Methanex Corporation Aktie

Good morning. My name is Trevor, and I will be your conference operator today. At this time, I would like to welcome everyone to the Methanex Corporation Third Quarter 2026 Results Conference Call. [Operator Instructions]

Thank you. I would now like to turn the conference call over to the Vice President of Investor Relations at Methanex, Mr. Robert Winslow. Please go ahead.

Good morning, everyone. Welcome to Methanex's Third Quarter 2026 Results Conference Call. Our 2026 third quarter news release, management's discussion and analysis and financial statements can be accessed through our website at methanex.com.

I would like to remind listeners that our comments today may contain forward-looking information, which by its nature, is subject to risks and uncertainties that may cause the stated outcome to differ materially from actual results. We may also refer to non-GAAP financial measures and ratios that do not have any standardized meaning prescribed by GAAP and are, therefore, unlikely to be comparable to similar measures presented by other companies. Any references made on today's call reflect our 63.1% economic interest in the Atlas facility, our 50% economic interest in the Egypt facility, our 50% interest in the Natgasoline facility and our 60% interest in Waterfront Shipping.

To review the cautionary language regarding forward-looking statements and to find definitions and reconciliations of the non-GAAP measures, please refer to our most recent news release, MD&A, annual report and investor presentation, all of which are posted on our website under the Investor Relations tab.

I will now turn the call over to Methanex's President and CEO, Mr. Rich Sumner, for his comments, followed by a question-and-answer period.

Thank you, Robert, and good morning, everyone. We appreciate you joining us today to discuss our third quarter 2026 results. With the third quarter average realized price of $510 per tonne and produced methanol sales of 2.3 million tonnes, our third quarter adjusted EBITDA was $543 million and adjusted net income was $284 million.

The third quarter adjusted EBITDA, which includes a $10 million accrual for restructuring activities at our New Zealand operations, decreased the second quarter of 2026, primarily due to a lower average realized price, partially offset by increased sales volumes of produced methanol. These outstanding operating results drove record levels of cash flow generation for our business, and I will speak more about our capital allocation priorities in a moment.

Starting with the methanol market. The ongoing Middle East conflict continues to have an unprecedented impact on the industry given the region would normally supply 15 million to 20 million tonnes, representing 30% to 35% of the internationally traded methanol in the market. The ongoing conflict continues to significantly restrict this supply and has resulted in elevated industry pricing, inventory drawdowns and ultimately, demand destruction required to balance the market.

This pressure continued and became more severe as we moved through the third quarter. After absorbing the short-term release of supply during the temporary ceasefire in mid-June to early July, we've seen very little supply able to reach the market. And as a result, there was increasing pressure on methanol prices, particularly in Asia and China regions with a significant fly up in September, resulting in spot price increases of $100 to $150 per tonne in these regions.

As a result, we saw increasing pressure on downstream demand, particularly in Asia Pacific, through the third and into the fourth quarter to balance the market. We estimate that the Middle East supply into the market is currently at approximately 5% to 10% of normalized annual levels, and this has been balanced with the shutdown of all coastal methanol-to-olefins demand in China and the reduction in demand in other regions, including the Middle East, Southeast Asia and India. We estimate current annualized industry demand to be approximately 90 million tonnes or a reduction of 10 million to 15 million tonnes as a result of these supply pressures.

We are currently seeing methanol spot pricing in the Atlantic region at $500 to $550 per tonne, Asia ex-China at $550 to $650 per tonne, and China at approximately $500 per tonne. Looking ahead, there remains significant uncertainty as to how long the industry dynamics and pricing environment could last. We're carefully monitoring the factors and related time frames required for a normalization in the methanol industry as well as macroeconomic impacts from an elevated global energy environment. We're unaware of any specific material damage to methanol production facilities in the Gulf region and the full impact of potential disruptions to regional natural gas and related infrastructure remains unclear.

Turning to our operations. We continue to deliver strong production results in the third quarter with total equity methanol production of 2.1 million tonnes. Starting in North America, we produced another record volume of methanol this quarter, reaching 1.6 million tonnes across Canada and the United States. Geismar and Medicine Hat continued to run at full rates, producing 1,007,000 tonnes and 140,000 tonnes, respectively.

At Beaumont, after completing cooling tower repairs early in the quarter, we produced 199,000 tonnes of methanol and 83,000 tonnes of ammonia. Our equity share of production at the Natgasoline joint venture was 221,000 tonnes.

In Chile, we produced 221,000 tonnes in the third quarter. As expected, production was lower in the third quarter as we undertook single-plant operation through most of the period, reflecting the seasonal reduction in natural gas availability from Argentina during the Southern Hemisphere winter. Late in the quarter, we restarted two-plant operations as planned.

In Egypt, our third quarter production was similar to that of the second quarter with plant operating at full rates through the Egyptian summer. In New Zealand, we produced 156,000 tonnes in the third quarter, following a planned winter outage in the second quarter to supply gas to the New Zealand electricity sector. The plant was restarted in July. As previously disclosed, we've entered into an agreement commencing in the first quarter of 2027 to sell our remaining gas entitlements through the end of the decade and are planning to indefinitely idle the New Zealand operations at that time.

For 2026, our expected equity production continues to be approximately 9 million tonnes of methanol. Actual production may vary depending on timing of turnarounds, gas availability, unplanned outages and unanticipated events. As previously discussed, we continue to operate under significant industry supply pressures, resulting in an elevated pricing environment. And based on October and November contract price postings and current spot pricing, we expect our average realized price range for these two months to be approximately $525 to $550 per tonne.

Assuming current pricing levels are sustained through December and produced sales volumes are similar to those of the third quarter, we expect adjusted EBITDA to be higher in the fourth quarter than the third quarter. Continued strong methanol production, underpinned by attractive natural gas feedstock in the current methanol price environment, is driving very strong cash flow generation for our business, and we ended the third quarter with over $900 million in cash.

In this strong pricing but uncertain industry and macroeconomic environment, we're continuing to focus the majority of free cash flow towards our deleveraging targets while also allocating a modest proportion to shareholder returns. Subsequent to the third quarter, we repaid $300 million of our 2027 senior notes, and we expect to redeem the remaining $400 million in the fourth quarter.

In addition, yesterday, we announced Board approval to initiate a normal course issuer bid under which we may purchase and cancel up to 5% of our shares outstanding. These actions reflect our disciplined approach to capital allocation as we move towards our balance sheet leverage target of 2.0 to 2.5x adjusted debt to adjusted EBITDA while also providing returns to shareholders.

Our priorities remain unchanged: safely and reliably operate our assets, cost effectively operate our global supply chain to provide unmatched security of supply to our customers, complete the integration plan and capture the planned synergies, and focus on conversion to cash through the business to deliver value for shareholders. We'd now be happy to answer your questions.

[Operator Instructions] Our first question comes from the line of Hassan Ahmed with Alembic Global Advisors.

Rich, a question around -- obviously, fairly elevated methanol prices, and I know you touched on this in your prepared remarks as well. But just wanted to get a better sense of at these pricing levels, what you guys are seeing potentially in terms of demand destruction, potentially also in terms of a supply response. Are there any talks about incremental capacity? How we should think about that as well?

Yes. Thanks, Hassan. In terms of supply response, like I said, I think where we are today is that the demand has effectively absorbed this level of Middle East supply. We said on the Q2 call, we were working through that temporary ceasefire. There was volume in the market, and we actually saw pricing in China in the $300, low-$300 levels during that period.

Our view is that after the ceasefire ended that unless something changed, we were going to run up against demand pressures, and that was going to become more severe through the quarter. And we've seen now all coastal MTO operations shut down. That's the first time we've seen that since the MTO sector started up. So that's 9 million to 10 million tonnes of demand right there in a normalized annualized that's out of the market today. And about 3 million to 4 million tonnes in Asia Pacific, that would be Middle East, Southeast Asia, India, operating at lower operating rates.

So as of today, pricing levels are already above MTO affordability, well above marginal cost of production. And we're watching it really closely as to where that demand pressure is. We think that it's largely into other applications in China, fuel applications may be under pressure. Acetic acid was under pressure. We think that, that's had a little bump here recently as well.

So we're watching it really closely. We have found this balance today of, I think, 12 million to 14 million tonnes effectively being absorbed under demand. Of course, there's still risk in the 5% to 10% getting out of the strait. October was one of the -- we saw a tax on ships being the highest through October, and there could be even more pressure on that supply. But as of today, we've found this balance, and that's where pricing is at. So we saw that lift up into September and our forecast for -- our guidance for the months of October and November are more reflective of that September being rolled through Q4.

And as a follow-up on the buyback obviously, the balance sheet is improving extremely rapidly. How should we think about the balance between further deleveraging and further returning cash to shareholders? Is there a specific leverage threshold at which you start getting a little more aggressive with the buybacks?

Yes. I think a few points there. I think, first and foremost, the earnings levels are driving great free cash flow in our business. I just want to recognize that having G3 running sustainably, having the OCI assets smoothly integrated and then having all of our other assets running reliably on the basis for such good free cash flow generation.

As it relates to leverage, we've set the leverage target at 2.0 to 2.5x on an adjusted debt to adjusted EBITDA level. We're progressing really well there. As it relates to the buyback, when we think about buybacks, we're really pleased to have announced that. We think that gives us a lot of flexibility. We do think that buybacks represent the most attractive return when we can say we're buying back at conservative mid-cycle types of valuations or below. So I think we'll be looking at that. We'll likely enter into the buyback with flexibility to go up if we see the share prices come off and also pull back if the share price has also really good performance.

So we've got a lot of flexibility right now. The focus of the majority of it is to deleveraging, and we think that provides a lot of downside protection to our business as well as more optionality on other ways of deploying capital.

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

Curious about what you're seeing in terms of the impact of the current methanol price surge on long-term decision-making. And I guess the areas that might be most visible would be the cadence of orders for new fuel flexible ships. But curious if you're seeing -- like are you seeing any of the end markets where longer-term decisions that would affect the structural trend in methanol demand are being delayed in a significant way because of what's going on and how long the war has gone on?

Thanks, Laurence. I would say not yet. The commitments to ships are still happening. And in fact, there's a decent amount of ships already in the water that aren't burning methanol today and really haven't been because the economics of methanol to conventional bunker fuels like VLSFO and heavy fuel oil have really not been there. And so we haven't seen an uptick in the use of methanol for those dual fuel vessels. The vessel commitments remain. Other downstream sectors, the MTO sector is obviously one that is now effectively phased out of this current market and the wave of those capacities had already come off.

So it's interesting like what's happening in this market is we're starting to see some downstream producers in Europe who we thought would be phased out operating because of constraints around the Middle East. So there's definitely a lot of short-term dynamics happening. I don't think it's resulting in yet a change in long-term downstream capital deployment, but it's something we'll certainly watch.

And then secondly, can you give a sense for how much of -- or maybe at what levels or how quickly -- let's put it this way, how quickly does the areas of demand destruction likely flex back if methanol prices come down. So I guess thinking there's like the MTO, there's the DME, there's some of the other markets that have curtailed a little bit. There's the marine fuel. Can you just give a sense for what chunks of capacity might have a lag response to lower prices as opposed to a quick response?

Yes. I think in a lot of ways, we've seen the coastal MTO sector be almost a big buffer against the Iranian supply. Iran usually imports about 9 million to 10 million tonnes into coastal markets, and that's the downstream demand from coastal MTO. So there's almost like a balance there, and we would expect that if supply gets released that segment is there to start up, and it would largely be based -- have to be a lower methanol price to be competitive today.

And then on the other sectors, it will be mainly into traditional chemical applications, acetic acid operations, potentially localized formaldehyde demand that would pick up. And so there might be a little bit of stickiness just because of the volumes there aren't typically as big, and we need to get that absorbed. So we could see volatility. Whereas we've seen pricing run up, we could see supply come on, pricing lag, demand pick up.

So we are watching things very closely and obviously carefully managing through this environment, which is part of the reason why we think our focus on the balance sheet makes a lot of sense right now and then obviously really focused on continuing to deliver such great results from our business.

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

Some of the natural gas production trends in Argentina have been pretty promising. And just wondering if you expect your Chile methanol production to be higher in 2027 and 2028 as a result of this? Are there any pipeline constraints or any other bottlenecks that would prevent you from capitalizing on that?

Thanks, Matthew. No, there's not constraints on our side. We've got more than enough pipeline capacity to bring gas into our plants for full rates year-round. As it relates to Argentina, we would agree about the positive developments there. the Vaca Muerta continues to be -- developed production continues to increase and pipeline infrastructure is being progressed to continue to improve the natural gas balances in that country.

And in fact, if you saw that Total came out with a commitment of $10 billion into Argentina. Part of that's in the Vaca Muerta; part of that is also in the Tierra del Fuego Basin offshore gas close to our plant. So a lot of positive developments. I think time frames to bring both the infrastructure in line with the production as well as get other things happening in the country is over the next few years.

That also aligns to the current planned gas regime that covers exports in the country. And so we think it's probably going to take that time until we start to see the opportunity to have year-round gas, and that's what we're working towards. And we're really optimistic about that. But right now, we're going to continue to guide. When we come out with our numbers and we'll give guidance for next year in the coming quarter here, it will likely be at the more 1.4 million tonne level for Chile for '27.

Sounds good. And then the Q3 realized methanol pricing in your system seemed better than expected. Was there a onetime boost from selling the New Zealand natural gas commitments? Or any other factors that we should be thinking about?

No. Certainly, nothing to do with our gas. Really, when we look at the pricing, we saw through the second -- sorry, the third quarter, a significant boost up in -- especially in the Asia Pacific regions where China lifted up and Asia Pacific ex-China lifted up by $100 to $150 a tonne. What you'll see is that, that September pricing a bit of uplift around the world as well. So that September environment is carrying forward into the fourth quarter. September really lifted us up. If you look at our ARP from July, August, September was the highest, and that's what's continuing into the fourth quarter.

Our next question comes from the line of Ben Isaacson with Scotiabank.

Two questions for me. Rich, first one on capital allocation. If your cash flow strength continues, you'll achieve your balance sheet targets very, very quickly. And beyond the 5% buyback, which I estimate you can achieve every few weeks if you wanted to, is there any focus or consideration on deploying growth capital? And is there any consideration on revisiting the dividend?

Yes. Thanks, Ben. Right now, obviously, as I said, our focus is around deleveraging. And you're right, we're making really good progress there. When it comes to growth capital, of course, we're always interested, can we find value-accretive growth for shareholders. When it comes to organic growth, our position still remains the same, notwithstanding the current methanol price environment, we'd have a lot of hesitation thinking that we're at a price that we need over a 20-year time frame at the mid-$400s or maybe slightly below to make long-term investment economics work for organic growth. And that's largely because we've still seen a very hot EPC market out there. And so the cost to build are still very high.

As it relates to M&A activity, we know that, that's very opportunistic and assets don't trade. We would look -- obviously look at something, but we're going to be very disciplined about the way we would look at anything, and we would measure that return over other capital deployment like buying back our own production through share repurchases.

So our focus continues to be on debt. We've got lots of flexibility, like I said, which is great. We think that as we're deleveraging, we're creating a more resilient and giving ourselves downcycle protection for the company, and we're creating more flexibility to buy -- to step in and do buybacks at a bigger level if it makes sense.

So I think right now, we've got our head down, and we're running the business safely, reliably, continuing to produce results, and then we'll deploy capital and make those decisions when we get there. You did ask about the dividend. We do -- we think a dividend is an important piece of our capital allocation. We want it to be meaningful. Our primary return of capital we want to deploy is through the flexible buyback. We remain committed to the dividend level. And as we're buying back shares, we would look to maintain that level by increasing the dividend to shareholders.

And my follow-up question. CF Industries recently gave some very compelling arguments as to why midcycle nitrogen prices should be higher for longer. And all of its arguments had nothing to do with nitrogen, but they were based on capital costs, logistics, inflation, et cetera. So Rich, you've talked about $350 midcycle for several years. Do you still believe that's the right midcycle going forward? And if not, what should it be?

Yes. So thanks, Ben. I think, obviously, in our industry, where we want to be is getting pricing to support growth. The challenge for us is the -- and we would have seen this actually prewar -- is the general petrochemical markets. This is not methanol, in particular. It's the markets around methanol.

Our market, we've got very good supply-demand balances on prewar levels, very tight industry market. But we have downstream consumption around us that is it has a lot of excess capacity combined with a slower growth demand environment. So for us, we have to see where we are long term, but certainly, the olefins sector was pointing to balance not until the end of the decade or beyond. What happens out of this remains to be seen, and we're going to continue to evaluate that. But I think the hard part for us lifting above that is seeing some healthier markets downstream.

Of course, this dynamic is bringing new fundamentals into that industry that we have to better understand. So I think the big thing for us is the health of our downstream markets that support reinvestment. And our view is that, that would get progressively better over time. And as we -- as that gets better, we think that lifts our midcycle pricing. And so that's the way we're looking at it. We're monitoring things very closely.

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

Not to beat the dead horse, Rich, but you amazingly are paying back $700 million of debt as you know in the second half of this year. If this second half year methanol price -- if your earnings in the second half of the year repeat again in the first half of next year, you would have another, what, $700 million to deploy. Would we assume that the full buyback here that would be about [ $300 million ] and the rest deleveraging, would you look to upsize the buyback, the NCIB? Like I know you're talking about you'll make the decisions when you come to it. But what if in the next six months, earnings levels stay the same, you have another $700 million to deploy. How does that look buyback versus deleveraging?

Thanks, Joel. I appreciate the question. We're thinking ahead, obviously, but we're also monitoring things very closely. Things can change very quickly, and we think the other side of this can have a lot of volatility, and there's also risks, right? So we're managing things very carefully. The good problem or the good challenge you pose is for us will be a look at what do we think provides the best return.

And we do think that the buyback will be a part of that. We also think that as we look, if we're deleveraging into the low end of our range or even slightly beyond that, that provides downside protection and it also provides more optionality for capital deployment. So we've got a lot of flexibility in our choices, and we're managing things really closely. The buybacks will certainly be a part of that. And we just have to make decisions about the proportion of that as we progress here. But let's get there, and we'll make those decisions as we continue to produce great results for shareholders.

Just a couple of housekeeping questions. Just I wanted to ask you, in some of the trade journals every week, there are a couple of discussions about Beaumont over September, October, a couple of multiday outages that then seemed to restart. So I wanted a comment on that, if there's anything at Beaumont we should be thinking about it? You had some comments about Beaumont earlier. And then also, I'm sure you saw the news today or yesterday that bunch of nitrogen producers are getting cut gas maybe 20% in November. Would your operation in Egypt be facing similar constraints? Could you talk about that?

Yes. So first on Beaumont, really nothing to report there. The big challenge that we worked through and the team did a great job bringing us back online with the cooling tower repairs that were executed in Beaumont, but nothing major to report there at all. As it relates to Egypt, we continue to run our plants at full rates. We continue to monitor the gas grid balances and are in communication with our gas suppliers, but we're continuing to run at full rates today, and you'll see our results as we move into our fourth quarter reports.

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

I recognize that you've got this leverage target threshold or range. But is there any reason you wouldn't just drive your leverage down much lower in the current environment? Just again, recognizing that the broader macroenvironment is pretty unique right now and the cash flow is so strong, why not just take leverage closer to 0?

Yes. I think 0 is pretty -- it would require a good sustained pricing environment for sure. Steve, appreciate the question here. And that's something we're looking at. We wouldn't have thought we would be accelerating as quickly as we are, certainly with the production levels, the attractive gas pricing as well as the high methanol pricing that we're in right now. And we're continuing to focus there, and it's accelerating very quickly.

But again, there's lots of uncertainty as to what the other side of this looks like once things do normalize and what that new normal looks like. But to your point, we think that moving -- deleveraging provides downside protection through the cycle which is a great position for us to be in, and it provides optionality as well. So certainly, further debt repayment will be a portion that we would look at as long as we're in this extraordinary situation that we are in today.

And just a quick follow-up just on the North American production continues to be quite strong. You've had the OCI assets under your belt for a while now and spent some time under the hood. Are there additional opportunities that brings on a brownfield basis or on efficiency basis where you could spend capital, again, while the cash flow stream is quite rich here. I'm just trying to get a sense for how these assets could be optimized from what you understand so far.

Yes. I appreciate that question, Steve. We're very happy with the way the integration has gone. Just talking about both of the assets, the Natgasoline, kudos to the team there that's delivered the record production over the last year. And our JV structure is working really well. We're working extraordinarily well with our JV partner there. And we think we have tons of methanol experience together. And of course, we've ran that technology in Trinidad. So that's running.

In terms of debottleneck, that's a world-scale plant. I don't see a lot of options in capital or debottleneck at that site. In Beaumont, again, really pleased with the production results as well as the integration of that site into our global asset management framework, and the teams are working really well there. As it relates to debottleneck, there's probably some -- we certainly need to spend capital, and that's from a risk perspective, that was something we're planning for when we get to the next turnaround because we are identifying -- always identifying where we need to spend money. And then there could be some debottleneck opportunities there.

We are looking at ammonia and is there some chances for us to spend some money to increase volumes there. So some interesting things that we're looking at. Obviously, the safe, reliable operations of the asset are critical, and our teams are working really hard on all that.

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

Just along the lines of capital allocation and paying down a bit more debt. So like obviously, after you pay down the October 27, is it -- are there any difficulties paying down the $700 million of December 2029 debt? I presume that would be like next on the list if you were to further deleverage.

Yes. I'm going to turn -- thanks, Nelson. I'm going to turn that over to Dean Richardson, our CFO, to speak to that.

Yes. Sure. Good morning, Nelson. No, there's no difficulties. I think it's the short answer. First of all, we have some debt at [ Natgas ] that gas that we include our share in our adjusted debt, and so work with our partner there to optimize that structure. And then when it comes to our bonds, we've got a '29 and '32. And we have different options there as to how -- if we wanted to deploy capital to those, we could do that fairly easily through open market or tender offers or other avenues. So lots of options, and we're looking at the best way to deploy that for the company.

And then just finally on -- I think you touched on debottlenecking a bit. So are there -- you touched on Beaumont or the OCI assets in terms of them operating well. But for your other facilities, is it safe to say that you -- all the low-hanging fruit in terms of debottlenecking or incremental expansions have been already looked at and it would -- if you were to expand capacity, would it be something more material?

