjusted EBITDA in the second quarter of 2025 compared to the first quarter. We would now be happy to answer questions.

[Operator Instructions] Your first question comes from the line of Ben Isaacson with Scotiabank.

I have 2 questions. Rich, the first one is on capital allocation. I'm sure it's one you've been asked before. When you -- when the OCI deal was announced, your stock was $40 and the weighted average spot price was about $350 or so. Now the stock is $30, the weighted average price is getting closer to $300. So the buyback return opportunity has improved. And from a time value of money point of view, the OCI return has kind of taken a very slight decline. Balance sheet risk has increased slightly. I'm not asking whether or not there's an opportunity to do buybacks instead of OCI. My question is, how flexible is the Board willing to be on this type of calculus? What is the threshold that they think about when deciding whether to pivot into something like buybacks versus completing this transaction without being criticized of too much short-termism?

I think when we talk about capital allocation and we look at our priorities for capital, number one, we want to have a strong balance sheet and be able to maintain our business through all cycles. And when we did the -- and the second thing is also looking at growth capital. And when we looked at both of those opportunities with the OCI acquisition, we're very excited about the value that creates for the company. But what we were committed to and remain committed to is delevering the balance sheet, and that's the continued focus for all of our free cash generation right now until we get to a place where we are -- where we were pre-deal with a much stronger asset base having brought on those assets. So that's the main focus. And right now, we're not considering share repurchases at this moment.

Fair enough. And then my follow-up question is on Iran. Can you give an update in terms of what you know about this port explosion and how it impacts methanol, whether it's trade, nearby capacity, storage? And then also what is your latest intel in terms of the impact that sanctions -- or the ramp of enforcement of sanctions are having on Iran methanol flow?

Yes. So first and foremost, no, that was a really tragic event that happened in Iran. We don't believe that, that's impacting methanol in any way. But obviously, that's something that they're going to have to review and figure out what that does from a safety and operational perspective, but not impacting methanol. As it relates to sanctions, I think what we saw through Q4 and Q1 is we saw Iran probably at some of the lowest points we've seen in -- from an operating, which is mainly because of the gas situation there. We believe a lot of residential demand combined with how the gas infrastructure performs. And obviously, that has to do with the impact of sanctions on their ability to produce and explore and invest in infrastructure there. So we saw well below 50% operating rates through Q1. We are starting to see increased rates as we come out of the winter period. We get most of our intel by looking at trade flow statistics. So we don't have a lot of insight into actually how each plant is operating, and we continue to monitor that. But we are expecting an increase in Iran flows into Coastal China in the coming months.

Your next question comes from the line of Joel Jackson with BMO Capital Markets.

So great that G3 is trying to ramp back up over the last little while here. When you think about that plants and some of the challenges you've had on it -- it's a bit of a different setup and configuration you have at other plants. And I think the depth of the configuration sort of requires -- what's the right word? -- like more user experience, competence, getting to know the asset better. Can you talk about that as the team learns to run this asset better? How much confidence do you have you can run this plant at 95% like your other plants? Or do you have to model for more maintenance, more downtime, more issues going forward?

The big thing for us was getting the right restart, start-up conditions for the ATR. So that was -- that has been the challenges we've worked through. We worked really closely with Johnson Matthey as well as bringing third parties here to help us through that process. And what we did is we've now got restart conditions. This start-up went very smooth. We've also built in validation checks that would tell us the 2 issues we experienced, and all of our validation checks have looked really good. And these conditions can be -- would also be used any time we go to -- if we ever have the plant come down for maintenance or an planned and unplanned maintenance. So we expect that these conditions look really good. Everything is checked out, and we feel really good about the ability for this plant to be up and running on a sustained basis and planning for high reliability. So we have -- we obviously have to prove that out and have a sustained run, but the start-up went extremely smooth and we're very happy with where we're at right now.

Okay. And then you have a busy month or so coming up, right? I guess you're hopefully going to close the OCI assets in the next imminent weeks. Have you been able to get some more color on how Natgas and Beaumont have ramped up? I've seen that they're doing better than they have in the past. Or is it you really only get on site once you close the deal?

It is more we get on site once we close the deal. We hear about industry operating rates through the same news reports or industry analysts that a lot of people read. Both those plants have come off of turnarounds recently. So that's a bonus for us. And -- but we will -- we're on our way to move through the regulatory process in Q2 and are excited to bring those world-class assets into our supply chain.