Yes, I think that's a fair characterization, Nelson. Obviously, we are always looking at ways we can continue to invest in our sustaining capital to ensure reliability of our plants and, of course, look for are there opportunities that we can spend capital to increase efficiency to create -- but these are not big capital items. These are part of our regular capital programs, which is included in our estimate of $150 million in capital a year. So I don't -- I wouldn't say there's any big opportunities that are in the hopper around big debottlenecks other than we are looking at some things around the ammonia, but even that doesn't represent huge capital outlay.

And then just one last question. In terms of winding down New Zealand, and I think you mentioned you'll be selling or winding down those gas contracts starting early next year. Like is that an asset or a liability? Or do you expect to receive any proceeds from ending those contracts?

Yes, you can think of that as a small asset. Just in terms of that contract itself, we've been foreshadowing gas in New Zealand for the deterioration in our gas outlook there for quite some time. We're operating plants at minimum operating rates. Our team has done a fantastic job operating it with a lot of uncertainty safely and reliably.

But we got to a point where we had to make decisions there to create certainty because of that deterioration. So you can think of that contract as something to create that certainty, and we were able to monetize that position, but it's not a meaningful or material cash inflow that we're anticipating, but we do expect to receive some cash under that agreement.

Your next question comes from the line of Hamir Patel with CIBC Capital Markets.

Rich, you've benefited from having no turnarounds this year. Can you update us on the turnaround schedule for '27 and '28?

Thanks, Hamir. Yes, we didn't have turnarounds this year. So most of our capital spend has been on line work, but we have had some prespending for our '27 turnaround. So you can think we usually say around two to three turnarounds a year. We'll be at the higher side of that in 2027. And our capital expenditure for next year, where we usually guide around $150 million will be higher than that next year, but not significantly higher because we have pulled some of that capital into this year, second half of this year. So yes, that's the profile. And obviously, these things will go up and down each year given timing.

And Rich, I noticed in the intra-quarter language that you use around expected prices, there was also a reference to spot pricing. Does that imply that perhaps you've increased your exposure to the spot market? And can you just remind us what percent of your sales are spot?

It's -- so we're not selling on a spot basis, but we're selling under term contracts and the two markets here that had the biggest impact are in Asia Pacific, and it's China and our Asia Pacific region. So those contracts are termed contract supply, but the pricing mechanisms have reference to spot. So we had meaningful adjustments in both of those. We don't have that as much in other regions in our sales portfolio.

Your next question comes from the line of Ahmed Abdullah with National Bank of Canada.

Just touching on those contract terms, are the current market conditions really allowing you to improve the pricing terms there? And how much of that improvement could persist as spot markets normalize?

Yes. We're going -- our contracts are on a year-round basis, and we're in our recontracting period right now for 2027. So too early to say how our contracts look for next year. Our sales and marketing team are always working on how do we continue to provide that reliable supply to our customers and also achieve the best terms possible we can in the market. But I wouldn't be expecting big changes for next year. Of course, we think that our supply position is providing great reliability and supply through a pretty tough time in the market. So we're into customer conversations, and we'll continue to do that, and you'll see that as we move into 2027.

And just on the current supply disruption, have you secured perhaps new longer-term volume commitments that could remain after conditions normalize?

Maybe I just want to make sure I understand the question. Is it that we would -- our commitments will be through -- we're going to have regular annual commitments with customers, and we would be doing that through any period of disruption or new supply into the market.

Yes. My question was around new customers and new supply -- new volume commitments that were coming into your books.

Yes, we're going to be high-grading our -- we always look at our sales portfolio, and we always look at what contracts we come up. We wouldn't expect overall sales to be significantly different as we move into 2027, but we're always looking at which regions and which customers that we're going to be selling to. So we don't expect a significant change in that, and you'll see that in our 2027 results.

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

This is James Cannon on for Josh. I just wanted to ask on -- dig in on the supply-demand picture nearer term. Particularly, I think as we get into fourth quarter, we typically see some capacity shutting down in China. How do you see that impacting the market going forward? Do you think there's risk skewed to the upside in pricing or something that you just see incremental demand shutting down?

Yes. Thanks, Josh. I think you've certainly got a point there. We do tend to see winter when we start to see restrictions on coal usage. So part of that will be what's [ the pull ] on coal domestically in China, what does that do to operations there, do they get supply constrained, and does that apply further demand pressure. It's something that I think we're going to watch that really closely. It's interesting. We haven't really had to look at that because of the swings we've seen mainly in Iran have outweighed so much of the supply swings in the winter. So that's something we'll watch.

And certainly, coal prices are already at pretty high levels, which would indicate that, that market is pretty tight. So we'll continue to watch. Again, we're at $500 methanol price in China, which we haven't seen for quite some time. So we do have to be careful how high we push and how much damage that does to downstream demand. But again, that's another factor that's going to keep us tight through the winter months.

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

All right. Thank you for your questions and interest in our company. We hope you will join us in February when we update you on our fourth quarter and annual 2026 results.

This concludes today's conference call. Thank you for joining. You may now disconnect.

Good morning. My name is Angela, and I will be your conference operator today. At this time, I would like to welcome everyone to the Methanex Corporation Second Quarter 2026 Results Conference Call. [Operator Instructions]?

I would now like to turn the conference call over to the Vice President of Investor Relations at Methanex, Mr. Robert Winslow. Please go ahead, Mr. Winslow.

Good morning, everyone. Welcome to Methanex's second quarter 2026 results conference call. Our 2026 second quarter news release, management's discussion and analysis, and financial statements can be accessed through our website at methanex.com.

I would like to remind listeners that our comments today may contain forward-looking information, which, by its nature, is subject to risks and uncertainties that may cause the stated outcome to differ materially from actual results. We may also refer to non-GAAP financial measures and ratios that do not have any standardized meaning prescribed by GAAP and are, therefore, unlikely to be comparable to similar measures presented by other companies.

Any references made on today's call reflect our 63.1% economic interest in the Atlas facility, our 50% economic interest in the Egypt facility, our 50% interest in the Natgasoline facility, and our 60% interest in Waterfront Shipping.

To review the cautionary language regarding forward-looking statements and to find definitions and reconciliations of the non-GAAP measures, please refer to our most recent news release, MD&A, annual report and investor presentation, all of which are posted on our website under the Investor Relations tab.

I will now turn the call over to Methanex's President and CEO, Mr. Rich Sumner, for his comments, followed by a question-and-answer period.

Thank you, Robert, and good morning, everyone. We appreciate you joining us today to discuss our second quarter 2026 results.

Our second quarter average realized price of $529 per tonne and produced sales of approximately 2.2 million tonnes generated adjusted EBITDA of $577 million and adjusted net income of $300 million. This adjusted EBITDA, which includes a $12 million accrual for restructuring activities at our Trinidad and Tobago operations, increased versus the first quarter of 2026, largely due to a higher average realized price driven by the Middle East conflict, combined with continued strong production from our enhanced asset base, particularly in North America.

The resulting strong cash flows from operations allowed us to repay the remaining $290 million outstanding on the Term Loan A facility, while still ending the period in a strong financial position with more than $380 million of cash on the balance sheet.

The continuing Middle East conflict has resulted in an unprecedented impact on many industries, including methanol. We estimate that 15 million to 20 million tonnes of annualized methanol supply is required to transit the Strait of Hormuz to reach end markets. During the second quarter, we believe some of this supply, mainly from Iran, came to market at significantly reduced volumes and almost entirely from pre-existing inventories.

We believe the significant supply gaps created through the second quarter were met with a combination of rapid drawdowns of inventory, primarily in Asia, and through increasing demand rationalization, both methanol-to-olefin demand in China and other demand, particularly in Asia. This situation led to elevated and volatile methanol pricing across the world throughout the second quarter.

There remains significant uncertainty as to the ultimate resolution to the ongoing conflict and the extent of damage to methanol plants and broader infrastructure is still not clear. As we move into the third quarter under current conditions, the impact of a more prolonged conflict will become even more severe on the methanol industry. We believe the 15 million to 20 million tonnes of production previously mentioned, continues to be idle and that pre-conflict inventories are now meaningfully reduced.?

As a result, we would expect to see even less supply from the Middle East as we move through the third quarter, and this, combined with inventory now drawn to very low levels, means we would expect increasing pressure on industry supply to meet ongoing demand. Under current conditions, demand rationalization will increasingly be required until a resolution allowing Middle East production to resume and to reach the market on a more normalized basis is found.

Turning to our operations in the second quarter. Our total equity methanol production of 2.2 million tonnes was slightly below first quarter production levels.

Starting in North America, we produced a record high volume during the quarter of 1.6 million tonnes across Canada and the United States. We produced 1,027,000 tonnes at Geismar, which is also a record level in a quarterly period for that site. We produced 180,000 tonnes of methanol at the Beaumont plant in the second quarter, and our equity share of production at the Natgasoline joint venture was 204,000 tonnes. At Beaumont, we took the plant offline in early June and safely executed a 30-day unplanned outage to repair the cooling tower with the plant restarting in early July.

In Chile, we produced 327,000 tonnes in the second quarter, utilizing gas supply from Chile and Argentina. As expected, production was lower in the second quarter as we shifted to operating one plant midway through the quarter due to the seasonal reduction of gas availability from Argentina during the Southern Hemisphere winter season.

In Egypt, our second quarter production was similar to that of the first quarter with the plant operating at full rates. The plant continues to operate well today, and we're closely monitoring the supply and demand balances in the country during the summer season when local residential gas demand typically peaks.

In New Zealand, we produced 46,000 tonnes in the second quarter, down from the prior quarter as we entered into various commercial arrangements to manage and optimize our gas supply entitlements, given the meaningful short-term uncertainty and structural challenge in the gas market. We shut down the plant for May and June and restarted in early July at similar reduced operating rates to the first quarter.

Lastly, on June 29, we announced the indefinite idling of our Titan plant in Trinidad and Tobago as we were unable to come to terms on a commercially viable natural gas contract. We'll continue to monitor future developments in Trinidad with a view to reassessing conditions over the coming years. I want to thank our excellent team members in the country for their professionalism through a difficult period.

As a result of the commencement of restructuring activities, we recorded a $115 million noncash after-tax asset impairment charge and a $12 million accrual for restructuring activities.

Looking forward, our expected equity production for 2026 is approximately 9 million tonnes of methanol. Actual production may vary by quarter based on timing of turnarounds, gas availability, unplanned outages and unanticipated events.

Based on July and August contract price postings and assuming market conditions remain consistent in this volatile macroenvironment, we expect our average realized price range for July and August will be approximately $460 to $485 per tonne. Assuming this pricing holds through September and factoring in produced sales volumes similar to those of the second quarter, we expect another strong quarter of earnings lower than in the second quarter due to lower pricing.

Our priorities for 2026 are unchanged: to safely and reliably operate our assets and supply chain; and to complete the OCI integration plan and realize plant synergies.

Now that the $550 million Term Loan A facility has been repaid, we're approaching our initial leverage target of approximately 3x adjusted debt to adjusted EBITDA. In this highly uncertain and volatile environment, we will continue to direct the majority of available free cash flow to building cash and reducing debt to move towards our longer term leverage target range of 2 to 2.5x adjusted debt to adjusted EBITDA at mid-cycle pricing. As we make progress towards this goal, we will evaluate directing a modest amount of free cash flow towards share repurchases.

We would now be happy to answer questions.

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

I just have one multipart question, Rich. On the Q4 call, so about 6 months ago, you said that we wouldn't really see much Q1 margin capture of rising spot prices as it related to the start of the war as you were going to honor contracts and discount rates that had already been negotiated, I think, a few days earlier. So the thinking was that if you didn't capture margin on the way up, then you would certainly capture it on the way down. And I think why the stock is down a bit today is because it appears that, that ASP guide that you're giving, it appears to be giving up margin on not just the way up, but the way down as well. So is that the wrong way to think about it? And can you remind us how exactly monthly contract prices are set, how those discount rates are set and adhered to?

And then just a blue sky question. Would it not be easier just to charge spot plus, say, a fixed premium or whatever the number is, $40 or so, for customer service availability, reliability, et cetera?

Yes. Thanks, Ben. I think just to answer that question, I think is it the wrong way to look at it, maybe partially, but certainly, there's an explanation regarding spot. I think in a rising price environment, what happens is contract prices tend to lag the rising price. Some elements in our contracts have some reference to spot pricing. And some of our regions are more focused towards the spot type of pricing element, Asia being the one that points more towards spot. So in a rising spot environment, you will have, I call it, a compression, you'll realize more off of the discount in a rising price environment. And in a lower price environment, you would realize less of that contract price because of those components in our contracts.

So right now, we -- when we gave our price guide for the third quarter, just remembering that from a market perspective, we saw a pretty meaningful impact through -- and this is a very highly volatile price environment we're in -- through July and August was the period here when we entered -- is the period where we had the temporary cease-fire and a lot of product got released in a very short period of time. That's now obviously stopped. That actual volume combined with sentiment meant we saw a pretty big downshift in spot pricing, particularly in Asia, but actually in regions around the world.?

So we effectively put that into our estimates for the quarter to be conservative. That's actually already started to reverse. So when we look at our price guide, we're probably already at the top end of the range. If market conditions continue, because we don't see supply being released, we would expect things to tighten up and that those realizations would be higher based on that view.

So -- and then back to your point about pricing, the -- I think the, call it, the market principle has been contract price postings. That's the way the industry prices. Are we always looking -- the way discounts have gone and the way some of the formulas work, we're always looking at, is there a better way to price. But as of today, we remain committed to our contract price postings, and that's the way we go-to-market to customers. Hopefully, that answers your question.

Next question comes from the line of Josh Spector with UBS Group.

So I just wanted to ask on the production guidance. I mean, you basically held that constant despite taking down supply. I mean, what's the assumption behind that? Are you assuming you could run Americas harder? Or am I just reading too much into a small change here?

Thanks, Josh. Really, when we look at that guide, we're sort of -- we are looking at where we are today, and where we are today, we're slightly -- we're higher than that -- higher than the guide. And so we've kind of already accounted for the back half of the year with Titan now being idled. And under the assumption that our -- what we've seen so far and where we're higher is really in Egypt and New Zealand. And when we look at the back half of the year and how things are trending, we think we make up that volume. So we're around the 9 million tonnes and holding to that.

I will also say that when we think about the tonnes, not all?tonnes?are created equal when it comes to earnings, right? And taking out Titan is a lot different than having higher Egypt volumes. So there's a benefit there certainly in terms of the cost competitiveness of the production that's really running well right now.

Okay. That makes sense. And I just wanted to follow up on your comments you made around cash deployment and particularly buybacks. I guess we don't know how long higher prices are going to last, but I mean, you're clearly generating more cash here. And I mean, we understand your goal of getting to 2 to 2.5x, but your stock is very volatile around people's views around the war on, war off. And it would seem like you have opportunistic opportunities to maybe deploy some cash there and still have pretty good visibility to getting to your leverage target in 6, 12 months from now. So why not consider doing something earlier? Or is that something that's going through the thought process at all as you look at where your stock is over the next 3 to 6 months?

It's certainly going through the thought process right now. We'll make an assessment of where we are against our deleveraging, what's the forward view of cash generation and where the share price is performing and determining how much goes to share repurchases and also when we would open up the flexibility to do that. But I can say that it is in the thought processes right now.

Next question comes from the line of Jeff Zekauskas with JPMorgan.

Your cash flows were very strong this quarter, but it's a little difficult to tell if there are taxes that need to be paid or if working capital really needs to move up toward the end of the year. What do you think the relationship between your operating cash flow and your adjusted EBITDA will be this year? What percentage will be operating cash flow roughly?

Yes. So when we look at our adjusted EBITDA, in a normalized environment we look at our adjusted EBITDA and our -- on an annualized basis. And the difference, we would say, is around $500 million between the two. And that's our lease payments, our interest, our capital and then cash taxes as well. When it comes to this period, we did have a significant working capital build. That was around $150 million, and a lot of that is in our trade receivables. So you can think of a lot of our -- a pretty big chunk of the earnings we saw is captured in our -- in AR right now. And in an event, if we get back to more normalized prices, we'd expect that those earnings would come through. So the longer that doesn't come through, the more we're earning in terms of higher prices.

And then when it relates to cash taxes -- maybe I'll turn it over to Dean Richardson, our CFO, to speak to that.

Sure, Jeff. So you're correct that we did accrue cash taxes in the quarter, obviously, given the earnings. And so you'll see that the cash taxes paid on the cash flow is a modest amount. And so there is a payable that's been built. So that's part of the build in our accounts payable. So you're correct, there is a timing factor there that's already been accounted for. It's -- our guide on taxes remains the same is that about a 25% tax rate and about 50-50 cash taxes. And that's primarily due to -- in this high price environment, our U.S. assets are not cash taxable. So that's the micro answer. The macro answer, Rich gave it around the relationship between EBITDA and cash flow.

And when the Straits opened up, how much methanol do you estimate came through the Straits? And how much have the Chinese increased their methanol production to make up for the tonnes they're not getting from Iran?

Yes. So on the first question, when we think about the Middle East and the 15 million to 20 million tonnes, the big question is sort of how do we -- how does the market stay in balance there? We think of that amount during the second quarter, about 1/3 of that was actually released during the quarter. And that was Iran coming out at smaller, more reduced volumes throughout the whole second quarter, mostly. And then during the period where there was a temporary cease-fire, we saw both Iran and the Saudi volumes being released -- Saudi and other non-Iranian volumes being released out of the Gulf. So it's about 1/3 total. Determining how much came out during the cease-fire versus -- is a bit difficult. So we do track vessels and a lot of those will be coming into the market over July and August, but it was certainly lumpy during that time frame.

How we -- where we go from here, how we also balance was on inventories, both the coastal inventories in China and then also on demand rationalization. So those levers are going to be hard to replicate because the plants haven't been idle and now inventories are fully drawn. Domestic operating rates in China have been strong, but there hasn't been a huge step-up of Chinese operating rates. The Chinese market has been somewhat sheltered by MTO shouldering most of the supply issue with Iran. And what will happen is as that -- as we work through inventories, and there's no longer these buffers, it's going to put both -- all of the MTO coastal demand under pressure and likely start to pressure domestic markets. So in a lot of ways, the domestic industry has been sheltered because MTO really takes the brunt of lost Iranian product into the market.

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

Looking at Beaumont, you took down the cooling towers back up. I know you talked about maybe being able to make some changes over time at that plant, maybe improving it. Would that be something you have to wait to do a bit later on a turnaround? Or did you be able to do some of the work in the last month -- or sorry, in June?

Yes. Thanks, Joel. Just a reminder, maybe about more broadly both Natgasoline and at Beaumont. We're very pleased so far with what we've seen from those assets after a year from the point where we closed the deal. The operating rates we've seen so far have been above where we would have -- where we sort of came out from a deal value perspective. This -- what we've done is deep technical reviews of both the assets, and that's looking at how the assets have run. We look at all of the inspection reports, and then we come up with a list of risks and vulnerabilities. And our goal is to always reduce those down as much as possible through online maintenance, through if we have unplanned maintenance as well as major turnarounds. And obviously, the most work you can do is during a major turnaround.

This issue with the cooling tower, we did have as a risk in our risk matrix for the plant. And we had had plans to do online maintenance during the second half of the year here. But upon further inspection, we saw that the structural damage to the support of the cooling towers was too much. So we took an outage. The team executed that within 30 days as planned safely. And at the same time, we took out other vulnerabilities of the plant. So our goal is to continue to run this reliably and -- safely and reliably, and we believe we can, on a long-term basis, do that with both of these sites.

Now we are still learning the assets. And if you ask us, would we like to have a full turnaround cycle? For sure. But we know -- we're getting to know these assets really well now. And our goal is to continue to operate at really strong reliability and then get the opportunities to reduce risk as much as possible. The next one being the turnarounds, which isn't until the '28-'29 time frame, but the team has done a -- is doing a great job learning the assets and integrating with the teams.

Okay. And then at Geismar, the three plants seem to perform really well. You get over 1 million tonnes in the quarter. You've never done above 1 million before. Should we be modeling that going forward? You should be above 1 million tonnes now, ignoring turnarounds or any unplanned outages?

I mean I think we -- that's our goal. Our goal is 4 million tonnes for the plant, and that's considering about a 97% reliability rate. The plants performed. We always do have -- in between turnaround cycles there becomes limitations as you get closer to a turnaround, that makes the kind of getting to the 4 million tonnes. Sometimes that -- you do get below that because you're -- where you are in catalyst life. But over the average, yes, the target is to have 4 million tonnes of production there.

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

Rich, wanted to revisit the 15 million to 20 million tonnes of sort of capacity being impacted by the Middle Eastern conflict question again. I understand -- you mentioned that almost 1/3 of that was released as Hormuz opened up. And clearly, it seems that these fits and starts will continue. But as you sort of cut through the noise, I'm just trying to get a better sense of how much of those 15 million to 20 million tonnes have actually been significantly adversely impacted, meaning what percentage of those 15 million to 20 million tonnes will take a while to hit the market as and when the [indiscernible] declaration and Hormuz fully opens up?

Yes. Thanks, Hassan. I think this is -- when you ask how much of the production is impacted, all of it is. It's all idle, and none of it is able to transit. We don't have free navigation flowing in through the Strait of Hormuz now and all of it has to transit that waterway. And so we have a long ways to go before we get back to normal here. And really what -- in my opening remarks, what I was trying to communicate is, what we have is that we did have about 1/3 of that, we would say, came into the market through pre-existing inventories. That was what was in storage or in vessels prior to the conflict. And then we haven't had any production to back that up. And how the market's really effectively weathered that is by drawing -- by having that be released, but -- and then draw inventories through the supply chain. And also, we've seen now demand much lower than what we would expect at this time of year.

So typically, you'd have the coastal MTO operating, that's 10 million to 11 million tonnes of demand, that would be operating at high rates in a normal year. So last year, we would have seen that operating at 80% to 90% operating rates. It's at 30% to 40%. We've seen demand happening,?rationalization?in the Middle East, in India, in Southeast Asia, and that's making up for a chunk of this. What we're not going to have, we did have this product be released through July and August, and that's coming into the market today. And once we get through, if we don't see some sort of normalization, once we work through that inventory, we don't have those levers to work with. And so then we've got an issue where you've got to see further demand rationalization and pressure on the industry.

And even if we get back to something that's more normal, it is really important that we were able to assess, can they get gas flowing to methanol plants the same way it was, or methanol plants able to operate at the same rates they were, and is navigation as free flowing as it was prior to the conflict level given the risks on shipping and the ability for owners and charterers and insurers to get comfortable with that navigation. So it's -- we're in a situation where -- here, where we do see some sustained pressure to getting back to something that looks like the world pre-this conflict.