If I just fit one more in, it looks like you're implying about a 40% discount rate so far to posted price in Q2. Is that the right level of discount rate we should be using as a base case for the rest of the year, second half of the year, even after the OCI asset closes and after G3 is back running normal?

We gave a range of $360 to $370 for the posted price. It's probably on the higher end of that range for the few months. Giving a discount rate -- I think what we're looking at right now is always what's the level over China in our global ARP. And I think right now, China is pricing in and around $270, $280, and we're realizing this level. So we could see some moderation in that depending on global supply-demand balances and what we see on energy pricing. But right now, we really focus on what's that realized pricing over China. And so, hard to give you a discount rate. I mean, if you want to use that 40% and -- it's something we probably want to get back to you on. But right now, we like the premiums that we're seeing over in the market, and we'll continue to track and monitor that as we move forward.

Your next question comes from the line of Josh Spector with UBS Financial.

I wanted to ask 2 things on China, is just one where you talk about where prices are today. I mean, they moved down decently over the last month. How do you think about the support level given where coal has moved towards? Does that leave more room to move down? Or is there something where you'd say this is something that drives support here? And then second, just -- I know there's not really any direct trade flow here of U.S. into China, but just thinking about tariffs creating friction, does that have any impact on Western Basin supply at all in terms of some of the movements, or Asia, if that's the one worth commenting on more?

And to your first question, the cost curve today is at that 270 to 280 level. That's a pretty firm cost curve based on coal pricing at around RMB 650 per tonne. And we've seen coal pricing, it's right in kind of the range that the government kind of sets on where they target coal pricing to be. So right now, we've seen -- we've tested our cost curve many times in this industry and it is quite resilient and responsive, and that's the level we see today. And it's -- the other data check is MTO affordability and where olefins pricing is at. And I would say that's another kind of data point that is pointing to around that 280 to slightly above level. So we think China is firmly in that space today. As it relates to product movements and friction, we don't expect a lot of -- there isn't a lot of U.S. flows moving to China today. Actually, there's no flows moving today. I think the biggest thing we would be looking at is just the impact of tariffs on export manufacturing out of China. And that's something we're going to be watching, because the Chinese manufacturing, a big proportion of that is for exports. The government is trying to stimulate domestic consumption as well. So there's actions being taken there, but that's something we're closely monitoring right now.

And probably too tough to answer, but I'll try, is just if you did have some downturn further from here in terms of China demand, would you see exports going into China needing to find a new home? Or would you see domestic assets shutting down? Is there any one of those that you would see as a more likely scenario?

It's -- I mean, what we would see is, if you got into -- first off, we don't see a big impact because when you really boil it down -- China is a big consumer of methanol. They consume about 60 million tonnes. About 1/3 of that is into traditional chemical applications. And then if you look at how much of that is export, a ballpark might be about 50% of that, and about 15% of manufacturing from China goes into the U.S. So you get down to a pretty small number that we're monitoring. So we wouldn't expect to see a big reaction right now on demand. If you got into an oversupply situation, yes, we'd probably see some moderation of operating rates in coastal China to balance the market, but not something we're seeing today, and we don't expect to see a big impact.

Your next question comes from the line of Steve Hansen with Raymond James.

Just wanted to ask about risk mitigation as you move into the closing stages of the transaction here. What are the key steps you need to take or maybe some of the initiatives that you need to put in place to make sure you've got the risk managed as you take on these new assets? I'm thinking gas in particular, I know it's unhedged. Any additional operational or offtake marketing type agreements? Just walk us through how you can get a hold of that and take risk down in what's still a pretty uncertain environment.

Yes. No, we -- I mean what we've done is already stood up a big integration management team that's looking at all aspects of the integration, ensure on day 1 we're going to be producing methanol safely and reliably as well as delivering to customers. Obviously, we can't step into that business today, but we've been planning as much as we can ahead of the transaction to be ready on day 1. There really isn't -- I don't -- we don't see a lot of big risks and hurdles, but we've obviously been assessing all of the risks and then trying to address everything we can. A big thing is getting on the systems and being able to communicate early and understand information flows, being able to bill and pay invoices, all of those things, and we're thinking through all of that. So on day 1, we bring this on in a very seamless way and be able to incorporate this into our business as quickly as possible and then really work on delivering on synergies, which will take some time. So we've had a big team focused on this internally. And working with OCI as much as possible ahead of the transaction while ensuring all sensitivities to the regulatory process, and that's not been closed yet.