Very helpful, Rich. Again, I wanted to dig a bit deeper probably on the demand side now as well, particularly in light of some of the inventory statements you guys made. You obviously talked about fairly significant drawdowns of inventory in Asia. I'm just trying to get a better sense. I mean, look, no two periods are the same. But if one was to go back to 2003 and the Iraq conflict, it just seems starting with upstream oil prices, which obviously are quite correlated to methanol prices. Going back to that time period, initially as sort of the conflict subsided, there were steep declines in oil, drawdowns in inventory, a lot of paper selling of sort of oil and in theory, obviously negatively impacting downstream product pricing. And then all of a sudden, the physical buyers came out and demand picked up, there was major restocking and pricing went up significantly.

So again, with that in mind, I'm just trying to get a sense of how critical are inventory levels right now? As you earlier said that pricing even today may be trending to the higher end of the guided to range. So if pricing does start picking up, I mean, what potentially could a restock look like?

Yes. Thanks, Hassan. I think you're asking all the right questions. It's really hard for us to formulate firm views because it is such a dynamic environment. But the -- for us, what we see on the methanol side and what we see from methanol is that we think our supply chains have been depleted of inventory pretty meaningfully, especially in Asia. When you look at coastal markets in China, it's now around 500,000 tonnes now. It was -- that was a 1 million tonnes draw in a quarter, that on an annualized basis, that's a lot. And then we do think the customer supply chains are really tight.

Then you get into, well, how is that affecting the downstream? I mentioned there that China has somewhat been sheltered because they had strong domestic production. That has supported some of the chemical markets like acetic acid and others where you do have export -- that has propelled a lot of export manufacturing, which is probably filling some of that -- the traditional chemical value chain, the gaps created in -- by the Middle East supply. How long that lasts and how sustainable that is without price killing off demand further downstream is a big question mark for us. So these are the things that we're continually monitoring.

Now one of the things to note for us is that the markets that are most acutely impacted here are the markets that we don't supply because it's where the Middle East is logistically advantaged. So it's a lot of India, it's Southeast Asia, it's Taiwan. But I do -- we do think that the longer this goes on, it's going to creep into the markets that we're also in. And so we're paying really close attention to that with our customers as well. But again, price is usually the one that kills it off and then that also gets into higher pricing down the value chain and inflationary pressures and what does that do to long-term demand risks. And that's why we're navigating this current market really, really carefully and carefully monitoring the situation.

Next question comes from the line of Nelson Ng with RBC Capital.

Just on shipping costs, I think the disclosure was higher logistics and other costs in Q2 compared to Q1, reduced EBITDA by about, I think, $18 million. Can you just provide a bit of color in terms of whether the majority of that was mainly higher shipping costs? And within shipping costs, like is it just higher fuel costs, like longer shipping routes, insurance or other factors?

Yes. Thanks, Nelson. When we're looking at our shipping costs today, I think we're in a very different environment on the supply chain than what we would have expected coming into this year. And it's affecting both the fuel cost because we saw bunker costs go up by about 40% during the quarter or over this last 5-month period. The other thing that is happening is in a normal environment, you see a much lower spot vessel market. So the spot pricing for spot vessels has gone up significantly. And there's far less backhaul opportunity as refiners are limiting export or unable to get the crude they need to produce or limiting exports. And so what that means is a far less optimal fleet, both from a shipping cost as well as the, I'm going to call it, the miles per tonne of methanol because we're having more shipping days for the methanol that we're moving around the world. And we're avoiding any spot exposure from a cost perspective.

So those two factors are probably causing $30 million to $40 million versus our, call it, our run rate or plan for the year. All of that would actually -- would normalize and go away in a different market, in a different pricing scenario. So part of the price uplift we're getting is coming with a less optimized fleet, which we're carefully managing. We saw about $18 million come through in Q2. We would expect that we will continue to have some increasing costs as we move into Q3 because of the lag impact on inventory and how that works through our shipping actually gets kind of attached to the inventory and flows on a lag basis.

Okay. Got it. And then just can you remind me like what portion of your product do you transport with your own ships versus using spot? Is it pretty much the vast majority?

The vast majority is our time charters. So I think 80% -- in a normal environment, 80% is time charter and about 10% to 20% is going to be COA and spot. In this environment, we -- normally, we'd be doing backhaul and efficiently managing fleet. Without backhaul, we shift away from -- we use our time charters to solely move our product. So we're more towards the 100% basis right now because that's the most efficient way with lack of opportunity and the high cost in the system. So we're trying to optimize around that. But today, it's -- we have zero spot exposure effectively because we're managing around that.

Next question comes from the line of Laurence Alexander with Jefferies.

Two related questions on the demand side. One is, could you be a little bit more granular about where you're seeing demand shaking out this year by the key end markets? And I guess, can you clarify to what extent you have visibility on the degree to which demand is getting pushed back? Or are you hearing from the downstream chain significant efforts to shift or substitute away or just outright demand destruction? Just trying to get your sense for how much visibility, if any, you've been able to get over the last few months?

Thanks, Laurence. Maybe just to kind of put it into perspective, like on a yearly basis, again, it's 100 million tonnes, 60% of demand in China, 20% to 25% is in Asia ex-China and the 15% to 20% is in the Atlantic regions. What we've seen today is probably in estimate, we're at -- we're operating 5% to 10% lower demand today than what we would normally expect in this time of year. And that's MTO operating at probably 5 million tonnes lower demand on an annualized basis than what we would expect. And then there's probably another kind of 3 million tonnes-ish of demand between Middle East, like MTBE, they've got MTBE production there. They've got some acetic acid production there. That's not operating. The market in India has been impacted, the market in Southeast Asia. So those, we would say is probably about 5% to 10% lower and particularly in those markets.

Now when we look at outside of -- the other applications, when we think about formaldehyde, it's a very much a regional type of demand. Housing has not been particularly strong. It's stable off of a low base. Some of the other applications I was talking about earlier is like acetic acid, silicon, some of the more downstream products that you do see being exported further down the value chain. What we think is happening is the pressure has been somewhat dealt with by China continuing to operate and being exporting out, and that's helping that value chain by solving that -- that's solving some of the supply.

How much of this is real demand destruction remains to be seen. And it hasn't -- we haven't seen it trigger. Huge uptick in acetic acid pricing and VAM pricing and others. So we're waiting to see how this responds, because if it does lead to ultimately destruction further down the chain, you would expect to see pricing increasing to higher levels there. So we're monitoring all of it. I think as we progress here, we'll get a -- we'll get increasing visibility, both on methanol as well as further down the chain.

Next question comes from the line of Matthew Blair with TPH.

Rich, do you think the Iranian methanol supply has been structurally impaired going forward? And if so, would that come from hits to like the South Pars gas field in Iran or actual damage to any Iranian methanol plants?

Well, thanks, Matthew. We -- it's still unclear today around what damage may exist. I think we haven't heard any reports that lead us to believe the actual methanol plants have been damaged. But we have heard reports about the South Pars field, and we have heard that the gas processing from that -- from those fields could be limited. It's really hard to know because we obviously don't have direct access to information. And we've never seen a period where anything could operate stably through the last 5 months. So it's hard for us to know. We will be looking really closely as soon as possible. And when -- if the gas fields are impacted or gas processing, of course, then it gets into how are you prioritizing your gas and where does methanol fit.

And we do think that methanol is obviously going to be deprioritized relative to residential demand, et cetera. And that's always been the case when gas isn't operating or there's peak demand residentially, that gets prioritized. So it's a very -- this is a big risk in the ability for supply to continue to meet demand. The other big thing, obviously, is navigation and getting that reestablished. But as of today, we don't have visibility or information that confirms any long-term damage.

Sounds good. Then, I think it's interesting that Methanex itself has built inventory each of the past few quarters despite a very favorable methanol price environment. Should we think about that as preparation for upcoming turnarounds in the back half of the year? Or is that just kind of normal course of business? And ultimately, would you expect to draw down some of that inventory in the back half of the year?

Yes. I wouldn't read too much into that. I would say that in this environment, we have seen customers being very cautious and especially when -- on sentiment. If they see an upward pricing pressure that may stabilize, we'll probably see them destocking and being -- and running low inventories and buying as little as possible until there's a more normal. And I think the world is waiting for a more normal environment. So just small changes in our sales projections can lead to a bit of a build in inventory. But I wouldn't read a lot into that. You would expect those things to reverse over time, but I wouldn't read a lot into that build.

Next question comes from the line of Hamir Patel with CIBC Capital Markets.

Rich, with your current customer commitments and the different demand destruction that you're seeing out there, how do you think about for the remainder of the year, your geographic sales mix? Just thinking about that slide you show that shows the different regions and how you might look to optimize that for the rest of the year?

Thanks, Hamir. We're kind of -- we would stick to that guidance, probably on the low end on -- from a China perspective, but we're going to be within the range, certainly. With lower Trinidad now, we would expect China would be lower. We'd be selling less there. So probably the proportionality is leaning less to China and more to markets outside of China, which obviously has a benefit from an overall ARP.

Just last question I had, earlier on a shipping question, I think you mentioned sort of $30 million to $40 million headwind you're seeing this year. You had $18 million in Q1. Should we expect most of that remainder to show up in -- sorry, the $18 million in Q2, the remainder in Q3?

Yes. I just want to clarify that's $30 million to $40 million a quarter. So these are -- it's significant in terms of the fuel, 40% increase in bunker charge and then the suboptimization overall in the fleet. So it's something we're very carefully managing. Yes, about half of that came through -- I'm just ballparking, half came through in Q2 and the other half would be coming through in. And I'm quoting the $30 million to $40 million against our run rate or our plan, which is way -- far less optimized today because of fuel and fleet. But yes, half through Q2 and then the other half through Q3. And then once we're there, we're kind of seeing that running through the system. If things normalize, we would expect to see the benefit coming through lower shipping costs in future quarters.

Next question comes from the line of Ahmed Abdullah with National Bank of Canada.

Just on the Trinidad idling process, beyond the $12 million restructuring costs, are there any ongoing other cash costs or closure expenditures that you anticipate in Q3?

No, no, there won't be. Obviously, we still have our team there. We're going through a restructuring planning activity right now to ultimately determine what the existing or the remaining preservation team will look like. And those would be costs that would continue to be incurred in our system, but wouldn't be very material.

Okay. That's fair. And just touching on the acquired assets and given their strong performance, you mentioned that you're on track to realize the synergies. Is there an opportunity that perhaps you exceed your original targets for the acquired assets in terms of synergies?

I think, maybe just to put it in terms of kind of some of the buckets here, we came out with $30 million of hard synergies. We've realized some of those. So we're running lower cost in certain areas. This year, though, we're running higher costs to try to tease out those synergies by the end of the year. So we're very much on track for the $30 million in hard synergies by the end of the year, and the team is doing an outstanding job progressing that.

In terms of the other, what we call -- I would call them deal value because we did make some assumptions on deal value. And I would put those in controllable and uncontrollable. The controllable variables are the asset performance and capital deployment, and both in terms of how the assets have performed and how much capital we're deploying against those assets. We're doing much better than what we showed on the deal value or the assumptions around the deal. And then the uncontrollable are the natural gas market and the methanol pricing market. And natural gas costs in North America have continued to be very competitively priced and priced lower than the $3.50 MMBtu that we assumed on deal value. And, of course, methanol prices have been -- have far exceeded kind of the $350 run rate numbers that we put out.

So across all the elements, the transaction is obviously performing extremely well. And it also shows the benefit of having fixed cost because all the uplift on price goes to earnings and cash flow. So -- but those are the elements. And today -- our job today is to control the controllables and continue to deliver on the integration, on the synergies as well as maintaining safe, reliable operations of the assets.

Next question comes from the line of Roger Spitz with Bank of America.

On Trinidad natural gas contracts, can you speak to why you were unable to agree on a new supply contract? How was Titan not contributing EBITDA or free cash flow in the second quarter?

Yes. I think -- so when we look at the way that the gas contract prices -- and the big reason why we idled, just to be clear, is the fact that we were unable to negotiate a future gas contract and that gas contract was coming to an end. So we did wind up terminating a gas contract earlier by a few months because we lived up to our contractual obligations. As it relates to the actual economics, the pricing under the gas contract is such that it's linked to methanol prices. Those methanol prices are linked to different regions around the world. And then when we assess that gas price against where Trinidad fits into our supply chain, the netback economics didn't make -- we weren't making money on it from that perspective. And the fact that we weren't able to -- we were talking about a gas contract that was going to be probably less favorable than the one we had at that point. And so we took the decision to idle the plant.

Got it. And then last, on the [indiscernible], they go current October 15. What is your thought on refi timing? Or given methanol price levels, maybe you think about just outright repaying the debt?

Yes, I'll turn that over to Dean.

Yes, Roger, you're correct. We have lots of options with regards to that in terms of as we build cash, our intentions to deploy it. So we haven't made a final determination as to early repayment or that. But we have lots of options that we're working through right now.

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

All right. Well, thank you for your questions and interest in our company. We hope you'll join us in October when we update you on our third quarter results.?

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

Good morning. Welcome to Methanex Corporation's Annual General Meeting of Shareholders. My name is Doug Arnell, and I am Chair of the Board of Methanex Corporation. We are pleased to host this meeting both in person and through a virtual meeting platform, accessible to all our shareholders regardless of physical location. I would like to acknowledge that this is a hybrid shareholders' meeting, whereby shareholders can attend and vote online as well as in person.

I would now like to officially call the meeting to order. In accordance with the company's bylaws, I will preside at this Annual General Meeting. Mr. Kevin Price, the Corporate Secretary of the company, is present and, in accordance with the bylaws, will act as Secretary and record the minutes. Ms. Zabrina Evangelista of TSX Trust Company is present and will act as scrutineer for this meeting and will assist in the tabulation of proxies and ballots.

The Secretary has in his possession the affidavit of mailing from TSX Trust Company as to due mailing of the notice calling this Annual General Meeting, the form of proxy and the Information Circular dated March 9, 2026. These documents were mailed to those who are shareholders of the company as at March 2, 2026, which is the record date. I direct a copy of the affidavit of mailing to be kept by the Secretary with the records of this meeting.

Company's bylaws provide that the quorum necessary for the transaction of business at a meeting of shareholders is 2 shareholders present in person or by proxy and representing not less than 25% of the votes entitled to be cast at such meeting. I've been advised by the scrutineer that as of the date of the proxy cutoff, there are 142 shareholders holding 64,397,175 common shares represented in person or by proxy at this meeting. This represents 83.27% of the 77,339,520 issued and outstanding common shares. Based on that information, I find that a quorum of shareholders is present and therefore declare that the meeting is properly called, duly constituted and able to proceed to the transaction of business.

With respect to voting, we will conduct the votes on the matters before us by a ballot. On a ballot, every registered shareholder and proxy holder entitled to vote on the matter has 1 vote in respect of each share entitled to vote on the matter and held by that shareholder. For those registered shareholders or proxy holders attending virtually, the ballot will be open for all resolutions at the same time. This will allow you to choose to vote on each resolution immediately or wait until the conclusion of discussion of each resolution prior to casting your vote.

For those shareholders attending in person, you will have an opportunity to vote through a paper ballot at the conclusion of discussion of all resolutions. Once discussion on all items of business has concluded, I will give you a period of time to enter your votes and then declare voting closed on all resolutions.

There will also be an opportunity for registered shareholders and proxy holders to ask specific questions -- questions specific to each resolution after the motion for each resolution. Registered shareholders and proxy holders attending online may ask their questions using the messaging function.

I now declare the polls open and we will commence the formal business of the meeting.

First item of business is the receipt of the Consolidated Financial Statements of the Company for the year ended December 31, 2025, and the Auditors' Report thereon. This material was contained in our Annual Report, which was mailed to registered shareholders and those beneficial shareholders who requested it. I now declare that the Financial Statements and the Auditors' Report thereon have been received by the shareholders as submitted to this meeting.

Now to the item of election of directors. Company proposes to elect 12 directors. They are: Jim Bertram, Paul Dobson, Maureen Howe, Don Marchand, Leslie O'Donoghue, Roger Perreault, Kevin Rodgers, John Sampson, Rich Sumner, Benita Warmbold, Xiaoping Yang. As I mentioned before, I am Doug Arnell, and I too am standing for reelection to the Methanex Board. As no other nominations have been received by the company, I now declare the nominations closed.

I will now call for a motion to nominate each of the company's 12 nominees for election as directors of the company, to hold office for a term expiring not later than the close of the next annual meeting of the company. Do I have a motion?

Yes.

Thank you. Is there a seconder?

Yes.

Thank you. Registered shareholders and proxy holders may vote at this time and may also submit any questions you have related to this specific resolution. We will now wait a brief period of time to allow for the broadcast delay and for time to submit the questions.

As there are no questions from the meeting room, I will now ask the moderator if there have been any questions submitted online that are specific to this motion.

Mr. Chair, no questions specific to this motion have been submitted.

Thank you. The next item of business is the reappointment of KPMG as the auditor of the company and to authorize the Board of Directors to determine the amount of the auditors' remuneration. I will now call for a motion that KPMG Chartered Professional Accountants be reappointed auditors of the company, to hold office until the termination of the next Annual Meeting of the Shareholders or until a successor is appointed and the Board of Directors be authorized to fix the amount of the auditors' remuneration. Do I have a motion?

Yes.

Is there a seconder?

Yes.

Thank you. Registered shareholders and proxy holders may vote at this time and may also submit any questions you have related to this specific resolution. We will now wait a brief period of time to allow for the broadcast delay for time to submit the questions.

As there are no questions from the meeting room, I will now ask the moderator if there have been any questions submitted online that are specific to this motion.

Mr. Chair, no questions specific to this motion have been submitted.

Thank you. The next matter for consideration is the advisory resolution with respect to Methanex's approach to executive compensation, often referred to as the say-on-pay vote. I will now call for a motion to approve the resolution set out under advisory say-on-pay vote on approach to executive compensation in the Information Circular dated March 9, 2026.

Do I have a motion?

Yes.

Thank you. Is there a seconder?

Yes.

Thank you. Registered shareholders and proxy holders may vote at this time and may also submit any questions you have related to the specific resolution. We will now wait a brief period of time to allow for the broadcast delay and for time to submit the questions.

As there are no questions from the meeting room, I will now ask the moderator if there have been any questions submitted online that are specific to this motion.

Mr. Chair, no questions specific to this motion have been submitted.

Thank you. That was our final resolution. For those registered shareholders and proxy holders attending virtually who have not voted on all of the resolutions, please do so now as I will close the poll in 30 seconds. For all registered shareholders and proxy holders in attendance, you may vote now, and we will collect your ballots.

[Voting]

Polls are now closed. I have now received the preliminary voting results from the scrutineer. With respect to the election of directors, I'm advised by the scrutineer that each of the proposed nominees has been duly elected. With respect to the resolution to appoint the auditors, I'm advised by the scrutineer that this resolution has passed, with approximately 77% voting in favor, and the resolution regarding the advisory vote on executive compensation has received the support of approximately 98% of shares voted. I declare all resolutions carried.

As there is no further business to be brought before this meeting, I now declare the Annual General Meeting terminated. If there are any questions that you have submitted that have not been responded to or if there are any other questions you may have, please contact our Investor Relations department. You can find their contact information on our website.

Thank you for joining us today.

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 2026 Results Conference Call. [Operator Instructions]

Thank you. I would now like to turn the conference call over to the Vice President of Investor Relations at Methanex, Mr. Robert Winslow. Please go ahead, Mr. Winslow.

Thank you. Good morning, everyone. Welcome to Methanex's First Quarter 2026 Results Conference Call. Our 2026 first quarter news release, management's discussion and analysis and financial statements can be accessed through our website at methanex.com.

I would like to remind listeners that our comments today may contain forward-looking information, which, by its nature, is subject to risks and uncertainties that may cause the stated outcome to differ materially from actual results. We may also refer to non-GAAP financial measures and ratios that do not have any standardized meaning prescribed by GAAP and are, therefore, unlikely to be comparable to similar measures presented by other companies.

Any references made on today's call reflect our 63.1% economic interest in the Atlas facility, our 50% economic interest in the Egypt facility, our 50% interest in the Natgasoline facility and our 60% interest in Waterfront Shipping.

To review the cautionary language regarding forward-looking statements and to find definitions and reconciliations of the non-GAAP measures, please refer to our most recent news release, MD&A, annual report and investor presentation, all of which are posted on our website under the Investor Relations tab.

I will now turn the call over to Methanex's President and CEO, Mr. Richard Sumner, for his comments, followed by a question-and-answer period.

Thank you, Robert, and good morning, everyone. We appreciate you joining us today to discuss our first quarter 2026 results. Our first quarter average realized price of $351 per tonne and produced methanol sales of approximately 2.2 million tonnes generated adjusted EBITDA of $220 million and adjusted net income of $23 million. Adjusted EBITDA increased versus the fourth quarter of 2025, primarily due to a higher average realized price, partially offset by slightly lower sales of Methanex-produced methanol. During the first quarter, cash flows from operations allowed us to repay $60 million of the Term Loan A facility, ending the period in a strong cash position with nearly $380 million on the balance sheet.

Turning to our operations in the first quarter. Our total equity methanol production of 2.4 million tonnes was slightly higher compared to the fourth quarter. Starting with our United States operations, we produced 934,000 tonnes at our Geismar plant and 195,000 tonnes at the Beaumont plant in the first quarter. Our equity share of production at the Natgasoline joint venture was 203,000 tonnes. Our U.S. assets operated at high rates outside of a short period early in the quarter when production was reduced in response to a significant short-term spike in natural gas prices in late January.

In Chile, we produced 398,000 tonnes in the first quarter, utilizing gas supply from Chile and Argentina. A third-party pipeline failure that occurred late in the fourth quarter was rectified early in the first quarter, and our plants operated at full rates for the remainder of the period. We're expecting to idle 1 Chile plant during the middle part of the second quarter, in line with gas availability during the Southern Hemisphere winter season.

In Egypt, our first quarter production was similar to that of the fourth quarter with the plant operating at full rates. The plant continues to operate well today, and we're closely monitoring the regional situation for any potential impact on its gas supply.

In New Zealand, we produced 158,000 tonnes in the first quarter, down moderately from the prior quarter. Despite the stable gas and production levels over the past few months, the structural gas outlook in New Zealand continues to be challenging.

Our equity production for 2026 remains 9 million tonnes of methanol. Actual production may vary by quarter based on timing of turnarounds, gas availability, unplanned outages and unanticipated events.

Now, turning to methanol industry fundamentals. The conflict in the Middle East, which began in late February, escalated into the second quarter. These events have significantly disrupted global markets for energy and petrochemical supply, including methanol, and we continue to monitor both short-term and longer-term impacts on global markets and our business.

The Middle East supplies approximately 20 million tonnes of methanol per annum to global markets, and this has been significantly reduced since the beginning of March. Thus far, overall methanol demand has remained relatively resilient with no significant signs of customer shutdowns or demand destruction. In Asia and China, which rely significantly more on Middle East imports that need to bypass the Strait of Hormuz, we've seen no trade flows from the Middle East non-Iranian supply and very modest supply from Iran into coastal markets in China since late February and believe that downstream operations have been primarily sustained through the drawdown of inventories. We believe this situation will be unsustainable in the short term, and we're working closely with customers to understand their demand outlook.

We're also trying to better understand the extent of damage to methanol plants and related supporting infrastructure in the conflict region, if any, and the length of time it might take to restore back to full operations, which is still unclear today. Given these unprecedented events, we've seen a rapid and significant escalation in methanol prices across all major regions through March and April. And we're well positioned in today's market with our advantaged asset base that continues to operate safely and reliably. As a result, we're expecting to see significantly stronger earnings and cash flows in the second quarter compared with the first quarter.

Based on April and May contract price postings, we estimate our average realized price for April and May is between approximately $500 and $525 per tonne. Assuming this pricing holds through June and factoring in produced sales volumes similar to those of the first quarter, we would expect a significant increase in adjusted EBITDA in the second quarter, consistent with the first quarter and adjusted for these higher methanol prices. It should also be noted that due to the timing of inventory flows, there will be delayed recognition into the third quarter of cost increases we're seeing now from higher natural gas prices linked to higher methanol, as well as higher ocean freight costs from higher bunker fuels.

We believe the current market dynamics could be prolonged for some time, and we're monitoring the medium- and longer-term impact and risks to the global economy. Our priorities for 2026 are unchanged: to safely and reliably operate our assets and supply chain; deliver on the OCI integration plan; and continue to progress our deleveraging goals. Based on our short-term financial outlook, we expect to repay the term loan of approximately $290 million in the second quarter. After the term loan is repaid, we will remain focused on directing the majority of our free cash flow towards the repayment of the bond due in 2027, while evaluating share buybacks with a smaller portion of cash if they represent an attractive investment for shareholders.

We'd now be happy to answer your questions.

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

Rich, a supply-demand question for you. And I know on the supply side, it's very, very fluid in terms of intel. But based on your best understanding right now, what do you think has structurally changed when it comes to methanol in the Middle East? And assuming Hormuz opens, how likely is it that Iran will be able to kind of go back to that run rate of about 9 million tonnes a year, give or take?

And then on the demand side, we know macro is challenging. We're seeing weak housing and construction. On methanol affordability, I believe there's a few small cracks in some of the smaller applications. So can you just discuss what you're seeing, the cadence of demand or how you're feeling about demand destruction?

Thanks, Ben. On the supply side, right now, we're -- it's difficult to get a read on exactly what could be sort of the longer-term impact on the supply side. There's a number of things that we're going to be trying to get a better read on. And so, it really starts with the infrastructure around methanol, and that would be the upstream. What -- if any, is there an extensive damage to upstream natural gas feedstock and related infrastructure? If there is, what will happen to gas allocations? Where will methanol fit in the pecking order? Has there been any structural damage to methanol plants or related logistics infrastructure? So all of those things we need to get a better read on in the -- as things start to stabilize, and we're not anywhere close to that today. So very, very, very important things for us to get a read longer term.

When it comes into the demand side, for us, we haven't seen the demand -- any significant signs of demand destruction. Obviously, affordability is going to be really important. We do think that as -- particularly in coastal markets in China, the longer the blockade is in place, the lesser Iranian product will be flowing into coastal markets there, and we do think that will put pressure on MTO operating rates. We've seen methanol prices now, around the world outside of China, in the $550 to $650 range. And it's really a supply issue. So demand side, of course, we're very concerned what this means around higher costs. Right now, it's really demand still pulling the supply in. But what this means longer term in terms of inflationary implications and which end streams actually hurt the most, it remains to be seen. So we're working really closely with our customers to understand their demand outlook, their affordability levels, what impact this has both in the short term and long term. So it's a difficult one to be able to give you a lot of guidance on right now, but it's all things we're monitoring.

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

I just wanted to approach the earlier question a slightly different way. In talking to sort of a variety of chemical executives, it just seems that the normalization in supply chains, let's say, if peace was declared tomorrow and the Strait of Hormuz were to open up again, it just seems the way -- from sort of reopening the oil and gas fields, just the way the pecking order of various sort of chemicals, energy sort of sources, feedstocks and the like will work, it may take as long as 9 months from the opening of the Strait of Hormuz, from the declaration of peace, for these sort of supply chains to normalize. And then, obviously, as you rightly said, we still don't know the full extent of damage, particularly in Iran and certain other Middle Eastern countries. So I mean, as I sort of compare that to what I at least see in terms of consensus earnings estimates for you guys, I mean, they have you guys peaking in EBITDA in Q2 of this year and then a steep fall off thereon after, suggesting to me the consensus seems to be baking in a sort of V-shaped recovery in sort of volumes coming out of the Middle East. So I would love to hear your thoughts about this.

Yes. I mean, in the opening comments -- thanks, Hassan -- I did mention that we think this could be prolonged for some time. And what that means is, we don't think it gets fixed in short order like that. That gas infrastructure is really important, and we do think that methanol probably fits lower in the pecking order. When you think about energy products for power or for transportation fuels and fertilizers for food, we likely fit somewhere down the line in the pecking order there. So it will come down to how quickly does all the infrastructure can it actually get up and running, including the downstream, as well as the upstream. And then, you also have to think that inventories throughout the supply chain are significantly lowered.

And we're not talking about just Asia Pacific here, even though it will be most acutely felt in Asia Pacific, but it's a globally traded market. And so, that's going to be drawing down inventories globally. And that's why we've seen pricing in the market run up globally. So we've got supply chains that have to be restored. We've got infrastructure that has to be back in place. We've got -- and on top of that, it's a 25- to 30-day transit time out of the Gulf. So we've got a lot of things that have to happen for these supply chains to come back. And it won't be -- our view would be that, that would very unlikely to be a light switch to happen.

Now, the big thing for us is, how quickly does the demand side shut down, and do we see that happening in a big meaningful way? And then, when product does come back online, the supply get ahead of the demand restarting and those types of things. So we have to be careful about what kind of whipsaws could happen on the other side of this, which we do think will be prolonged. So hopefully, that's a little bit more context on that one.

Definitely very helpful, Rich. And as a follow-up, could you just talk a bit about sort of -- in this sort of new pricing regime that we are seeing, China's role, particularly as it pertains to the coal-based methanol, obviously, on the cost curve now, it's positioned quite differently. And the reason I ask you this is, particularly over the last couple of weeks, certain sort of further downstream chemicals like acetic acid, which rely on methanol, seem to have been coming under fairly severe downward pricing pressure in -- on the spot market in China in particular. So, I just would love to hear your views about pricing, particularly in China and how certain elevated pricing regimes in other parts of the world may actually hold up even if China puts some downward pressure on pricing.

Yes. Thanks, Hassan. So for us, when we look at our -- the pricing in China, we definitely think that it's a demand-driven price more than a cost side price for us. And it's really driven off the fact that there's 11 million tonnes of coastal MTO that are -- is a ready and willing market. So where we've seen pricing in China going from methanol is in the $400 to $450 per tonne range, which is very consistent with what you've seen around the affordability back to [ C2, C3 ] pricing, which a lot of that's driven off of naphtha price. So we do think that we're -- we've been saying for quite some time, methanol is increasingly a demand-driven pricing. And then, what we've seen is that the China price -- outside of China, we've seen pricing going into the $550 to $650 range.

When we look at some of the downstream, you mentioned petrochemicals, and petrochemicals around methanol have been overbuilt. So even in the current environment, I'm assuming that a lot of the acetic acid that's come on stream over time has been a weaker -- it's been a weaker segment because of the economic -- the impact economically of what's happening. And then, of course, that -- those are consumers of methanol. So it's something we need to watch out for. Does that release more supply into the market if acid producers are lowering their operating rates? But we haven't seen a significant impact of that coming back into the supply base for us today, so -- but something we'll watch, highly driven towards a demand-driven cost curve for us. And that's on the basis that methanol is very different than other petrochemicals.

We're forecasting to see a supply gap in the next 5 years of 9 million to 10 million tonnes. And that's still -- that supply still relied on Iranian production, existing production, as well as potentially new projects. So I think for us, we're in a structurally tight market ultimately, and we do think that leads more to a demand-driven cost curve.

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

I'm going to ask a couple of questions on some of your marginal assets, and I'll do one by one. First, we talk about Trinidad. I've seen some of your -- so you obviously have a gas deal up for renegotiation later this year, one of those plants that are running. I've seen 2 of your [ nitrogen ] peers in Trinidad very recently sign very short-term gas deals. A third nitrogen peer has not been able to do so. Is that something you would consider doing? Like maybe describe the Trinidad environment, would you consider signing a short-term gas deal to keep the plant running, considering this very strong environment?

Thanks, Joel. I mean, right now, we're in discussions. Our gas contract is up in middle of September. We're in discussions with the NGC. We're considering all possible range of outcomes through those discussions, including a short-term deal, as well as the potential to have to idle the plants. It will come down to those NGC discussions. In the short term, Trinidad is an extremely tight gas market with LNG, ammonia and methanol, all operating below the nameplate capacity. And so, a lot of that's going to come down to those commercial discussions. But our team is looking at all possible outcomes, and also thinking -- we are looking longer term there and what optionality may come in. But we do think any new gas from Venezuela is quite a ways out and also carries risk on whether it can ever flow to methanol economically. So there's a lot for us to consider there. But yes, we would look at short term. We also are -- if we [ can't ] get, in the short and the medium term, to work together, we're also having to look at other outcomes out of those discussions.

Okay. And then, turning to New Zealand, obviously, just running the one plant there at quite low rates. Gas has been a problem there. And it looks like the Maui gas field might be closing end of this year, maybe making that situation worse. But what is the end game here in New Zealand?

So I mean, I'm going to start by -- I will kind of remind both New Zealand and Trinidad, while they represent over 10% of our production, it's less than 5% of our run rate earnings. So both these assets have performed extremely well for us over our history and operate extremely well. New Zealand, the issues around gas are not new to us. We've been seeing a deterioration in the gas supply for quite some time. And so OMV, our big gas supplier came out with an announcement that they would cease production on their Maui field by the end of the year. If that were to happen, we can no longer -- we no longer are capable of running our plant. So it's something we're working on with our gas suppliers, and we're looking at all options on how we monetize our gas position, including producing methanol or selling gas. And whatever we're doing, we're doing safely and reliably as we move towards whatever the resolution is going to be. But the outlook is tough, and it's structurally challenging there.

Your next question comes from the line of Jeff Zekauskas with JPMorgan.

In the event that your earnings slide up this year, what will happen to your cash taxes? Does your -- what would be the cash tax rate or responsibility in a much more profitable environment? And also, if you could comment on what would happen to your working capital? Would your receivables and inventories and payables go up at the same rate as sales? Or do you expect it to be faster or slower? Could you help us out on those issues?

Yes. I think I'll turn that question over to Dean Richardson, our CFO.

Yes. Thanks, Jeff. When it comes to taxes, our tax rate guidance of 25% does hold even in a different price -- a higher price environment. From a cash tax perspective, we have been guiding to the majority of our taxes being cash. However, in a higher price environment, the majority of our earnings would go to the U.S. And so, the percentage of our cash taxes would actually go down because of the significant assets and loss carryforwards we have in the U.S., given the acquisition and the build-out. So the percentage of our 25%, the cash tax would go down more towards the midrange of that. It would be about a 50-50 cash versus deferred.

From a working capital perspective, certainly, methanol price has a significant impact on receivables. So we would expect -- and we did see some of that even in Q1. We would expect that in Q2 as well when it comes to our flow-through to cash flows that the receivable balance would increase with the higher price. From an inventory perspective, given we have limited purchases, most of our inventories are based on our cost structure of our plant. So we would not expect inventories to move. And there would be some offset in payables when it comes to that. So net-net, yes, we would expect a higher working capital balance due to the increase in methanol price.

And then, for my follow-up, given what you've already seen in April and whatever normal seasonal considerations there are, as a base case, would you expect to sell more produced methanol in the second quarter than you would in the first, all things being equal?

It will be highly dependent on our sales, and we're monitoring our sales quite carefully right now because obviously, looking towards, do we start to see any demand deterioration? We're also being very careful in today's environment around how much we buy as well. So if we have flexibility to not be selling in this environment, we may not be -- if it means we're covering that with produced tonnes, just given the risk that we could see things change. So to the extent that we hold our sales levels the same, you would probably see more produced tonnes coming through. If we were to decrease our sales, you may see about the same. So it's highly dependent on what our overall sales are. The majority of the inventory we are bringing through now is produced product. And that's a big change since we brought 4 million tonnes of North America supply on with G3 and the OCI acquisition.

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

I apologize if I missed this in the prepared remarks, but I guess, when you're talking about your realized pricing, you seem to be implying a discount rate that maybe is in the high-40s versus you realized in the low-40s this quarter. I wonder if you can kind of confirm that.

And then like related with that, I thought when pricing is going up, the discount rate comes down as you're kind of catching up to that, and then vice versa when prices go down. So things seem a little bit backwards versus what I anticipate. So can you help me understand that?

Yes, Josh, well, for sure. What you're going to see is, when we think about the -- when we look into the second quarter here, we are expecting to sell a lower proportion of our sales in China. And that's mainly where we have flexibility on our sales and where we can reduce down the level of purchases. So that's sort of the plan today. And that -- what that results in is a higher discount because actually, pricing outside of China has higher discounts, yet a higher realized price. So we actually have higher and stronger average realized pricing when our discounts are higher. It's very -- a little backward in the way to think of it, which is why I tend to like to ignore discounts and focus on the average realized price as much as possible. But that's really the reason that you're seeing that.

Okay. That makes sense. And you made a comment earlier about some of the lags and some of the cost sharing agreements and that lagging into 3Q. That's also a bit longer than what I would anticipate. I don't think we've talked about those lags in the past really coming up. So if I interpret that right, it seems like you would over-earn a little bit in 3Q because maybe you're paying less on the equivalent gas basis versus what you would, and then, that would catch up. I guess, is that correct?

And then, is there a way to think about like how long those lags are? Are they actually a 3-month lag? Or is it just that it's increasing month by month and that's kind of the catch-up we're talking about, just so we can sensitize that from a cost perspective?

Those are -- that's a fair question. So it really is about inventory flows, and we have about 45 days of inventory. So you will see some of those costs coming through, but not all of them. It won't be reflective of today's market structurally in the second quarter. So there's a lag, probably about $30 million, $40 million of that 45 days that will be coming in, in the third quarter. That would be more structural in today's higher pricing environment. And that's both on the -- includes the shipping and the gas.

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

First question, just a follow-up on what was asked on Trinidad. So you mentioned that you're considering a number of options. For the Trinidad facility -- or the Titan facility, is it due for another turnaround after September 26? So like does the new contract need to be long enough so that you can fund a major turnaround?

The new contract -- no, there isn't a turnaround coming. But the economics of the existing contracts are -- the lion's share of the rents are going back to Trinidad. And any increase in any pricing means that it makes it very difficult for us to support running there. And so, obviously, a lot of this is going to be coming through the negotiations with the NGC. But I hope you understand that -- yes, that's -- obviously, we're progressing that. Indications look challenging.

Got it. Okay. And you did mention that New Zealand and Trinidad make up less than 5%. 5% of your run rate EBITDA or earnings?

Yes, 5%.

Okay. Got it. And then, my next question is about the OCI assets. I think initially, you guys provided an estimate of about $30 million of synergies that you're expecting to achieve. Can you just give a quick update on how that's progressed and what you still need to implement over the next several quarters to achieve that?

Yes. So those synergies come in, in the form of insurance, come in the form of logistics costs around terminal optimizations, come in the form of IT costs. It comes in the form of looking at how we optimize some of the sites that we have. We're in the -- things are progressing well. We're probably through some of the synergies. Others, we're actually carrying double costs this year like IT. So -- and we're progressing all that. We have a plan set out that by the end of the year, we should be through that. But we are carrying higher fixed -- we have a higher fixed cost carry this year to then achieve the synergies beginning in January of 2027.

Got it. It sounds like we'll see most of the benefits next year.

Your next question comes from the line of Hamir Patel with CIBC Capital Markets.

Rich, are you able to quantify the non-gas feedstock cost increases that you're seeing? And how much on a per tonne basis might that be once it's sort of fully apparent in Q3?

Non-gas feedstock costs.

Just your non-gas cost increases.

I see. So in the first quarter versus the fourth quarter?

Well, just by year-end as that filters through.

Okay. Well, it's mainly the costs that we're looking at. So if we think about -- I do know that there's some focus on how we get to our run rate numbers and what's in our cost structure that we're working on. The first one is our fixed cost structure, which the last caller asked about, where we are progressing to bring our fixed cost structure down through the year through the integration.

The second area is ocean freight. We've had a longer supply chain through Q4. We had some lag into Q1 around our longer supply chain costs. We have seen a weaker backhaul market over the past year. That's something we're managing very closely. In today's environment, though, things have changed quite a bit around freight. Our focus around freight is around avoiding any type of spot vessel requirements in our system. Spot rates, we have -- there's 2,000 ships locked in the Gulf right now, and supply chains have increased because products got to move longer outside of the Gulf to meet demand.

So spot vessel rates have gone up quite significantly, and the backhaul market has disappeared. So our goal today is to keep as little -- our ships also [indiscernible] product avoid any spot vessel requirements. And this is one of the competitive advantage we also have here is that we've got our own fleet, and we have no exposure to the shipping market. Now, our cost per tonne might be higher, but our cost per tonne is a lot lower than our competitors that face market rates today. So our attention around shipping has shifted here in today's environment, like a lot of parts of our business.

Great. That's helpful. And just the last question I had, in terms of your 2026 methanol production, what percent of that -- I'm guessing a very small percent would be spot.

Yes. In terms of our sales portfolio, we have very little in the way of spot sales. We do have some flexibility to put some product in the market. But today, our commitment is to our term contract customers, and that's who we're here to service. And we have long-term customers. We have term contract supply, which is a min-max commitment per month for their businesses. That's where our primary focus is on ensuring that reliability of supply today. To the extent that if our customers are unable to produce, we will have more product available into the market. But today, our commitment is to our contract customers.

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

Rich, could you talk about where MTO operating rates stand in China today and how that compares, say, to like a Q1 average?

Yes. So thinking back to -- maybe I'll take back to Q4. Q4 MTO operating rates were close to in the 85% to 90%. We saw Iranian supplies actually stay on the market in Q4 until around the December time frame. And then, what we saw was a gradual lowering of MTO rates through Q1. Q1 average is around 70%, 75% rates. And through March -- we think some Iranian supply was able to move through March and April, some limited volumes, 200,000 tonnes a month. MTO has been holding in around that 70% operating rate. But now, we're seeing a dramatic shift in coastal inventories in China, which, assuming this blockade stays in place and there's no product available in behind what's come in, in the last few months, we're going to see inventories drawn. And I think we're going to -- it's going to be very difficult for -- to see those rates continuing.

Great. That's helpful color. And then, just circling back to the guide for Q2, the $500 to $525 realized price through April and May, I appreciate that your -- the discount rate is moving up because you have less sales to China. If we just look at your realized price compared to the global spot average, your realized price tends to be above 100% capture on the spot average. But in Q2, it's shaking out closer to 92%. And so, I guess, just to ask the question another way, is the guidance -- should we think of it as conservative? Like, or are you factoring in potential price decrease in June? Just trying to get a better sense of why that guidance isn't a little bit higher.

I think, in an upward market, you're going to -- and I don't know how you're trending the spot price. But in an upward market, there is some catch-up through the delay of 1 month or 1 quarter. As an example, we set our European price, which is a quarterly price, back in March. And European spot prices have gone from -- at the time, I guess, we were down in the $500 level or slightly over, to now above $600. So there's going to be those lags even on a monthly basis, depending on when you're trending the spot price. It takes a month to be able to adjust to the then prevailing market. And so, I think there could be some -- the read there could be, because we've had a steady and significant increase in market pricing, and that's led to that difference.

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

Two quick questions. Just first, a bit of housekeeping. Just on the ammonia side, can you clarify how you're doing in terms of either ASPs or margins and kind of any kind of your baseline outlook for Q2, how much you've contracted versus spot?

And then, secondly, kind of higher level, given how stark the disruptions could be if the war continues and the rhetoric around the war potentially continuing several more months and all the bottlenecks that, that would imply, what are you hearing from customers about what they think it would take for the industry to undertake capacity additions elsewhere to fix the supply-demand balance?

Thanks, Laurence. To your first question on the ammonia pricing, we're -- we produce around -- produce and sell around 80,000 tonnes a quarter. And our estimates when we did the acquisition was around 50 million tonnes of EBITDA per year. And that was at a price of -- using a Tampa price of around $450 per tonne. It's now at $775 per tonne. That has climbed up over April and May. So we're obviously achieving a significantly higher earnings there, probably an uplift of $20 million plus per quarter at these prices. So that's where we are, and we are contracted there. So we do sell mostly contracted tonnes.

On your question around capacity additions, it's not something yet that I think the market is in discussions today. I think what we'll have to do is take a look at when things get resolved, and I do believe it will take -- people want to get a read on where things rest long term. Does the pricing support what you need longer term to reinvest in the business, which will be a function of many things, demand supply, long-term energy prices. Is there a raise to capital because a lot of people want to do it at the same time. Many different factors would have to be worked out before I think you'd see big commitments to capital. So we're in a wait and see here on where this actually lands, and certainly things that we're going to be monitoring very closely.

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

It could go to Rich or whoever. I mean, the question really is around this Iranian situation and the restart of plants in recent weeks. I mean, we've been reading about the restarts, but there doesn't really seem to have a clear path to getting product to market. So the question is ultimately, is there any indication that they're trying to recreate supply chains around the Gulf or around the Strait, either by a trucking or some other avenue to tidewater that would allow any volume of magnitude to actually get out? I mean, have you heard anything around that context? Or is the restart just really around testing the facilities as best you can tell? I'm trying to get a sense for why restart if you can't get the product out.