Okay, great. That's really helpful. And then just thinking back to the G3 recovery and startup now it's been announced, is there going to be gating milestones as it's going through, you know, this new, I'll call it, run rate process with the new catalysts in place or the new fixes to the ATR anyway. So how should we think about that? Is there planned ups and downs to test out how it's going? I'm just trying to get a sense for whether we should expect any sort of fluttering in the operating rate here in the next quarter or 2.

Well, I think one distinction, and maybe it's just something to clarify, is this has all been about start-up conditions and getting the unit to full operating rates. Once we've gotten to full operating rates -- the autothermal reformer has operated really well at 100% operating rates. We operated at for 4 months close to full capacity, producing 600,000 tonnes. So once we get the unit up to full rates, it's operating extremely well. What we didn't have are start-up conditions that either didn't produce it or it didn't have pressure on the system that caused the catalyst damage. And so what we've done through this step, and I feel very confident about that we validated through the process, is that we now have start-up conditions that allow us to get to those high levels without doing any damage within the unit. So there is no bringing down to test. We've got ourselves up to high operating rates, and that's where we expect to be. Of course, any time we -- if we were to have unplanned downtime, we would go in and inspect and just validate everything that we can't do while we're online. But everything online tells us we're in good shape.

Okay. Great. And then just one last one. I apologize if I missed it earlier on some of the tariff talk, but is there any issue with bringing methanol in from Trinidad as you see it here today? Is there any, I don't know, risk to the tariff structure there? And how that should impact sort of inbound flows, I guess, more broadly from the country?

Yes. So there is some limited flows of Trinidad into North America, mainly in the -- on the East Coast supply chain. So there is a flat 10% tariff right now. And it's pretty -- very minor and limited impact to the business, and that's something that we're working on right now.

Your next question comes from the line of Hassan Ahmed with Alembic Global.

A question around demand. Over the last couple of years, I take a look at a variety of sort of commodity chemicals out there. They've been pretty weak, maybe even some, sort of customers of yours. I'm just sort of thinking in terms of like polyurethanes and the like, and I know that's a much smaller sort of piece of the pie. But I mean, as I read sort of some of your near-term commentary, particularly as you talked about some sequential demand declines in Q1, I mean, it just appears to me that they were primarily, call it, for seasonal reasons, Lunar New Year and the like, maybe slightly reduced MTO operating rates. And then, if I heard you correctly, you're talking about a sequential uptick in demand in Q2. So with all of this volatility, macro-economic volatility, some of your end markets being a little volatile, I mean, could you talk about how methanol demand has actually held up far better than some of the other commodities out there? And what your expectations are even in this sort of reduced global GDP growth environment over the next couple of quarters?

Sure. So right now, again -- I think I've talked about the makeup of demand for methanol. When we look, about 50% is traditional chemical applications, about 30% to 35% is energy applications and the other 15% to 20% is methanol to olefins. So I mean, if we start with the energy applications, those have been quite good for us. And when we're seeing those, we haven't seen big variability or volatility in that demand. It's been really stable and growing. MTO tends to be a balance on the industry. So when there's a lot of supply in the market, they tend to operate high rates. And when the supply gets tight, they tend to operate low rates. So there's a bit of a noise in our demand because of the balancing act of MTO operating rates on our industry. The traditional chemical applications vary by -- have varied by region, and that depends heavily on GDP in each of the regions. And that's something we monitor really closely and a lot of it goes into all the leading indicators of economic activity. And so you go around the world and -- it hasn't been particularly strong, but we haven't seen weakness. But it's something that we're watching, and we're expecting relatively flattish. When we say seasonal demand is going to pick up, we're not talking about big increases from a percentage basis. But it was seasonally low in Q1 and we expect it to be seasonally higher in the second quarter. Certainly, auto, housing, all those leading indicators are things that we're tracking and we're going to watch closely. But I think one of the things to note about our industry relative to other petrochemical industries is that we have seen, I would call it, lower growth than we've seen historically. What we are seeing is limited supply. And I think that's one of the differentiation points. Existing supply in methanol has had a hard time keeping pace even with slower growth because of constraints around Iran, constraints around Russia, Venezuela. We've seen it in Trinidad, New Zealand, et cetera. Because of those gas feedstock or geopolitical sanctions -- a variety of number of factors has led existing supply to be constrained and not a lot of new capacity being added in the industry. So I think -- I do think there's a bit of a differentiation that even with slower demand, methanol is not getting out of balance like we do see in some of the other sectors.

Understood. Very helpful. And as a follow-up on the feedstock side of things, particularly on the U.S. natural gas side -- I mean, obviously, with the close of the OCI deal, your exposure is going to get larger in the U.S. I mean, it just seems that you have arguments being made on both sides of natural gas prices. Obviously, we've seen a fair degree of volatility in nat gas prices. Crude oil prices have come under pressure. There are some sort of pundits out there talking about how they're potentially in a lower oil price environment, there could be shut-ins in the Permian. I mean, how -- now, as your exposure is rising in the U.S., with all of this sort of noise around natural gas pricing, how are you guys thinking about nat gas? How are you guys thinking about your existing hedging program? How are you guys thinking about the hedging program on a go-forward basis with the OCI deal eventually closing?

We look at it very closely, obviously. And right now, as you know, we actively are in the market with our rolling hedge program targeting to get certainty around our cost structure at around 70% operating rates. So that's where we are today on our current U.S. assets. And I think what we're seeing is we have seen volatility in the short run and we've seen the long run end of the curve actually coming down. So when you look at where the long end of the curve is, it's at -- we're seeing $350 pricing or below, which is really positive for us. So we're actively looking at what we want to do with OCI. We haven't taken any action on that to date, but it is trending positive to gas pricing. That gives us a really good cost structure over that longer period. In the short term what we've seen is spot gas trading down below $350. But when you look over the remainder of '25 and into '26 and somewhat into '27, it's still in the $4 range. And so we're kind of -- we can be a little opportunistic with the way we layer in. So we're looking at both the short term and the longer term. But we believe there's going to be opportunities to get a really good cost structure to underpin making our company stronger and more resilient with these assets.

Your next question comes from the line of Nelson Ng with RBC Capital Markets.

First question just relates to New Zealand. Can you just talk a bit more about the gas supply situation there, Because it looks like you diverted gas in Q1? And I think in the past, it's typically been over the summer or the Northern Hemisphere summer. Do you expect -- I guess the follow-on question is, do you expect the diversions to the power sector to ramp up? And can you decide when to divert gas or does the offtaker do that?

On New Zealand gas, you're right, we did. We produced about 160,000 tonnes during the quarter. So we produced less than full capacity at one plant. We are selling a small portion of gas, and that was a contract that was asked of us and we negotiated last year. As it relates -- as we move into the winter months, it's more likely that we could see a big ask on gas, which we'd be very responsive to if that's the case. So it's more an ask on us rather than us selling in. Gas in New Zealand, I would say, where we are today just with our suppliers -- our continued operations at one plant are dependent on gas production in New Zealand, and it's something we continue to work really closely with our gas suppliers there. So we're in this balance of, we need the gas to continue to maintain our minimum operating rates. There's some requirements of -- needs for the residential power. And so we're trying to balance all of that while working with our gas suppliers on their outlook for gas supply. So it's a pretty dynamic situation, and we'll be able to give you more of an update when we get through Q2 as to how that power sector and draw on gas plays out.

And if methanol prices trend lower, are you able to push more into the power sector? Or like you said, it's more about -- what I'm asking for -- but...

Yes, it is more about the demand-supply balances in the country and what comes to us from request. Certainly, we're there and we've always been responsive to that, and we'll continue to be.

Got it. Okay. And then just switching topics a bit. On the OCI transaction, can you just talk about which key approvals are needed and if any have been received yet?

Yes. We're going through the regulatory review process in both U.S. and Europe, and those continue to progress. And that's -- those are the remaining steps to move through approval of the transaction.

Your next question comes from the line of Matthew Blair with TPH.

Great. I want to circle back to the Q2 guide. So the $360 to $370, it seems to imply that the discount rate is getting worse in Q2 than it was in the first quarter. Are there any structural changes that would explain that? Or is that just a function of the geographical mix?