Yes. No, we're not hearing any of that, trying to get a different supply chain to avoid the Strait. And we do think the U.S. blockade is a very significant derailer in terms of trying to get -- move products out. So we haven't heard of any of that product. And again, everything has to move to China as well. So no, none of that has come to our attention, Steve.

That's great. And just one follow-up. Apologies for the background noise. Just wanted to ask about your operational cadence this year. I mean, are you making any plans that would differ versus your thoughts 3, 4 months ago around how to operate the assets this year, just given the tightness? I think Joel had asked the question earlier about short-term gas contracts. But even around the broader maintenance profile or anything else in your internal capability or levers to pull to run harder in this environment, is that being contemplated? Or is it still sort of the status quo plan?

Well, I think everywhere around the world in our asset portfolio -- so North America, we want to run 100%. Egypt, Chile, those are our assets that represent -- are well placed on the cost curve. Our operating strategy is always to run safely, reliably for the long term and then always enhancing how we can have reliability at the highest rates possible. Around Trinidad and New Zealand, New Zealand is a bit of a different story. The gas, actual contracts there are attractive, but we're running the plant very suboptimally because we're well below capacity, and the gas is -- it's a mature basin, and it's in decline. So if we were able to run there as a flexible asset, maybe we would. But it's really about the gas basin and it's structurally challenged. And then, Trinidad becomes more of a cost issue and really how does the NGC going to negotiate. If there was something that made sense in the shorter term, maybe we will look at that. And that was to Joel's point. But it'd to make sense in the short and medium term, and we would look at those options. But at the same time, we have to look at all possible ranges of outcomes out of those discussions, and that's what we're doing.

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

Thank you for your questions and interest in our company. Hope you will join us in July when we update you on our second quarter results.

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

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 Fourth Quarter 2025 Results Conference Call. [Operator Instructions]

I would now like to turn the conference call over to the Vice President of Investor Relations at Methanex, Mr. Robert Winslow. Please go ahead, Mr. Winslow.

Good morning, everyone. My name is Robert Winslow, and I recently joined Methanex as Vice President, Investor Relations. Welcome to Methanex' Fourth Quarter 2025 Results Conference Call.

Our 2025 fourth quarter news release and 2025 annual report were posted yesterday, and can be accessed through our website at methanex.com. I would like to remind the listeners that our comments today may contain forward-looking information, which by its nature is subject to risks and uncertainties that may cause the stated outcome to differ materially from actual results.

We may also refer to non-GAAP financial measures and ratios that do not have any standardized meaning prescribed by GAAP, and are, therefore, unlikely to be comparable to similar measures presented by other companies. Any references made on today's call reflect our 63.1% economic interest in the Atlas facility, our 50% economic interest in the Egypt facility, our 50% interest in the Natgasoline facility and our 60% interest in Waterfront Shipping.

To review the cautionary language regarding forward-looking statements, and to find definitions and reconciliations of the non-GAAP measures, please refer to our most recent news release, MD&A, annual report and investor presentation, all of which are posted on our website under the Investor Relations tab.

I will now turn the call over to Methanex' President and CEO, Mr. Rich Sumner for his comments, followed by a question-and-answer period.

Thank you, Robert, and good morning, everyone. We appreciate you joining us today to discuss our fourth quarter 2025 results. I'd like to start the call by thanking all our global team members for their continued commitment to responsible care and safety, which remains at the core of our company's culture. Over 2024 and 2025, we've had the best 2-year safety performance in our company's history, even as we navigated significant changes to our asset portfolio and supply chain.

As a demonstration of these results, we've had 0 Tier 1 process safety incidents over the past 2 years and recorded only 0.09 and 0.12 recordable injuries per 200,000 hours worked in 2024 and 2025, respectively, compared with the chemical industry average of 0.59 in 2024. These outstanding achievements are a testament to our employees and contractors continued focus on strong planning, hazard awareness and reliable behaviors.

Turning now to a financial and operational review of the company. Our fourth quarter average realized price of $331 per tonne, and produced sales of approximately 2.4 million tonnes generated adjusted EBITDA of $186 million and an adjusted net loss of $11 million.

Adjusted EBITDA was lower compared to the third quarter of 2025, as higher sales of produced methanol were offset by a lower average realized price, and the impact of immediate fixed cost recognition related to plant outages in the fourth quarter.

Turning now to industry fundamentals. We're closely monitoring the current events in the Middle East region and its impact on global markets and our business. Looking back on the fourth quarter, we estimate that global demand increased in China by about 4%, while demand outside of China was relatively flat.

The increased demand in China in the fourth quarter compared to the third quarter was driven by increased demand for methanol into energy applications and higher operating rates by methanol to olefin producers, the latter also being supported by high operating rates and import supply availability from Iran.

Steady imports from Iran, particularly through October and November, also led to higher coastal inventories in China, which pushed pricing towards the $250 per metric ton range. Towards the end of the fourth quarter, we believe seasonal gas constraints significantly reduced Iranian output leading to MTO producers reduced operating rates in response to decreasing supply.

Through the first quarter of 2026, up until current market escalations, our average realized pricing has been quite stable with some small increases on slightly tighter supply conditions. After considering first quarter posted prices and factoring in higher discounts -- customer discounts through recontracting for 2026, our first quarter average realized price is estimated to be between $330 and $340 per tonne.

The current escalation in the Middle East brings significant uncertainty to reliability of methanol supply to the market from this region. We continue to see significantly reduced methanol supply from Iran, and we believe it is also impacting operations and trade flows from other producers. This has led to an increase in spot methanol pricing in Asia Pacific and Europe with Chinese methanol prices now trading above $300 per metric ton and European spot prices now trading close to $400 per tonne.

Now turning to our operations, where our methanol production was higher in the fourth quarter compared to the third quarter. Starting with our newly acquired assets in Texas. We produced 216,000 tonnes at Beaumont and 186,000 tonnes from our equity share of Natgasoline. During the fourth quarter, Beaumont experienced a short unplanned outage and Natgasoline took a plant 10-day outage to reduce a -- to replace the catalyst that's important to environmental compliance.

We've been actively working with both of these manufacturing sites on integration plans, completing detailed reviews of systems and technical findings and are pleased with the progress to date.

In Geismar production was slightly higher in the fourth quarter as all 3 plants operated reasonably well, although we did experience some minor unplanned outages. In Chile, after completing a plant turnaround in September, we operated both plants at full rates for most of the fourth quarter, utilizing gas supply from Chile and Argentina.

During December, a third-party pipeline failure caused a temporary restriction on gas supply to our facilities, and this resulted in approximately 75,000 tonnes of lost production. The gas supplier developed a resolution to this issue in early '26, and we're now operating both plants at full rates, which we expect to sustain through April.

In Egypt, we had higher production in the fourth quarter as the third quarter was partially impacted by seasonal gas availability constraints. There's been stabilization of gas balances in the region, but some continued limitations on supply to industrial plants are expected going forward, particularly in the summer. The plant is currently operating at full rates, and we're closely monitoring the regional situation for any potential impact on gas supply to the plant.

In New Zealand, we produced 171,000 tonnes as increased gas supply was available in the nonwinter season. Notwithstanding the short-term dynamics, structural gas supply availability in New Zealand continues to be challenging, and we're working with our gas suppliers, and the government to optimize our operations in the country.

Our expected equity production for 2026 is approximately 9 million tonnes of methanol. Actual production may vary by quarter based on timing of turnarounds, gas availability, unplanned outages and unanticipated events.

Now turning to our current financial position and outlook. During the fourth quarter, solid cash flows from operations allowed us to repay $75 million of the Term Loan A facility and end the year in a strong cash position with $425 million on the balance sheet. Since the start of '26, we've repaid a further $50 million, and the balance of the Term Loan A facility is currently at $300 million.

Our priorities for 2026 are to safely and reliably operate our business and continue to deliver on our integration plan. We remain focused on maintaining a strong balance sheet and ensuring financial flexibility and our near-term capital allocation priority is to direct all free cash flow to the repayment of the Term Loan A facility.

Based on a forecasted first quarter average realized price between $330 and $340 per tonne and similar produced sales, we expect slightly higher adjusted EBITDA in the first quarter of 2026 compared to the fourth quarter.

We'd now be happy to answer your questions.

[Operator Instructions] Your first question comes from the line of Joel Jackson with BMO Capital Markets.

Welcome aboard, Rob. Nice to hear from you again. Rich team, can you talk about costs? So if we look at Q4, and we think of costs, not gas costs but other costs logistics, other things going on, can you talk about what does that look like into the first half of this year in Q1? It seems like costs have really elevated. What's going on? Are there any artifacts, some of the things going on with the OCI taking over the OCI assets?

Thanks, Joel. Yes. I mean a couple of points I'd make on cost is we did see that the unabsorbed costs come through. That's really about how the assets ran through December. We saw some outages there that just results in immediate recognition of those costs to the P&L. As we think into where we were, our fixed costs we would expect those to come down. Our ocean freight was probably a longer supply chain in the third and fourth quarter.

As we said, we do have probably a higher percentage of sales coming through in the last few quarters as we -- higher than we expect as we move into the new year with our contracted position. And then we have not yet -- we're not all the way through the OCI transaction. So right now, we are spending costs as we move through to create the synergies post deal, and that will happen through 2026 and when we get into 2027. So we're not all the way there, obviously. And what we do need to do is to continue the integration plans. And as we move through, we'd expect beginning in 2027, that our fixed cost structure also adjusts down to the new base of the business.

Okay. And then my second question is, obviously, you all know what's going on in the world. And there's a lot of methanol sitting in Iran and Saudi and around the Middle East. You obviously set your contract prices, your posted prices for March just on the onset of this. It's early, but what do you think is going to happen here in the market? Like if this continues, can you talk about what will we see in the short term, the medium term as you see your business potentially changing from what's going on?

Yes, for sure. I think for us, I mean, I think the -- our first -- and first priority here is our supply to customers. And I think this is where our reliability of supply and our global supply chain really shows -- demonstrates its value. And where we are today is that's our first commitment. Pricing has obviously increased in all regions with the anticipation of tightness coming out because the amount of tons on the internationally traded market here is quite meaningful that's currently impacted. So our first commitment is to our customers. And as of right now, we'll see some benefits because of the tightness on pricing through March, but the real reset will come through into the second quarter.

I think the big -- we're talking about around 15 million to 20 million tonnes of the globally internationally traded methanol market here. So it's a significant impact. which will ultimately impact all global markets, and we've seen pricing come up around the world, and we're watching things really closely here obviously, with our customers trying to make sure we keep them whole while also looking at the risks on the global market and potentially some demand destruction that could come out of the market as well. So watching things very closely, and we're really talking to all our suppliers about -- or all of our customers about how we can keep them supplied through this.

Your next question comes from the line of Ben Isaacson with Scotiabank.

I have a question and a follow-up. Rich, can you remind us how opportunistic are you able to be when we have price spikes? I know most of your volume is contracted. So can you just talk about how you can take advantage of short-term price spikes? And is there some kind of lag in that recognition?

Thanks, Ben. Yes, I mean, we're a term contract supplier. So our first priority is our commitment to our customers, and we reset price monthly. And so right now, we're selling based on our March contract price. And we would expect under current conditions that we would be resetting into April to be reflective of the market. So our first priority right today is the security of supply to our customers globally.

Of course, there are certain mechanisms in our contracts, which may adjust up slightly, and that's built into our forecast. So you could see that there could be a little bit of a push up in our kind of guidance on where pricing is for the first quarter. But generally, it will reset into April. And our first commitment is really about, how do we make sure we keep the industry operating for our customers and really to help them take care of their business.

Great. And my follow-up is in the Middle East. I know things are moving very quickly. Are you aware factually of any damage to methanol assets or export or port infrastructure in Iran? And are you seeing a slowdown in gas flow from Israel to Egypt?

Thanks, Ben. No, we're not aware of any damage to any methanol facilities. We're monitoring the situation really, really closely. As far as it relates to the gas supply from Israel and to Egypt, our understanding is that gas is not flowing that they've all but shut down the gas imports from Israel today. What we're working really closely with our gas suppliers in Egypt.

Our plant continues to operate. It is the low season in terms of demand on the gas grid in Egypt. And -- the Egyptian government has been getting in excess supply or more supply through LNG imports. So, so far, we've got sustainable operations there, but we're watching things and monitoring them really closely.

Your next question comes from the line of Hamir Patel with CIBC Capital Markets.

Rich, in your price guidance for Q1, you referenced new customer discounts for 2026. So how should we think about, how much maybe on an annual basis, those have shifted? And will that largely be apparent in Q1? Or will it adjust over the year?

I think the Q1 will be sort of -- is sort of the reset, Hamir. It's what we'll wind up seeing is that when we think about where our realized pricing is for Q1, if you go sort of region by region, China is going to be up because we saw that supply through Q4 built in China. So China is going to realize more in Q1. The European contract settlement actually results in slightly lower pricing for Q1 compared to Q4. And then when we look at where North America, Latin America and Asia Pacific are, they're kind of relatively flat on a realized basis.

So that should be a resetting the discount for 2020 -- or Q1 should be consistent through or a good guide for the rest of the year. And then on an average realized basis, we're expecting to be up a little bit. And this is all pre the current developments, right? So I think prior to the current situation, we were going to be slightly up mainly because of China and factoring in all those other considerations.

Okay. Great. And Rich, with respect to the 2026, the $9 million production guide, can you give us some color on some of the regional puts and takes embedded in that? I imagine the Egypt piece is probably maybe the most fluid.

Yes, I think it's -- we've got a -- you can think of it in terms of these numbers about 6 million or a little over 6 million tonnes in North America, about 1.3 million to 1.4 million tonnes for Chile, which is consistent with where we were last year, around 0.5 million to 0.6 million tonnes for Egypt, which is obviously less than around an 80% operating rate. And then Trinidad would be one plant would be really the Titan plant around 800,000 tonnes. So I think -- and then New Zealand our guide for New Zealand is less than 0.5 million tonnes, and that's because of the situation we're faced with in New Zealand on gas supply. So those are rough numbers to help you with kind of breaking that out by plant. .

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

I just want to go back to the discount issue or perhaps even just the weighted average global price just as we think about the shifting dynamics there. It did strike me that the realized price came in lower, but not just because of the discount but because of that global-weighted spread or global-weighted average, I should say. Has there been a material shift in the sales mix here in the last 2 quarters relative to prior? It does seem that the formulas we used in the past are becoming outdated.

No, I think, what we do is we give guidance in terms of percentages in terms of regional allocations there, Steve. So I think you can use those as a good guide. And I think the proportion of China was higher as we move through Q4 for sure. And that's partly because when we acquired the assets, we did inherit a fairly large uncontracted position from the OCI business. We've contracted into Q1 now. And I think the what you'd see is that if you work the percentages, and the pricing you get close to our ARP. But I think, we can help you with that offline, if it's, for some reason, it's not adding up.

Okay. No, that's very helpful. And just on the operational rhythm or cadence at the new facility in Geismar. It sounds like things are running well now. But just to give us a sense for again that cadence? Is it running sort of to plan, and you think you suggested even full rates? But I mean, is there anything else in sort of the tempo that we should expect to change over the balance of the year, whether it be turnarounds or other major hiccups?

Yes. No, we're pleased with the operations in Geismar. We've gotten through our the ATR challenges that we had, and we feel really good about the way the asset is running. So in a lot of ways, it's about just continuing to ensure safe, reliable operations in Geismar, and the team is doing a fantastic job there. So we're -- we've put those issues behind us. And right now, we've got a really good, stable production coming out of Geismar.

Your next question comes from the line of Jeff Zekauskas with JPMorgan.

I remember that you were less hedged on gas at Beaumont and Natgasoline. Is your hedging now consistent with your other North American plants, and when there was that gas spike at the end of January? Was that something that you felt or you were hedged against it?

Yes. Thanks, Jeff. We -- so our hedging today, what we're guiding towards is around 50% hedged for our North American assets, and that's across the whole portfolio. We did see gas pricing, as we always see, come up through the winter period, and then we did hit the gas spike. We'll talk more about our operations when we get to our first quarter results, but we would expect and normally expect gas prices to come up, and then we have different ways to manage that. So we would have had some open exposure, but we would have been managing disclose more about that in our first quarter. We do expect the gas pricing, and that's part of the guide. Really, when we look at slightly higher earnings, part of the reason that it's slightly higher and not higher is because there is a bit higher gas cost coming through in the first quarter compared to the fourth quarter, which we'll give more information on when we go to disclose that in the coming weeks here. .

Okay. And in Trinidad, do you expect your operating rates to rise relative to the fourth quarter or fall in the first quarter?

Well, we've got in Trinidad. We're running the one plant, the one -- the smaller Titan plant based on a gas contract for the plant. So we're expecting that operations should be very consistent. And yes, we'll operate that plant. Our main focus is going to be on gas contract renewals for the Titan facility. That contract comes up at the end of -- in September time frame, and we would expect to have good operations from that plant up until that time frame.

We are looking at the contract renewal already. Most producers are already in discussions for their gas recontracting, their feedstock recontracting in Trinidad, and we're making sure we're in discussions as ours comes up later in the year. But I would anticipate that we're running that plant at similar rates to last year until that time.

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

It's Chris Perrella on for Josh. As you had lower production out of the OCI -- the acquired assets sequentially. Can you just give us an update on the integration there and sort of what the cost puts and takes over the course of 2026 or what you guys are budgeting in there for the spend to get the synergies?

Yes. No, the first thing I'd say about the assets is we're really pleased with the way the operations are going there. We -- when we modeled this, on the acquisition, we used operating rates of around 85% to 90%, and we've definitely achieved over and above that since we've owned the assets. We're really impressed with the teams that we're working with, and we're really working collaboratively together to bring our global expertise and work with the expertise at both sites to create value from the asset.

So really happy with that. We did have some downtime in Natgasoline, and that was really partly an environmental compliance getting ahead of environmental compliance there and taking a proactive outage. And then we did have some minor downtime at the Beaumont plant as well. So really happy with the way the assets are running and as well as the other parts of the integration. What we did have is, we had, we said about $30 million in synergies that we were targeting to realize by the end of 2026.

We've realized some of those, but you also have to take on higher costs when you're integrating systems, and you're integrating teams and other things during that phase. So we're in the middle of that right now, and we'd expect to try to complete that as we move through 2026, and then have realized the $30 million in synergies as we move into '27.

I appreciate that. Is there a step-up in the spend there in the year? Or is that cost now kind of baked in on a go-forward basis, at least through the end of the year? And then could you just -- has the gas supply situation in Trinidad absent the contract improved since the events in Venezuela?

Yes. So to the first question about the spend there increased. I would say no. When we did the modeling around the deal, we would have set a certain assumption around operating rates, and we would have set an assumption around CapEx spend on average per year.

The two things I'd say to that is the plants have been operating above our assumptions on the deal. And the second thing is both of the assets have come off of turnarounds in 2024 and 2025. So really, the CapEx spend relative to where we had deal assumptions, which would have been an average are much lower in the early phase of the asset acquisition, which is good for us because we're in a deleveraging period.

On your second question, which is in regards to Venezuela, yes. So there's announcements about fields being developed there and for import into Trinidad. So that is a longer-term positive. When we look at the Dragon field that's recently been announced, the things I would say is, one, the size of these fields relative to the demand/supply gap, more than just the Dragon field needs to be developed. So there are other fields also being developed, but that's going to take time. It's going to take a lot of progress. And then ultimately, we're also going to need to ensure that the commercial agreements and pricing that is for that gas, allows that to make sense long term for methanol.

So there's a lot to be done there, and our focus is really on the short term right now is how we're operating our plants in Trinidad with a contract renewal that's ahead of us before any of this gas could come on.

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

Quick question on the supply/demand dynamics. Rich, you talked about potential demand destruction. Can you -- like I think you talked about in the past how MTO facilities are, like their economics are somewhat challenged. But do you expect a large reduction in MTO demand? And also from your customer perspective, do you have a sense of how price sensitive they are?

Yes. So thanks, Nelson. Yes, just there's a lot of dynamics going on, obviously, right now. So we've seen, just in terms of MTO and MTO affordability, to your point, the price in methanol is rising, but so is the price downstream for the -- in the olefins market, and that's because, it's not -- methanol is constrained, but so is naphtha, so is all the oil derivatives that come out of the Middle East, which means naphtha pricing has gone up, which means olefins pricing has gone up, which means that makes methanol more affordable. So there's a lot of dynamics at play right now. That's what's you're actually uplifting China price, but their pricing in the downstream has gone up too. So the affordability dynamics are changing as well.

So there's a lot in play. I think what's going to happen here is depending on the restriction on supply, it's going to be, okay, how does that supply get directed into which markets, and then what does that do to price? So we're watching things really, really closely. But right now, every -- all energy and energy derivatives are lifting up because the demand supply gap continues to grow every day that there's disruption in that region and not a lot of product flowing out.

So we're going to monitor this really closely. Our commitments to work with our customers and on security of supply, and certainly, we see the forecast would be there's going to be pressure until some relief comes into the market.

Okay. Got it. And then in terms of your production in New Zealand, it's staying relatively low in 2026. I presume that facility is marginally profitable. So I just want to get your sense on like what are some of the factors or some of the key factors you look at in terms of making a decision to potentially like mothball that last plant?

Yes. So I mean, really, it's coming down to gas production and gas development and production out of the field. These are very mature fields, and there's not outside of the existing fields, there's not a lot of new exploration going on. So our concern would be that we have seen the forecast continue to decline. .

And in that industry, you have to see capital going in, and you have to see development consistently happening for that to be -- for your operations to be sustained. So we're watching things really, really closely. Today, that we've got a profitable operation, but we are operating even when there's peak gas available, we're still operating at less than one plant at less than full rates, which is not ideal. So we're watching things really closely. And we're working with gas suppliers as well as the government to sustained operations, but it is a tough outlook right now.

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

Great. Could you talk about whether you're truly realizing the benefits of the OCI acquisition that closed in mid-2025. And just looking at the total company EBITDA in Q3 and Q4, it's roughly flat to Q2, even though like global spot methanol prices are also about flat, and I think the OCI acquisition should have provided at least $250 million in EBITDA. So is this just a function of, I remember Q3, you had some accounting headwinds, Q4, it sounds like some unplanned outages, but are you getting the benefits of that OCI deal rolling through?

Yes. So I think, maybe the way to answer this is just look at that -- if we look at kind of the numbers that we had on the deal at a $350 methanol price, we said it was slightly over $1 billion in EBITDA. So that would be $250. Methanol prices today are not at $350 per tonne, that's $20 lower across an asset base that's 9 million tonnes. So that's -- the big thing is price.

We're also pre-synergies on the deal, so we haven't realized the synergies. And I did describe there are some other things on cost structure that are slightly above what our assumptions would have been on the deal.

So as we see that some of those cost issues are transitionary. And I think we can get back to those numbers, but we certainly need the market to be a little tighter and methanol prices to be at the $350 level to hit the numbers that we disclosed. And in today's environment, we would be looking and thinking we're probably at least in the short term, going above $350.

Okay. Sounds good. And then what percent of your North American methanol production is exported? And should we think about applying spot U.S. prices to those export volumes? Or is that really still on like a contract basis?

We run our -- I think the way to think of it is we run our global supply chain, our assets through our global supply chain. So we give our regional sales percentages, and then you can see where our assets are located. So our -- we run things so that our product isn't assigned to any particular region. It's a flexible supply chain where we -- our main priority is to keep our customers full with in the most cost-effective manner to do that.

So I think it's a little bit more, you have to put it together on where the product is going and how much we're selling. And right now, we've got -- we would give you the global sales allocation, and you can see where our assets are located. And so we will have some cross-basin flows from the Atlantic over into Asia Pacific, but mostly the product stays within the Atlantic Basin.

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

I guess, first of all, just can you help parse what the current situation means for the market in terms of the near term? Like how much of the near-term disruption is shipping being rerouted, and to what extent, or how long do you think it will take for you to start seeing customers shutting capacity in response to a tighter market? Can you help sort of parse the near-term supply chain adjustment versus how you're thinking about the demand adjustment?

Yes. So thanks, Laurence. I think when we look at what supply is impacted today, you have between Iran that Iran puts into the market around 9 million to 10 million tonnes a year. And then when you combine Saudi Arabia, Oman, Qatar, Bahrain in other countries that are going to be impacted. It's probably another 9 million to 10 million tonnes of a 100 million-tonne market, but really a globally internationally traded market about 55 million tonnes. So this is a pretty big impact.

Of course, Iranian supply goes only into China. So that's a direct impact to the China market. And then the other product services, mainly the Asia Pacific region as well as some into Europe. So those trade flows today have stopped. How long this lasts, how quickly you can -- you work, you're going to first work off inventories, you're going to try and buy product to ensure security of supply. How long this lasts will impact. How long and how long people have on inventory will ultimately determine how long people can operate here. So our first commitment here is to our contract customers, and the security of supply that we provide through our contracts, and that's our #1 commitment, and we'll continue to monitor this as it evolves because it's certainly hitting methanol, and it's hitting a lot of other downstream oil and energy products as this develops.

And secondly, on your shipping fleets, given that you can reroute tankers more quickly than sort of somebody who's using the -- has a ship but that might be contracted to ship in other products rather than being committed to methanol. Should you be seeing a benefit in Q2 or Q3 from that? And can you help size it?

Yes. I mean, I think the main thing for us is that this is where our time charters certainly give us that security within our supply chain. And so we have very little spot exposure in our fleet. We've seen shipping rates double on a lot of the lanes that we do. And so it's more of a what does it do to our competitors versus what does it do to us to the extent that pricing has to go up to help our competitors cover costs to meet security of supply well, then that's going to be baked into the pricing that we can benefit from. So it's not an immediate like instant hit to our cost structure because we -- ours are fixed in. But we do think that, that partially is compensated through increasing price that's required to get other products into market. So again, that's another factor that we'll be watching. And certainly, this shows that demonstrates the value of our Waterfront Shipping company and having dedicated ships to our business. .

The last question comes from the line of Steve Hansen with Raymond James.

Just in the event that this conflict does last longer than planned or longer than some people might expect, how do you think about the incremental or excess cash flow coming in the door? Is it just going to accelerate the paydown of Term Loan A? How you've been at a fairly rapid pace thus far, anyways. But is that how we should think about that excess cash flow that comes in the door?

Yes. Our first commitment is to our balance sheet right now. We have, like I said in the opening remarks, we've got $300 million left on the Term Loan A, and that's our first priority for cash. Of course, we're going to monitor things really closely here. Volatility is important. You can have fly-ups, and then you can have reversals depending on how quickly things do change. But obviously, our first priority and commitment is to the balance sheet post-deal. And right now, obviously, this pricing environment is very supportive of that.

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

All right. Well, thank you for your questions and interest in our company. We hope you'll join us in April when we update you on our first quarter results.

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

Okay. Good afternoon, everyone. We're about to get started. Hello. My name is Kevin Price. I'm the SVP and General Counsel at Methanex and it's my absolute pleasure to welcome you to the 2025 Investor Day for Methanex Corporation. And that welcome is not just for you here in Toronto, but also the many people we have attending via webcast.

Now before I hand over the day to Rich and my other colleagues, I've just got a couple of housekeeping items to go through. First, a safety note, and this is for those who are in attendance today. In case of an emergency, the hotel will activate their emergency response team and if you hear an intermittent alarm, please stand by and prepare to leave the building and listen to the instructions given over the emergency voice communication system. Now if you hear a continuous alarm, please evacuate using the stairwells.

Now the stairwells for us, the main ones are just behind you. So there's also another set over to the right through where the food was. Now both stairwells, they lead to the rear alley and onto Bay Street by the loading dock entrance. And after exiting, please proceed north to the evacuation site at the Bay and Adelaide Center. And second, I would like to remind the audience as well as our listeners on the webcast that any information in the presentation materials are presented orally either in prepared remarks or in response to questions may contain forward-looking information.

Actual results could differ materially from those contemplated by the forward-looking statements. For more information, please refer to our 2024 annual and third quarter management discussion and analysis. And lastly, this presentation uses certain non-GAAP measures that do not have any standardized meaning prescribed by GAAP and are, therefore, unlikely to be comparable to similar measures presented by other companies. These measures represent the amounts that are attributable to Methanex Corporation and may exclude the impact of specific items.

And with that, I'd like to turn the presentation over to Methanex's President and CEO, Mr. Rich Sumner.

All right. Thank you, Kevin. Good afternoon, everyone. I want to welcome all of you. Welcome to those that are on the webcast, and also official welcome to all of you that are here with us today in Toronto. Thank you for taking the time on your busy schedules, and we're really excited about our Investor Day today. You will see that you have a Giftii in front of you, that Giftii is a replica of the Methanex dual-fuel vessels.

You'll also be happy to know that we had a different idea that got canceled, which was a stick-build methanol plant that you would have had to build and assemble, and you had to do that correctly to take it home. But we know better than anyone how hard it is to build a methanol plant. So I guess what I want to first say is I'm really excited to be here today: One, because it's the first time in 3.5 years; two, because it's the first for me as CEO; and thirdly, it's because we have such a great story to tell for shareholders.

I'm also excited that it's not just me and that it's my executive team joining me in the presentation. So I'm going to do a quick introduction for the team joining me today. So maybe just a raise of hand. So first, it will be Dean Richardson, our Senior Vice President of Finance and CFO. Next, is Kevin Maloney, our CFO -- sorry, our Senior Vice President of Corporate Development. I'm using my glasses necessary.

Next is Gustavo Parra, our Senior Vice President of Manufacturing. Next is Karine Delbarre, our Senior Vice President of Global Marketing and Logistics. And last, but not least it's Mark Allard, our Senior Vice President of Low Carbon Solutions. Some facts about the team here.

So we all started in our roles about three years ago when I took over as CEO. But across this group, we have about 150 years of Methanex experience across this group that will help me go through our story today. So a huge amount of experience, some more than others. And the other fact about the entire executive team is that we've lived in every and led teams in every major marketing and production site across the Methanex globe. So extensive experience, huge talent and very excited that they're here with me, and we're very proud to be leading this team at this point in the company's future.

Turning to the next slide. We will have a main presentation, the main presentation will be provided by that -- the team here. We are also going to do two panel discussions. The first panel discussion will talk about global manufacturing and really about how we manage our assets from a Center of Excellence perspective. And Gustavo Parra will host a panel discussion with Paul Daoust, our VP of Projects and Turnarounds. And Matthew Geary, our VP of Reliability and Asset Integrity. The second panel discussion that we will have will be on low carbon -- low carbon methanol is an area that we get asked a lot of questions about. It obviously is an evolving area. It has a lot of debts to it. So Mark will host a panel discussion with Renato Monteiro, our VP of Low Carbon Methanol Supply and Roger Strevens, our Director of Low-Carbon Regulations and Advocacy.

So on to the first slide here, and that is the theme of today. The theme here is Methanex turning the corner from investment to impact. Why the name? First, it's the investments we've done. We've had an intentional build-out of assets in North America. And combined with the OCI acquisition, this is really the cornerstone of Methanex's global asset portfolio.

How do we turn the corner? It's taking those assets. It's leveraging our global capabilities in manufacturing and sales and supply chain to then get to impact, which is really focusing on how you do that with a stronger asset base and focusing on free cash flow generation. Of course, it all has to happen also in the framework of the markets, and we'll talk about the methanol markets and why we think it's a very constructive market for us to be able to execute over the next few years.

So how will we walk through that story? The first section will be a section called methanol, a quietly constructive market. I'll go through the markets methanol supply and demand dynamics, talk about the existing structural tightness we see and how that actually gets tighter as we move forward in the next 3 to 5 years. The next section will be presented by Kevin Maloney. He'll talk about how we have transformed our asset base with that intentional build-out in North America. And that, combined with some of the gas basins for both Chile and Egypt, are supporting our base production today in prolific gas basins that really support our asset portfolio.

The third section will be on leveraging our global capabilities, and that will be presented first by Gustavo and he'll go through our Center of Excellence around manufacturing. Karine will then talk about our global leadership position and really how that's unique in our industry. And then finally, we'll talk about, again, how we translate all that into stronger free cash flow generation going forward.

Dean will present that section. He'll talk about our approach to deleveraging, getting a stronger balance sheet. And then I'll finish with our disciplined capital allocation, both a look back in history and then also thinking forward for the next few years. So we do hope that all of those things will weave the story on how we're turning the corner from investment to impact. Before I get into the first section, I do want to stop on the OCI acquisition.

For us, this was a transformative opportunity to acquire North American -- world-scale North American assets that access abundant North American gas supply. The acquisition price was lower than the brownfield reinvestment economics. We think that this was also an attractive time from where we are in the market cycle with no one building methanol plants and also the existing supply being constrained.

And obviously, this is a fit for our business. This is our business, methanol, and these assets are fitting -- fit very nicely into our business and should be easy to integrate. Now integration is never easy. What we have seen so far, though, is a really well-planned integration. I think we're seeing really good results from the assets. We're still very early, and Gustavo will talk about this.

In fact, this will be weaved throughout everyone's discussion. So Kevin will talk about how this fits within the purpose of investing in North America. Gustavo will talk about our approach to integration and how that's really important when we look at our newly acquired assets. Then Karine will talk about our global supply chain, which starts with our assets and how that bolsters our leadership position in the industry.

And then Dean will talk about actually integration time lines, how we're progressing on synergies. So it is a big theme, and it's a big focus. But so far, so good, and I really want to thank our teams, both from a due diligence perspective, but also from an integration planning perspective. Still early, lots of work, but things are going really well. So start of the first section. This is Methanex, we're calling methanol a quietly constructive market. Why are we calling it that? We -- I think everyone in this room painfully knows that commodity chemicals have been in a tough -- we're going through a tough period.

And we're not immune to it. But I think there is a difference in terms of the structure here, certainly on the supply side for methanol that makes it a quietly constructive market. So we'll go through the -- both the outlook for demand, which we do have a moderated outlook for demand. I think where we are today is a moderated outlook in terms of GDP growth.

We're also being quite conservative in looking at new applications. But even with a moderated demand forecast, you look at no one building new methanol plants and also the constraints on existing supply, we see a constructive market today and one that gets more tight as we move forward. I will start with demand, and we did think that we'd play a little video that contextualizes the diversified end uses of methanol and where it goes. So we'll start a video now, and please watch.

[Presentation]

Okay. So hopefully, that puts it into perspective. You can touch and feel a few of the places that methanol goes. I get the pleasure of presenting the first graph of today. There's going to be lots of graphs. This one, what we're trying to show here is achieve a couple of objectives. First is looking at the current makeup of demand in terms of the broad sectors of downstream applications as well as the regional breakdown.

The circles are meant to contextualize size of the markets. And then the colors are reflecting our views of demand growth over the next 5 years. So I'm going to start regionally. And when you look at -- starting from left to right, so we have the Atlantic markets, it's about 20 million tonnes of annualized demand. Asia, ex-China is about 15 million to 20 million tons of annualized demand. And then China is the biggest market, about 60 million tonnes of annualized demand.

So think 100 million tonne market or thereabouts. When we look at the breakdown, the first application is broad-based chemical demand. So think formaldehyde, acetic acid, methyl methacrylate, silicone. This is going effectively into endless consumer, residential, commercial applications, really GDP driven. And what you can see is the breakdown of our demand forecast. So green means over 2%. This is not -- we're not projecting big strong growth like we would have seen in the past. And remember that when methanol demand shows up, it shows up where industrial manufacturing will happen in support of global GDP demand growth. So China, what we look forward in terms of industrial production, both to support their local economy, but also export markets is where we see industrial production and demand consumption for chemicals happening.

You can see then we go over to Asia Pacific, which is slightly lower and then the Atlantic markets, which is where we kind of moderate down the most. The energy applications, this is where methanol is being used as a transportation fuel. It's in MTBE, which is a gasoline oxygenate as well as in biodiesel and the production of biodiesel. So those are the big two outside of China.

In China, they're using methanol as well to replace coal in boilers and kilns and as a cooking fuel. And that's where we see the strongest growth. Again, moderated down from what you would have seen in the past. The other thing I'd mention here is we haven't put any meaningful upside in marine demand into those numbers. So we've taken a conservative approach in terms of the outlook.

The last sector is the methanol to olefins market, and that's about anywhere from about 15 million to 20 million tonnes of demand, all in China where methanol is being used as a feedstock in the production of ethylene and propylene. What we see here is we've got a yellow with a question mark. And I think the reason you see a question mark is because of when I overlay the demand growth even with conservative assumptions and you overlay that against the forward look on supply, we do see a tightness there that we'll need to balance.

And when we look at -- in that frame, we think about that as a marginal consumer and the olefins market today is the marginal consumer. One thing to note is that within the next 5 years, there's going to be a start-up of 3 more MTO units, representing about 4 million to 5 million tonnes of demand. We haven't put that -- all of that into our numbers because of the constraint from a supply side, which I'll show in the coming slides.

Okay. So this next slide, two big points are. We're looking at what's the forecast of new capacity additions in the industry and also a bit more color and breakdown of why we say current existing supply is constrained. The graph on the left shows the forecast of new capacity additions in methanol. If you look at the dotted line, the dotted line shows average of the past 5 to 10 years. And then you look at the forward line, that's the average for the next 5 years. You can see that average is around 2 million tonnes a year, whereas in previous, we saw above 5 million. Really, that comes down to why is that? We've seen, first, the cost to actually build a new methanol plant has increased significantly.

And we've also seen the market today not pricing at a level that is really encouraging reinvestment in the industry. Those asset additions are mainly -- going forward are mainly in China. And I'd also say that when we look at the other areas, it's Middle East, which is mainly Iran. And when Iran has added capacity, they've had a real hard time actually delivering supply because of the gas feedstock constraints in that country.

So there's a question mark on whether that will actually result in production. So that's the first side. We move over to the right-hand side. This is the breakdown of the existing market. And what you see in a lot of analyst reports that study methanol is there's around 160 million tonnes of capacity. And then the industry operates at around 65%, 70%, which I always think is a very low number. And we're trying to break that down.

The first yellow line or yellow bucket there is plants that are effectively mothballed. In China, as an example, they've been progressively shutting down small inefficient plants. Plants were built out in a big way in the early 2000s. So these are plants that have been shut down for more than two years, 100,000 to 500,000 ton plants. The economic and political challenges to restarting are significant. Also in this bucket will be existing capacity that is structurally constrained because of feedstock. So think Trinidad, 8 million tonnes of capacity, operates 4 million to 5 million tonnes. Think Europe, 5 million tonnes of capacity, operating less than one million tonnes a year. Equatorial Guinea, a plant -- 1 million tonne plant that's been permanently shut down and gas rediverted into LNG. New Zealand, 2.5 million tonnes of capacity. We're operating one plant less than full capacity. So you really look at that as being significantly structurally constrained.

Then on the right, the next bar is talking about where you see seasonal restrictions or sanctions. So Iran has 15 million tonnes of capacity. They operate 9 million tonnes a year with added pressure as we see from sanctions. Russia is sanctioned, has 5 million tonnes of capacity, operates 3 -- and in the wintertime, we get significantly restricted in China as natural gas gets shut down and coal gets redirected.

So where we think effective capacity in the industry is more at around 110,000 tonnes. And when you think about a 100 million tonne market and you have to have plants turnarounds and there's always unplanned things that happen, we're at a really high required operating rate to meet current demand. So now we take both those, and we put them together. On the left-hand side, what you see is a 16 million tonne demand growth, which we talked about being moderated for GDP, conservative around new energy applications. So we have 16 million tonnes of demand, 9 million tonnes of new capacity split between China and Middle East -- we put a yellow line, which is at risk.

That could be at risk because of the new projects and their ability to actually deliver production or further constraints on existing supply. What you see there is a supply-demand gap of around 10 million tonnes. That's where ultimately, we all know demand and supply have to equal. And we do think what's that going to mean is pressure on the consumers in the industry. So what does that mean in terms of pricing? In the short run, ultimately, it will be driven by cost curve. The marginal cost of production, we foresee remaining marginal coal and natural gas producers in China.

But increasingly, as we move forward, we think that the price is set by the marginal consumer, and that's the olefins consumer. The olefins market has been structurally under pressure. When we look forward, the big rebalancing is what's being forecast. It will take time. We're seeing actions being taken in Europe, in Korea, in Japan. China is talking about anti-involution and its work back to chemicals. So it will take time, but we see structural improvement as we move forward.

Timing is dependent on demand and the pace of restructuring. So that is something that we're focused on. We think today, a reminder that the MTO affordability and the cost curve is really set in China and all markets trade at a premium to China, and Karine is going to talk about how that works in our portfolio and how we -- where we sell in the world and how that achieves an average realized price above that. In the long run, pricing ultimately needs to move back to encourage new supply into reinvestment economics. Given the current environment around commodity chemicals, we do think it takes time. So we don't project that happening in the next 3 to 5 years, but we will be looking at that very closely. What that means for our portfolio is with small structural improvement, we're realizing today $350 methanol price with small structural improvements.

We think that it bodes really well for us as we bring these new assets on and deliver really strong free cash flows. So that's the main conclusion. So -- I think we got a little summary here. Industry is constrained both from existing supply with limited new capacity. We think increasingly, it's the olefin market that we look -- we will be looking forward to get direction on pricing. It will take time to get back to reinvestment economics, but we expect that the structural improvement is going to be puts a really good environment for us to execute on what we need to do over the next few years. So with that, I'm going to turn it over to Kevin, who will talk about our investing in North America.

Thanks, Rich, and good afternoon, everyone. I'm really excited to have the opportunity to speak with you today about how we've reshaped and strengthened our business and give you an update on our producing regions as well. I'd like to start with this map and the visuals here because I think it really does a good job of illustrating our asset portfolio and how we think about it. What the size of the circles represent is the proportion of earnings that each region contributes to our overall run rate. And the colors of each circle represent our view of the gas risks or opportunities that -- in each region.

As you can see, North America clearly dominates our earnings generation capability with access to low cost and abundant natural gas. In Chile and Egypt, we have stable to improving gas supply conditions in both regions. And we have a lot more uncertainty in our Trinidad and New Zealand assets, which today, as you can see, don't contribute meaningfully to our overall business performance.

Over the next few slides, I'll describe the journey we've been on reshaping our portfolio over the past 15 years or so. And ultimately, it's a story about recognizing shifts in what was happening with the development of shale oil and gas in the U.S. And by taking a disciplined approach, we were first movers that took advantage of these developments. And we've been able to build out a very significant capability in North America that is now a considerable competitive advantage.

But before I get into what we've done in North America, I'd like to provide some context as to how the methanol industry has developed historically, what has changed and why we are well positioned for the future. First, when we think about some of our older assets like New Zealand and Chile, these developments occurred where there were stranded gas in basins that were too small for LNG developments, but also two large to develop for local market demand, typically gas basins with resource size is in the range of 1 to 3 Tcf.

This was -- this size of gas resource was the sweet spot for methanol. And this became the business model for project developers, locate smaller stranded gas fields near deepwater ports in countries you're comfortable developing a methanol project. This was the original business model, which led to the development of both New Zealand and Chile. The business model for methanol is, however, quite different now. In particular, as we entered the 2010 period, supported by advancements in shale drilling technology, we began to see upstream investment activity shifting away from smaller basins to larger, low-cost resource basins with shorter investment cycles like the U.S. shale basin.

And over the last 15 years, the business model for methanol has been about building or acquiring assets in the U.S., where there's a very significant large low-cost resource base. Today, we have a portfolio that includes 6.7 million metric tonnes of low-cost North American production capacity, which now accounts for 65% of our global capacity and 75% of our earnings -- our run rate earnings generation capability. And over the next couple of slides, I'll talk a little bit more about how we built up this capability and why we're confident about the gas outlook and our future in North America. Another interesting point about the shifting patterns in upstream investment is that we have two assets that are ideally located to benefit from our -- located to benefit from emerging shifts in upstream investment activity. specifically Chile and Egypt.

At a very high level, we're seeing meaningful upstream activity happening in other large low-cost resource basins, such as shale gas in Argentina and also conventional resources in the Eastern Med, and we believe both Chile and Egypt will benefit from these developments. I have a couple of slides where I'll talk more about these two regions in a bit more detail and share our perspective.

And finally, I'll come back to the slide at the end to quickly comment on both New Zealand and Trinidad. Now turning to -- back to North America. The chart on the bottom here shows the build-out of our North American capabilities. At a high level, without going through each addition of capacity, it shows us growing our North American capability, starting with the restart of our Medicine Hat plant, which we announced in 2010 and the plant came online in 2011. Then the build-out of our -- of our 3 plants in Geismar for 4 million tonnes of capacity and finishing with the acquisition of OCI's methanol business, which we closed earlier this summer. So in total, over this 15-year period, we've added an impressive 6.7 million metric tonnes of low-cost production capacity across 3 production regions in North America. As I'm sure you can appreciate, this is a significant competitive advantage for Methanex.