Yes. No, I think you probably shouldn't read too much into that. I think we'll probably be on the high end of the range. So I'm not sure where you're calculating the percentage. Again, we're really focused in kind of what will be the realized pricing over kind of -- when we think about the cost -- or the price at our region, which is China. We have seen inventories getting more healthy and through -- with more supply into the market. So as we trend through Q2, we'll just continue to track. And directionally, we have seen some moderation there. So -- but I wouldn't be pointing you to a big expansion in the discount. It's more pointing to where some of the spot markets have trended in the short term.

Sounds good. And then you mentioned improving methanol demand in the second quarter in part due to higher MTO operates. Is there any numbers you can share on where MTO utilization is today versus the average for the first quarter?

Yes, it's -- today, it is pretty similar to the first quarter. It's around 75% to 80% operating rates, and that's where we are. We have seen when there's lots of supply available in the market, which we do think as Iran ramps up and we start to see more coastal product available in China that we have seen them get into the above 90%. And there's -- again, there's about 21 million tonnes of capacity. So a 10% change means kind of 2 million tonnes of demand there. That will all be dependent on what's available in the market and as these plants come out of their maintenance.

Your next question comes from the line of Laurence Alexander with Jefferies.

Could you speak to -- as you were assessing kind of trough scenarios for the OCI merger, how severe a trough you considered and what sort of liquidity metrics you focused on? And secondly, could you give an update on what you're seeing on the shipping pipeline for methanol flex fuel capacity?

In terms of a trough scenario, we sort of plan the company and the balance sheet around the $250 per metric tonne price. This is the lowest we see pricing go in a 12-month period and usually it would only be in a sort of an economic shock type of event like COVID or a financial crisis is where we've seen that happen. The first thing that we do in terms of planning the company is having assets that are on the low end of the cost curve and cash positive through the cycle, which we think these assets would be. And then it's also just ensuring we have access to liquidity. And so our undrawn credit line is available to us, and that will be actually increased to $600 million post deal as well. So we have natural levers in our business. Typically, when you see lower methanol price, our gas contracts respond. Some of them are pinned to methanol price. In those lower environments, we always see gas in North America tends to be a lot lower. We get foreign exchange on our fixed cost structure because the U.S. dollar tends to strengthen and currencies against it tend to be weaker. And then we also look at other things like discretionary CapEx and OpEx and other measures that we would take in those types of environments. So we feel that we've properly planned for any trough scenario. We're certainly way -- far away from that today, and we'd have to see a lot greater impact to get to anything that resembles that.

Okay. Great. And just on the marine flex fuel.

Sorry, yes, marine. We're -- I think we'll start with the ships. We still see all of the container ships, and the outlook there is 350-plus ships coming into the market over the next 4 or 5 years. By the end of this year, the demand potential for all the ships that will be on the water would be close to about 3 million tonnes of demand potential. Of course, that will depend on their selection of fuel. Is it -- are they going to burn methanol? Will they burn conventional bunker fuels? Today, gray methanol, so call it conventional methanol, is -- with the affordability levels today, methanol would probably be higher than low sulfur fuel oil, probably lower than marine gas oil. So we're not sure what economic decisions shipping companies are going to make there, but obviously, we're in a lot of discussions with them today on their needs. Giving you a demand forecast is difficult because those decisions have not been made structurally. So we're not seeing long-term contracts for methanol quite yet, and we're working on making sure that methanol is available in all the major ports through relationships with bunkering companies. But difficult to give you a demand forecast. Discussions around low-carbon methanol also continue, and that becomes a bit more of a cost decision and are regulations going to push that and are customers going to have willingness to pay. We have seen some positive signs from the IMO regarding both their percentage of lower carbon fuels they want to see go into the global fuel pool as well as potential penalties that would be applied if shipping companies are noncompliant. Those have not been implemented and there's still lots of discussions, but the IMO has taken some steps to try to push forward with that, and that's something we're watching really closely.

And then just lastly, the U.S. proposals to implement fees on China-made or China-owned ships or fleets, ordering ships from China, does that create any arbitrage opportunities for you relative to competitors?

I don't think it does. I guess being a Canadian company do we have an opportunity to -- yes, I think maybe it depends on what type of ships we're talking about. The types of ships that we're building are medium-range vessels that are smaller in size. So I think this more gets into larger container ships. But we can get back to you on that question.

There are no further questions at this time. I will now turn the call back over to Mr. Rich Sumner.

Thank you for your questions and interest in our company. We hope you'll join us in July when we update you on our second quarter results.

This concludes today's conference call. You may now disconnect.