Not only do we have a low-cost structure. But as Karine will share later this afternoon, we're also well situated from a marketing perspective. Now turning to the chart at the top. This shows the history of gas production and pricing over the same period. And I think there are a few kind of key important takeaways from this chart. First, if you look at the -- looking at the blue line, from 2010 to 2025, gas production has essentially doubled, growing from around 55 Bcf per day to 105 Bcf per day today. It's a near 100% increase in the gas market.

Second, from a historical gas pricing perspective, looking at the yellow squares on the chart. And if we exclude the 2021 and 2022 period, which we consider a once-in-a-generation event, when the economy was coming out of COVID, compounded by the start of the Ukraine war, we can see that gas pricing has essentially been flat in nominal terms. So what this means is that gas pricing has been declining in real terms. At the same time, gas supply has doubled and easily kept pace with demand.

There are several factors that this can be attributed to some of the main drivers being the overall size of the gas resource base in North America, the amount of gas delivery infrastructure that's available. And one thing that I think is underappreciated sometimes is the significant productivity improvements that have been achieved with the development of shale resources. Overall, the main message on the slide here is that we've been very deliberate and measured about building out a significant capability in North America and doing so is we've gained increased confidence in the North American gas market.

Now turning to our outlook for North America gas. I have a few charts points to go through to provide some perspective on our views.

The first chart here is simply a visualization, which highlights the overall magnitude of the gas resource base in the U.S. The circle at the top represents current annual gas production in the U.S. and the circles below show how much gas resource is estimated to still be available based on analysis from the potential gas committee and also the U.S. Energy Information Agency, the key circle to focus on here is the third one, which shows that there are approximately 50 years or more of gas that can still be produced technically and commercially at today's conditions. So in simple terms, there's a lot of gas that's available to be produced in North America, which gives us a lot of confidence about our long-term availability of gas supply for our North American assets.

The next chart here does a great job highlighting the productivity improvements that have been achieved across several shale gas basins in the U.S. In summary, over a 10-year period from 2014 to 2024, new well gas production per rig has increased by 3 to 5x. That's 300% to 500% improvement considering that the cost of drilling is one of the most expensive aspects of producing gas. It's pretty amazing to see how much improvement has been achieved in a relatively short period of time. Now the improvements come from advancements and shale drilling technology such as just increasing the number of wells per pad, longer laterals with some producers now achieving laterals over 4 miles in length, better placement of wells and better fracturing technology, just to name a few.

Now it's totally a fair question to ask about whether these productivity improvements will be sustained going forward. But from a learning curve perspective and based on the data in this chart, it doesn't appear like the pace of improvement is flattening or decelerating yet. Plus, if you look at the investor deck so some of the main upstream players operating in these basins like EOG and EQT they're all continuing to set and achieve incremental productivity improvement targets. So for me, it seems sensible to assume that there's much -- there's more opportunity available here.

Finally, the last chart is simply the NYMEX forward curve through 2035, taken as of November 7. What this shows is that the forward curve over the 10-year period is trading essentially between $3.50 and $4, an MMBtu on a nominal basis. It's important to remember that the forward curve is not necessarily a prediction of future pricing, but more of a risk clearing market, where counterparties are willing to hedge and lock in pricing and returns for the business. What's interesting to note here is that despite expectation of increased demand for LNG and data centers, the curve is in backwardation, with pricing of the 10-year mark around $3.50 normally, so about $3 on a real basis.

Also, while we haven't shown it on this chart, industry observers forecast prices over time to reach $5 in nominal terms. So today, about $4 on a real basis based on the assumption that dryer gas from basins like the Haynesville are going to be needed to balance the market and that productivity improvements are going to slow down.

So based on the forward curve and forecasted prices, we believe a long-term range of $3 to $4 real is a sensible planning assumption for our U.S. assets. And as a reminder, we also have exposure to AECO for our Medicine Hat plant and AECO has been trading at around $1.50 discount to Henry Hub. So in summary, for all the reasons mentioned, first, we have a really very large low-cost resource base in North America, which is yet to be produced. Second, I think the very real possibility of achieving even further productivity improvements in drilling. And third, where the forward curve and forecasted prices -- where the forward curve is trading and industry expert forecasts future pricing.

For these reasons and others, we continue to believe there will be abundant low-cost gas or North American assets, which we believe makes our capability quite valuable. On this slide here, I wanted to briefly describe how we manage gas price risk across our North American asset base. In really simple terms, based on the chart on the left, we hedge a portion of our North American gas requirements using a laddered hedging strategy where we hedge a higher percentage of our requirements in the near term, and then this percentage steps down over a 10-year period. In the past, while we were building out our North American portfolio, we aim to hedge about 70% of our near-term gas requirements.

Now in the context of our current finance strategy, we are making a shift to take a little bit more open exposure and targeting around 50% in the near term. The 50% target is really aimed at striking a balance between protecting against gas price spikes and also benefiting from lower gas prices.

And as you can see from the chart on the right here, monthly gas prices over the last 10 years have mostly been below $4, with only a handful of monthly prices above $4. In fact, if we remove the gas prices from the once in a generation event from 2021 to 2022, there's only been one month over the past 10 years where gas prices have been above $4 Also, in terms of managing potential short-term gas price spikes typically linked to more extreme weather events that occur in the South or in the U.S.

We can also adjust our production across our North American portfolio. And given the scale and flexibility of our global supply chain, we could resell gas if it made more economic sense to do so. And finally, our 50% near-term target is not a hard target as we have the flexibility to increase our near-term hedge position if we see prices that we really like, but this will be done more so on an opportunistic basis. So in summary, we take a balanced approach to our overall gas price risk management strategy and have additional levers to manage short-term gas price volatility.

Now coming back to -- coming back about Chile and Egypt for a moment. As I mentioned earlier, these are 2 assets that we believe will benefit from the significant upstream activity that is taking place in the respective basins. First, let me take -- talk a little bit about Chile. The base load gas supply for our Chile plants, which is roughly about 40% comes from the state-owned energy company, [indiscernible], who is planning to maintain and grow its local gas production. Chile has also been benefiting from upstream activity in Argentina. Activity taking place not only in the Austral Basin in the South, but also from significant activity in the Vaca Muerta formation in the Neuquen Basin. This is a prolific shale gas basin analogous to the U.S. shale basins, which is estimated to contain over 300 Tcf of gas. To help put this into perspective, 1% of this gas or 3 Tcf would supply our Chilean plants for over 50 years. I was in Argentina about 6 months ago, and while they're in the early innings of the game there, what I observed from an upstream investment perspective was absolutely outstanding.

The pace of development activity happening there -- is happening very rapidly in Argentina as they leverage U.S. technology and experience, along with building out critical infrastructure like takeaway capacity and development capacity. The upstream developers in Argentina are working very hard to enable growth in both regional exports and also LNG developments. Ten years ago, we were only producing 200,000 metric tonnes in Chile.

And this year, we're on pace to produce around 1.4 million metric tons. That's a 700% change. We expect this trend to continue as upstream activity accelerates in Argentina, but the pace of our production improvements will likely be constrained somewhat by export policies and how these evolve over the coming years. At the moment, the current [indiscernible] government is honoring export regulations put in place by the previous government, which are in place through 2028, and we are not expecting major changes here. So in the near term, we expect to receive full gas to operate both plants for about 7 months during the Southern Hemisphere summer period and gas for one plant operation during their winter period, so production of around 1.4 million metric tons per year. Egypt is somewhat of a similar story.

The Eastern Med is a large conventional resource basin and virtually every oil major is exploring and developing oil and gas in the region. The gas resource base in the East Med is estimated to be somewhere between 140 and 500 Tcf of undiscovered gas. And given its local demand and existing infrastructure, Egypt is well placed to benefit from increased development activity in the region, both domestic and cross-border, and we expect this will improve overall gas supply security to the country.

As an example, earlier this year, the Cypriot and the Egyptian governments signed agreements to pave the way for gas exports from Cyprus to Egypt from the [indiscernible] developments. In Israel, Chevron and its Leviathan partners recently agreed to amend their 2019 agreement with Egypt export gas from Israel increasing volumes by 45% in the near term and then subject to a positive FID on its Leviathan expansion plans targeted for the end of the year, their gas supply commitment would increase by another 85% up to 1.25 Bcf per day over the 2030 to 2040 period.

Now while some of you may have seen that the Israeli Minister of Energy has said that he isn't approving this agreement at this point, gas supply from Israel to Egypt is, in fact, seen as a real success story for cross-border developments. And in the past, we have seen pragmatism prevail and think that's likely what will play out this time too. Also another important point that I think is worth noting is that we have a very strong relationship and partnership with the Egyptian government. And during times of gas supply constraints, which are typically seasonal in nature, we have been able to operate at high rates, including this past summer when we operated approximately 70% during this period.

So again, the main message here is that there is a tremendous amount of positive upstream activity going on in the Eastern Med and combined with our strong partnership with the Egyptian government and we expect Egypt to benefit from these developments.

Now coming back to the slide I started with. And to wrap up the discussion on our portfolio, I wanted to make a few comments on both New Zealand and Trinidad, as we can see from the map here, both New Zealand and Trinidad don't contribute meaningfully to our overall business performance. New Zealand is the oldest asset in our fleet, and it's currently celebrating 40 years of operation.

But for the past 5 to 7 years, gas supplies have been in significant decline. The reason for this is essentially twofold. One is that the gas basin itself is quite mature and developing new gas in the basin has become increasingly complex and to be quite frank, any recent upstream activity hasn't been that successful. And second, and probably the more important reason is that the previous New Zealand government implemented a policy in 2018 to ban further oil and gas exploration with other policies that made it more restrictive and uncertain for upstream development. While the current government has reversed the ban on gas exploration and implemented some other policies to improve upstream investor confidence, it's really difficult to say today whether these actions will also lead me enough to improve the situation.

Today, we're only producing at a rate of around 400,000 to 500,000 metric tonnes per year in New Zealand. And as we look forward in New Zealand, we're continuing to engage with government and upstream partners to encourage more upstream investment, but we're also taking prudent steps to manage and optimize our business there. Trinidad is similar, but slightly different story to New Zealand. What's similar is that the offshore basin supply in Trinidad are all mature at end of life. Production has gone from a peak of 4.2 Bcf a day in 2010 to around 2.5 Bcf per day today. That's roughly a 40% decline from peak production. But what's different and more important is that the country itself is highly dependent on oil and gas revenues.

So unlike New Zealand, there's strong political will of motivation to enable upstream activity in the region. Today, there are a few local offshore developments that are expected to come online in 2027, have the potential to slightly increase current production and sustain that for another couple of years. However, we currently expect gas supply and demand balances to be relatively tight through 2027. Ultimately, to sustain and grow production, grow gas supplies in Trinidad hinges on the ability to develop cross-border supplies with Venezuela, where there's a very large gas resource base but such cross-border developments require the right geopolitical conditions to enable.

Today, we're operating our Titan asset in Trinidad and producing around 800,000 metric tonnes per year. And even though we've got -- we've developed good capability in Trinidad. Continued operation will be largely contingent on the gas look and more importantly, our ability to secure future gas supply contracts to profitably sustain longer-term operations in the country.

So to conclude, there are a few final takeaways really to sum everything up. The main takeaway is that over the past 15 years, we've reshaped our portfolio and built a significant capability of 6.7 million metric tonnes per year of low-cost production capacity in North America. And this is greatly strengthened the business, enhanced the earnings and cash flow generation capability of our business. In addition, given the size of the North American gas resource base, the potential for further productivity improvements, along with the forward curve and forecasted prices, we continue to expect a long duration of low-cost gas supply for plants, making our North American capability quite valuable.

And finally, there are very significant and positive upstream developments happening in Argentina and the Eastern Med, and we expect both Chile and Egypt to benefit from these developments. Now before we stop to take a 10-minute break, we'd like to share a short video, which goes through each of our North American production sites and shares a little bit about each. Thanks.

[Presentation]

Okay. We're going to take a 10-minute break, and we'll come back with the rest of the first presentation. Thank you.

[Break]

So I think we'll get started in a minute here. So I'll just go through the agenda for the rest of the day here because I know I didn't complete that in the first discussion, but we'll go through the second half of the presentation here. We'll start with Gustavo talking about our Center of Excellence around manufacturing. Karine will talk about our global leadership position and then Dean is going to talk about our focus on cash flow generation as well as our strengthening of the balance sheet. I will talk about our capital allocation philosophy. And then we will end the first presentation. That will be followed by 30 minutes.

We'll take a quick break, followed by 30 minutes of Q&A, and then we'll go into our panel discussions. Okay. So with that, I'll invite Gustavo up to the stage.

Thank you, Rich. Good afternoon, everyone. Before I start talking about manufacturing, Rich mentioned about this 150 years of experience and to be honest, I got a little bit scared because I realized that 25% of that is me. So it's a great opportunity to talk about manufacturing and explain how we work, what our focus areas are and how do we deliver value to the business. So this slide is basically a representation of our global strategy. We really focus on those elements that you see there. But let me start talking about the effort that we put in working as one team using our Center of Excellence approach.

We put a lot of effort in transferring our knowledge working with our lessor lens using best practices. Part of that is our team that we have in region, we put a lot of emphasis in developing our team by using our competitive assurance process and also our professional development program. One example that probably reflects that is turnarounds when we execute turnarounds in region, we think about turnarounds as a global initiative for manufacturing and we deploy resources in region that bring expertise into that particular turnaround and then they go back into the other region being those learnings in a way that we continue to learn from each other. A few elements there basically are showing our approach in manufacturing. I will start talking about safety.

Safety is really #1 for us. We put a lot of emphasis in working safely in every site that we operate. We really focus on the health and safety of our team and really protected environment and also the community that we operate. Lots of effort in reliability, reliability by doing our proper asset management and operating that with excellence using our systems and practices and standards that we have captured for years of operating experience and also understand the asset, understand the risk and manage those accordingly.

In a way, the main message here is that have a global manufacturing strategy that focus in delivering safe, reliable, sustainable operations across our asset portfolio, and we translate excellence into value. A little more color on how we work using our global operational capability and our Center of Excellence approach. We start with a global manufacturing team that is driving our manufacturing strategy, they allocate resources to develop and deliver our key initiatives and also measure performance.

In the left side, you see what we call our global expert. They focus in asset assurance. They also manage reliability data and put a lot of emphasis in improving our plant performance. And then on the right side, we have our global functional teams that are basically focusing on delivering and the global key initiatives that we have in manufacturing are working together with the site management team.

So I will try to kind of reflect on all of this as an example, Kevin showed the video on North America and the two plants that we relocated from Chile. I have the honor to lead those projects years ago and kind of describe how this model works. You think about this, we have a team in Chile that we built there to find a way to dismantle the plant and find a way to make models of this plant and then put it in vessels and move it to the Louisiana through the Atlantic and over to the Mississippi River. We have another team in Louisiana that was preparing the plant, ensuring that we have the foundations in place to receive those modules and ensure that everything is prepared as soon as we have those models in place. We have to build a big bridge over the [ levy ] in Louisiana to bring those models across and installed this accordingly.

Everything fit very nicely. Everything came together very nicely. And then we commissioned and start up those plants very, very well in a year -- in a calendar year. And I have to say those plants are operating very reliable, very safely, and we added very quickly in 4 years extra 2 million tonne capacity. So that's in a way trying to reflect how this model works, and we have been unable to do that without the capacity and the talented team that we have in our company.

Moving forward to some of the performance metrics. This slide is showing our safety performance that have been -- we are very proud of that. We have been well below industry benchmark in both [ health ] and safety and also process safety. Notable for me is that we haven't had any major event in the last 2 years. You see 0 there. And that's because of the effort that we put in running those assets safely and protecting our people, as I said before.

On the top, you see our reliability performance over the last 5 years is an average of 96%. We do have a target of 97%. We are putting a lot of emphasis in removing all the defects that we have in our assets and manage the risk accordingly. G3 has been a really nice story now. The plant is running extremely well. We are very happy with that asset.

It's very reliable. We sort out all the initial operational issues that we have with the plant, and it's a really, really good plant, low emitter, high reliability and high efficiency. And lastly, our capital performance. We put a lot of emphasis in managing those based on risk and based on priorities and based on return of the business.

And the number that you see there, the $150 million is basically including our new assets in Beaumont. And we are going to work very hard to keep those numbers on those levels. OCI, Rich spoke about OCI and more colleagues are going to talk about that as -- we are really happy with the assets that we have, really excited what it's going to bring to our company.

We have a great team that are running those asset for years. Most of them enjoy and they said that they've worked very nice with us in learning from our background and our best experience in building and operating plans. I'm really excited to go through that process. A couple of comments there.

We have -- you saw in the video, our plant in [indiscernible] in Alberta. Beaumont has a lot of similarities in the front end of the plant with that particular plan. So we are bringing all our years of experience into Beaumont. And not gasoline is basically a copy of our Atlas plant in Trinidad that we have a lot of history operating those plants and learning from that particular asset.

So I will try to show a little bit of data or analysis how we really are focusing in bringing these new assets on. It's a lot of detail there, so I will try to highlight a few things there. We -- at the beginning, we knew that we need to engage the team well -- so we went back, we follow a very thorough onboarding program, and we are now following a process of competitive assurance and understand what are the gaps that we need to reach and how we work together. Main thing that we did and successfully achieved are the reviews on safety and responsible care.

We wanted to do that to ensure that we don't have major compliance issues. That we are protecting the environment well and we have good safety practices to manage our assets accordingly. Happy to say that we didn't identify any bit red flags, and we are going to work through the findings based on using our [ nonop ] processes. We did complete also a deep dive on the assets that we call Asset Assurance and we are going to probably talk a little bit more about that on our panel.

But also, we have a very good understanding on the vulnerabilities that we have in the plant and how we are going to overcome those in the next period to come. And lastly, all our technology is coming across. We have all the systems and processes that we use for years, and we are building that into our new organization. For example, we do have strong applications to monitor performance in the plant, and that requires a little bit of training for the new team to understand how we report back and how do we manage those issues. By closing, I think what I would like to do leave with you is kind of 3 messages. Safety is our top priority. We have a strong belief that safe plant is a reliable plant and a reliable plant is more production.

So that's the way that we think about this. We are focusing in ensuring and improving our reliability performance and efficiency across the assets and this will bring more methanol. And lastly, we believe that we have a Center of Excellence approach that our team worked together, and we've been valued to the business. So with that, thank you very much first. And with that, I will pass it on to Karine.

Thank you, Gustavo, and good afternoon, everyone. So you heard from Rich how the methanol supply and demand balances are getting tighter. And you also heard from Kevin and from Gustavo, how our reliable assets are becoming even more reliable and stronger supported by natural gas in North America. So what does this mean for our strategy, our marketing strategy? What you will hear from me on the next few slides is that we are the global leader in the methanol industry.

We have a global reach supplying customers in all major continents that we create value with our supply chain, our global supply chain, creating reliability for our customers, and a lot of flexibility. And those two elements are really critical in today's world where the methanol markets, as I said, are getting tighter, making reliability even more so valuable and geopolitical environment are creating added constraints when you want to move product around.

So I mentioned about our global reach. And as I said, we have access to all major consuming regions. We can do business pretty much with any customers around the world. And let me just explain what I mean by this global reach. We spoke about our global asset base. We have 6.7 million tons in North America, our assets in Chile, in Egypt, in Trinidad, in New Zealand. And from those manufacturing sites, we supply our -- the local demand first, and then we export to the consuming regions. To manage those exports, we use our own vessel fleet, which is a very key component. You'll see what I mentioned afterwards. And so once the product gets into the region, we have marketing offices around the world that make sure that through our extensive network, we make sure to deliver product to our customers on time.

So why is reliabilities becoming so much more important. As Rich explained, there is a lack of new capacity coming in the market. And if you noticed the new capacity is actually coming from China, from Iran and from Russia mostly. And brief point about China. It's mostly Inland coal-based Chinese production that we're talking about. It's about 50% of the global production that's coming from Inland China. And really, it's the market that's not truly accessible.

So the rest, as I mentioned, of those new assets are mostly coming from Iran and Russia. And today, our customers cannot buy product from those two countries, their sanctioned product. We also mentioned about the attrition that we foresee in the future. But just also to give you a sense of what happened to the existing capacity that's running today.

In the past 5 years, the production of the three world-scale plants that was built in North America was actually offset by the shutdown in Equatorial Guinea, in Trinidad and in Europe. So that really tells you how the non-sanctioned product is getting actually quite tighter. So that makes definitely reliability and flexibility, truly important features. And I would say that we stand out in the methanol industry with our capabilities. And as you can see on the graph on the right-hand side, we've put here our estimated market share, excluding, again, the inland domestic China market.

And methane exercise is twice as you can see, the nearest of our competitors. I would add that there's many producers in the world in methanol. There's a long tail list of producers after these few names you see here. And most of our competitors are actually regionally focused. They either run single -- their single plant operator or they run out of a single region, which makes them much less flexible when it comes to, as I mentioned earlier, sanctions or navigation restrictions.

And maybe a quick point on sanctions. About 30% of the global production outside of China is actually today subject to sanctions, it's a significant amount, obviously. And I just also mentioned about navigation restriction, and this is really very much felt in the Suez Canal. I am sure everybody is aware that there is significant restriction to go through the canal at the moment.

And it's truly impacting the ability for Middle Eastern producers to go through the Suez and bring product into the European markets. So we stand out very different supply chain that we are running with this very complex and comprehensive global footprint. Let me try to give you a sense as to not only how are we set up, what's the supply chain setup, but also how are we actually running our supply chain. It took us years to develop this very sophisticated end-to-end process that I'm going to try to give you a sense of.

So on this map here, we're trying to provide a snapshot. It all starts, as I said before, from our manufacturing sites. Those are the purple dots on the map. We supply local demand. It's mostly in South America, North America and in Europe that we supply regional local markets, and then we export the balance using our own fleet.

Waterfront Shipping is our subsidiary, manages exclusively Methanex methanol and brings product to the market. And they are today, contracting 30 deep-sea methanol tankers under long-term time charter. And what that means is that we actually control and direct where those vessels are going. It's a fully integrated fleet that we manage and can send constantly those vessels different directions. It's what those arrows on the map here represent. We have different options, obviously, as to where we send the product.

Once the product gets into the market, we lease about 25 terminals around the world. Those are the yellow dots you see on the map. And we also discharge into our customers' terminals, for instance, in the mediterranean sea, we have our Egyptian plant. And from there, we're going to be supplying customers directly into their storage facilities along the mediterranean coast.

And we dropped in about 70 terminals around the world directly into our customers' facilities. From there, once the product gets into the market, our teams, regional teams, we have 8 marketing offices around the world, take over the product and make sure to safely and on time, deliver it to our customers using all kind of mode of transportation, which I'll explain in a minute. Most of the demand, I would say, in China, in Asia and in Latin America is really along the coast, it's very close to those big import hubs.

But when you think about North America and Europe, there is a lot of inland demand, and we actually use what we call the hub-and-spoke terminal concepts where we bring product into these large hubs. And then from there, we dispatch the product to the end and location. And you can see that we have about 400 delivery points that we supply. And as I said, mostly in North America and Europe.

I just want to point your attention to the 1,400 railcars that we lease. It's mostly North America that we lease those cars, again, because there's a lot of inland demand. And Gustavo mentioned the attention we pay to the focus we pay to safety in our manufacturing site. And the same holds true for our transportation -- for the transportation safety. I'm very proud to share that we are one of the two chemical industry -- sorry, one of the two chemical companies in North America that have been awarded for the tenth consecutive year the so-called Grand Slam Award from the Class 1 railroad for no non-accidental release on their network. That was a mouthful, but it's a very nice testament of the -- of our dedication and focus on transportation safety. So that's the setup of our supply chain. How do we actually run the supply chain. We have an extensive team, very talented team that's constantly looking at supply and demand balances.

So looking at our production forecast, looking at our customer forecasts, and then making sure that we, in a very cost-optimized way, match both of them, making sure that we supply our customers on time. It's true for global movements, our global supply chain team as well as obviously, in region movements. We always focus on cost. We're running a commodity business, as you well know, and we are paying close attention to our logistics cost.

And from that perspective, we have a few levers that we use to minimize cost. We keep open position in each of the regions. So we are active in the spot market. We are purchasing in the spot market. And that allows us to balance supply and demand subject to the volatility and minimizes our transportation cost. We also organized swaps with coproducers.

And because we have such a global footprint, we are really able to organize several kind of swaps with many different counterparties and that those swaps obviously reduce your logistics costs. And lastly, Vodafone Shipping also minimizes shipping cost. And to do so, they use what we call back home. So they're bringing third-party cargoes into the ships rather than the ships returning back empty to the load region. And we actually bring over 95% of the vessels coming back from the Asian markets coming back to New Zealand or the Americas are actually carrying third-party cargoes, which definitely brings you revenue and reduces your shipping costs.

So in summary, we have a very extensive supply chain, a very sophisticated end-to-end process that we have developed over many years, significant improvement in -- sorry, significant investment in physical assets as well as in our teams around the world. And this brings a lot of reliability of supply, obviously, to our customer, and that will be our next topic. It's what's our customer portfolio looking like.

So on the left-hand side of this chart, you see the sales mix and the different delivery modes that we use to supply our customers. We sell about 60% of our volume into the Atlantic Basin, defined as the Americas and Europe. This is aligned, obviously, with the production profile we talked about earlier, but it's also aligned with our capabilities and the complexities of those markets. And you can see in the number of modes of transportation that we use, how much of these inland markets they are mostly in North America and in Europe. So we supply our customers by vessel and pipeline, that's the easy ones, and then we do a lot of trucking, barging and rail supply. And then obviously, we supply 40% of our sales into the Pacific Basin, which is the growing market.

So we're very comfortable that we have a high-quality portfolio. We have a good sales mix of geographically differentiated geographies and industries. We typically align with customers who are industry leaders, which means that they're growing and that they need suppliers who are able to support their growth. We also have long-standing relationship with our customers. 75% of our customers, we've done business for over 10 years. 50% of our customers, we've done business for over 20 years.

And in the past few years, I've been celebrating a few 30 years anniversary. And I can tell you that feels pretty special. It's quite neat. And finally, I point you to the graph at the bottom of the slide here, where you see the green, the bottom green line represents the China price. The blue line represents Methanex's global average realized price. And the gray bar represents the differential between those 2 on a dollar per metric tonne basis. So what does this chart tell us? We mentioned the fact that the China prices is under pressure. In the past 3 years, it's been below $300 and it's really a function of the pressure of the sanctioned product. China is the clearing market in the methanol industry, imports about 15 million tonnes, 2/3 of that is coming from sanctioned countries, it's Iran and Russia. And those 2 countries have no other home to go to, but China.

So definitely, a lot of pressure from sanctioned product, but also the fact that the MTO segment, which exists only in China is lacking affordability because of this olefin overhang that Rich mentioned earlier. So lots of pressure on the China price. When you look at our global ARP, our global average price, it is reflective of the sales mix that I just described. So those different geographies and those different markets that we serve, the region. The deep in-region market that command very specific service level and different requirements, those attract higher netback and premium pricing. So this is why our price in the past 3 years has been above $350 per metric tonne.

And now when you look at those gray bars, you see that they've been existing for a number of years now. Over 7 years, we've had a recurring differential over the China price. And this is really becoming a function of this -- the tightness of the non-sanctioned product. And we really believe that the international product is becoming tighter and structurally trading at a premium to the China price.

And these differentials are really exacerbated when you have supply disruption. And this is exactly what happened in Q4 and Q1 this year. I'll just give you an example to try to make you feel what I'm talking about. There was a number of outages that happened, unplanned outages that happened starting Q4 last year, compounded by some gas diversion in Q1. Some plants were selling to the gas grid rather than producing methanol. And the European market experienced a very significant tightness and prices in Europe increased over $120 above China.

And what we saw is that ultimately, trade flows rebalance, but this took a very long time to actually happen and the prices stayed elevated for a number of months. And the reason is that one element is that the producers are contracted. Customers want term supply, but producers are contracted. There is only a very limited amount of spot noncontracted volume.

So it's really difficult to actually have access to excess volume for one. And the second element is that, as I mentioned earlier, navigation is really restricted around the Suez. And guess what, to get to Europe, you have to mostly use the Suez to pivot from the Middle East. So it really creates a lot of length and time for flows to adjust or very high prices. It takes high prices to actually see those flows to readjust.

And because of our flexible supply chain, when such disruption happen, we're actually able to benefit and capitalize from it. We stop our purchasing activity, for instance, we redirect our vessels to those different higher netback regions. We organize swaps. So we have a number of levers to take -- to capitalize on these disruptions. So in summary, I hope you understood that we are the global leader in the methanol industry. We are in a very unique position with our very sophisticated global supply chain, a very integrated process that we are running that took us years to develop and would be very hard to replicate. It gives us a lot of reliability proposal into our -- for our customers and a lot of flexibility in a world that's becoming increasingly constrained by geopolitical events. Thank you for your attention. I'm going to now turn it over to Dean.

Thank you, Karine, and good afternoon, everyone. I hope you can see from the discussion that our full team is committed to operational excellence across the business and whether that's about investments, gas supply, supply chain, working capital, we're all focused together on a safe, sustainable business that ultimately drives strong free cash flow. I'm also going to talk about our balance sheet and update our leverage target. Starting with this chart here in the upper left, this builds off of Gustavo's earlier discussion on reliability.

And what you can see is we're talking here about onstream time. Onstream time is the combination not only of the reliability of our plants, but also of our feedstock supply. And so you can see we've split the chart between North America and rest of world. And when we don't have feedstock constraints, our plants run at very high rates. The rest of world has had its challenges as we've seen there. And I will point out that running at higher rates not only helps from a plant efficiency perspective, but Karine's talked about our global supply chain.

So you can think about how a stable supply of methanol and a predictable supply allows us to optimize our supply chain, things like backhaul, et cetera. The bottom left builds off of Kevin's discussion of our portfolio transformation. And it just shows the evolution over the past 10 years to where we now have a full 2/3 of our production capacity in the U.S. with a further 20% in Chile and Egypt, and 12% in Trinidad and New Zealand, which we were calling here a challenging outlook today.

If you translate that to earnings on the right, you can see our run rate at a $350 average realized price. And a full 95% is now coming gas basins where we feel we have a long, strong future with 5% in Trinidad and New Zealand. I'll take my turn talking about the OCI acquisition. I know it's been threaded through the presentation today, and this has been a full effort across our team over the past year or so. The due diligence phase, it was very detailed. It involved all our functions from manufacturing, gas supply, finance, et cetera. And of course, we had a long time to plan as we work through the approval process, culminating in the June 27 closing date. All this culminated in being ready to run what we call our day 1 to 90 integration, and we are ready to really get in there and make sure that we address the high-risk, high-value items.

An example I can give is with Karine's team who runs our marketing and customer service. Within 30 days, we had transformed -- or transferred all of the new customers, new logistics onto our systems, which not only allowed for continued reliable to supply to our customers and our new customers but it also allowed us to start getting after synergies, things like looking at terminal contracts, consolidating delivery, barges, et cetera. So that's one example of many that have done across the business, and we are making progress towards our $30 million synergy target. There's other things, of course, that are going to take a little more time, of course, IT systems and some of those changes, which involve multiple layers of people and processes. We're working diligently through that, and we are on target to hit our $30 million synergy target within that second year.

Of course, as a business, we're looking beyond that, that is the starting point. We've always said those are hard achievable costs that we know we could get at -- the real value here is running the plants at high operating rates. We've talked about how we -- on our deal, we sort of modeled them in the 90% range. And of course, our target is 97%. So Gustavo and team are working hard at that. We had a great Q3, which we're very pleased about. But of course, we're not sitting on our laurels that has to be sustained over multiple quarters and years, and we're working very hard at that. Karine similarly on the supply chain side.

So we think there's upside there, and we're working very hard to get at it over the next couple of years. This shows a bridge of our EBITDA evolution over the past couple of years. And you can see in 2024 when we had a $355 realized price, what we realized on EBITDA. And after adjusting for Trinidad and New Zealand, you can see what our building blocks to get to our current run rate expectations, particularly G3 and OCI, including the synergies.

We've -- I hope you've seen from my colleagues here that we collectively are very focused on delivering operational excellence to get to that level. And we do believe there is further upside through the newly acquired assets as well as Chile and -- Chile and Egypt gas supply, which in our run rate, we don't have full rates there. So we are looking to continue to deliver on that expectation.

One thing that's really near and dear to my heart, of course, is translating earnings into cash flow. And for us, that's defined as operating cash flow less our interest payments, our lease payments, our CapEx payments and all that's reflected here on this screen. And you can see that we do have a good transfer of EBITDA into cash flow, particularly when you think about the -- over the last 5 years, the capital that we've put into the business, and once you adjust for that and take Rich's comments that we don't have much growth capital in the horizon, we compare very favorably to a peer group.

This shows the last 5-year history, and towards the right, you can see what our run rate are expectations are and that we're working towards. And as a team, we are working very focused on that point there. Turning to the balance sheet. A strong resilient balance sheet is critical to us in the commodity industry. And when we think about this, we think through the cycle, so we know we're in a commodity industry, we prepare for low prices. And when we think about our balance sheet, we specifically think about a $300 to $400 window where we think it's reasonable to have a leverage target. So we're seeing our leverage target at 2 to 2.5x at a $350 price.

Importantly, down on the bottom left, you can see what that does through the cycle. And we're very focused on making sure that we have reasonable leverage through that range. We do prepare for prices below that as we go through crisis points that we know we've seen in the past, and we will see again in the future. And that is through protecting with a sustainable low cost structure and ample liquidity. From a leverage perspective, we think this is the right target for Methanex because of the protection it provides to shareholders through the reduction of risk. It is investment in great quality, as you can see on the right with our peers. That's really important to us because it provides us flexibility, low covenant structures and also Kevin talked about the hedging opportunities that we have and having a strong balance sheet and access to credit is critically important our business.

So for all these reasons, we think that this is the right target for Methanex and we're working towards that. Of course, as you know, in the near term, we are directing all free cash flow towards repaying our term loan A as our #1 priority. And in the next section, Rich will talk about how we're thinking beyond that as we move towards our ultimate capital allocation philosophy. So wrapping up this section, I think that it's really building on the work of my colleagues who have really talked about our collective efforts around portfolio transformation, delivering excellent can cash flows, ultimately having a strong balance sheet and preparing us for the future.

So thank you. I'll turn it over to Rich now.

All right. Well, thanks, Dean, and to the whole team for setting me up with a nice -- to be the cleanup hitter here. So I want to start by talking about capital allocation at Methanex. Our primary principles around capital allocation is to have a strong balance sheet, have a sustainable dividend. Find long-term value creation and then return excess cash for shareholders. And we think we have a really, really nice track record in terms of a balanced and disciplined approach here. And we think that the significant investments we've made in strengthening the asset base set us up really well for that. So I'm going to start with a little bit of history on our capital allocation.

And if you look at the graph on the right, that shows our capital allocation balance for the last close to 10 years. And now I'll point you to pre 2025. If you look at that allocation, have close to $2 billion in shareholder returns and about $1.3 billion in investment, and that was mainly G3. So the balance there, about 60% returns to shareholders via dividends and share repurchases. At the same time, building G3, which was done at $750 per installed tonne. So well, well, well discounted below where reinvestment pricing in the industry would be.

We're now -- obviously, the acquisition of OCI is the big focus. This, again, was an opportunity for us to acquire world-scale assets, North America feedstock immediate cash flows, no construction risk and no time frame of a new build. So our big focus now, as Dean said, is on deleveraging. I'm going to get to that in a few slides, but really a balanced approach, and we believe we're set up well for how we move in the future here.

This next slide shows a little graph on our production per 1,000 shares and how that's grown over time. So if you look from 2015 to today, we've doubled the production per share on a 1,000 tonne per share -- 1,000 tonne share basis. I'd say you can also see that, that has been done 2 ways, adding capacity, but at the same time buying back shares. I would also highlight that we think that, that's a significant improvement in the asset base itself. So the quality of the production that's in those -- in that per share production is something that we think is significant and, and we certainly recognize when we look forward.

Now the time frames and capital allocation. So Dean spoke to it, I think when we're looking forward and we're setting our target leverage to 2x, 2.5x, you can think of this -- these bars as being around a 2- to 3-year time frame. Our first focus is on the left-hand side, and we -- our commitment to shareholders. And certainly, the feedback we received when we did the OCI transaction was about balance sheet and balance sheet focus. And we've committed to getting ourselves back to 3x debt-to-EBITDA, which is our pre-deal leverage. You can think of that as the term loan A number. There's $425 million on our term loan A at the end of September, but we're also carrying excess cash around $100 million.

So on a net basis, it's probably $325 million to $350 million left to go. Once we get there, we're still thinking majority focused towards debt. We have a 2027 bond coming due, it's a $700 million bond and our target is approximately half of that to be paid down and then refinance the rest. So you can also see that we acknowledge that today's share price is very attractive from an investment opportunity to buy back the company for existing shareholders. And so we're also looking to start to return cash to shareholders.

Where that leaves us is once we made progress on the deleveraging, we're going to position where we're really, really well positioned from a flexibility perspective to be able to either step into the market in an increased way to buy back shares are also positioned for longer-term growth. Again, over these 2 to 3 -- on a 2- to 3-year time frame, we're not expecting to be making any big decisions on major capital. So we're set up really well from a cash flow perspective.

And I do want to start by reiterating the point around the debt. We do think that having a lower debt target, that there's a perception of risk on our industry that's really important. We think that getting the debt to the right level broadens our set of shareholders as well and helps us close the valuation gap that we see today. So certainly a big focus for us. So where do we want to be? The left-hand side says as a -- for our business, we want to be focused on our sustaining CapEx. Gustavo talked about that as a big focus is making sure we get safe, reliable assets, while at the same time optimizing our, our capital.

We have a commitment to -- we're going to -- as we delever, we'll take down our interest and lease payments over the next few years and we have a commitment on the dividend. And one thing that we have a minimum commitment there that it's a commitment to the overall dividend level that we see today. So we're close to $60 million a year in dividend payments. We're committed to that cash outlay. So as we buy back shares, should increase yield for existing shareholders. Ultimately, we want to get to our target leverage. And on the right-hand side, we think it positions us extremely well for flexibility in terms of how we invest on behalf of you, the shareholders. And this is just a snapshot.

There's a lot of different pieces of information here. I think I'll start with the chart on the left -- the bottom left-hand side, which really talks about our share price performance. And you can see that clearly, the commodity chemical space has been very challenged over the past 3 years. Our share price has performed, obviously, reasonably well, relatively well. But we still see a lot of upside. And the graph on the right-hand side talks about our free cash flow yield at -- on either consensus basis or a run rate that Dean spoke to. That's a very high yield, we think, very inexpensive cash flows, certainly an upside valuation for shareholders.

The other -- on the top left-hand side, I do want to highlight that we obviously are always talking about risks. We're always talking about where the pushback on the shares is. And we'll highlight some of the big ones, which is methanol markets and macro risk. I hope we've -- I believe we've shown the structural constructive forces around methanol that we of today and as we look into the future. The other is around asset performance, G3 and the newly acquired assets. I hope you believe we've shown how focused we are around our center of excellence on both our newly acquired assets as well as our existing platform.

And then the last part is around leverage in the balance sheet. And hopefully, you also see that we are very focused on that. So all around, we see a lot of upside for shareholders, and we're really focused on delivering results. So just to pull it back. We think we've had a long history, a very balanced and disciplined approach to capital allocation with our -- underpinned by our over 6.5 million tons of North American supply as well as our assets in Chile and Egypt that provide really stable gas and prolific gas basins to support production there. I think we're well positioned for strong free cash flow and also taking a very balanced and consistent approach to capital allocation. So final takeaways.

Well, I think I'll just walk you through what we believe we showed is a quietly constructive methanol market, how we've taken assets and our investments in North America, including the OCI acquisition to really make the cornerstone, that the cornerstone of our production to transform the business. Focus now is on taking that and leveraging our global capabilities and Gustavo and Karine talked about that. And then converting that strong asset position into free cash flow generation and disciplined capital allocation. And ultimately, that's all about turning the corner from investment to impact for you, the shareholders.

So that ends the presentation. I really want to say thank you. We're going to take a 10-minute break. We're going to come back, that will give you some time to think about questions. We're going to come back with a 30-minute Q&A, and that will be followed by our panel discussions. So thank you very much.

[Break]

Okay. So welcome back. We're going to start the 30-minute Q&A. We're going to do a balance of the questions from the audience here as well as there are some questions coming in from the webcast. So we're going to start it off with questions from the floor here. And so why don't we -- yes.

Ben Isaacson from Scotia. I have 2 questions. First question, if we don't think about New Zealand, is it possible that each plant can be free cash flow neutral or positive at all points in the cycle. Is that an aspiration or is that possible?

No, I'll -- I mean, right now, we -- first and foremost, even Trinidad and New Zealand are free cash flow positive, and that's an important element to both -- at certain points, we have flexibility, okay? So now the other assets that we see today are assets in Egypt, Chile and the U.S., we see those very much on the low end of the cost curve. So in terms of operating at all points in the methanol cycle, that's an important thing that we do in terms of when we look at an asset and when we run it for long term, we try to get a gas price that does allow us to do that. So we think we're very comfortable in North America, Chile and Egypt. And then right now, we're very focused in both Trinidad and New Zealand about ensuring that we're free cash flow positive, and obviously, pricing would impact that.

And then just a follow-up question. You showed on one of the slides, the operating rate of the industry. And my question was, if we go back in time and this maybe 20 years ago, when methanol prices were super high, maybe $1,000 a tonne. How much did the industry operate at when there was an incentive for everyone to make money, what was the most we've ever seen in the industry?

Yes. I mean, going back in time, and I can get some of my colleagues' views on this, but we've almost always seen an operating rate in the industry 70%. And a lot of that is because of the capacity in China. Capacity in China has changed over time because we've got to think that half of the global methanol production is there. What we have seen is that in China, you had inefficient plants that operate at lower end of the rates. So that meant China's operating capacity was limited to around 60%. We have seen, as they modernized plants, they've been able to get higher.

But you've always, always seen the industry operating at 60% in China and then 70% outside of China, and we've had this average because of the constraints, constraints have been there, but we are seeing a significantly increase in constraints, particularly because of geopolitics as well as certain gas basins and being mature. We also have to think that there's been a pretty big run on LNG pricing as well, which means diversion of gas into LNG, it can make more sense from a [ naphtha ] perspective. But maybe, Karine I don't know if you -- longer-term operating rates, what's the highest we've ever seen us be able to do even when methanol pricing was extremely high.

Yes. I mean I would have to go back, obviously, to see the data, but as you described, today, there's not a lot of latent capacity for sure. And in the past, it was a bit more, but we've seen this massive rationalization taking place in China. That really means that in the past, call it, 4 for 5 years, China has been operating at a very high level even though when coal prices were high, coal prices were low, we've seen some pretty sustained high operating rates in China, and we really think there's not much latent that was much more in the past, those years you just mentioned, it was definitely more.

It's Joel from BMO. I'll ask 2 questions one by one as well. Maybe Rich and team kind of together in -- let's connect your dots. So you've shown a lot of slides today. So what you're saying is you generate a 350 methanol, about $500 million of free cash flow, correct? And when you pay off the remaining 325, 350 of the term A of the loan, you'll get into a more balanced capital allocation with buyback and debt, okay? So $500 million free cash flow you want to pay off half of the $7 million of the 27s over a couple of years, the 27s. So that's about $175 million a year. So $500 million free cash flow, $175 million of debt repayments starting after you started buyback, you should be doing a 300 million on your buybacks. Is that correct?

Well, if you look at where -- how it will pace, we're going to be mid next year when we about -- this is depending all methanol price dependent, but it should be sometime mid next year a little later when we get past the initial deleveraging. We have now a little over around, I think, Dean, around 15 months to go until we have to refinance the 27 bonds. So we're going to need to build up that 350 over a shorter time frame than two years. So it will probably be -- what we would expect is it will be lower on share repurchase lower than $300 million for the next 15 to 18 months following our initial deleveraging.

Okay. My next question is looking at Slide 35, which is showing how your average realized price premium has really expanded for the last 5 years or so over the China price. And obviously, we talk about the posted price premiums over many, many years. So obviously, your mix changes now even more with Beaumont, not gas in that you have a bigger North American mix. Can you -- why will the premiums stay where it is over China? Other concerns you may get normalization and that premium comes back down, ignoring mix effects that you now have more or production.

Yes. I think Karine explained it well when you said, when you look at where a lot of those constraints are happening, those -- the constraints on supply in the industry are happening in, in volume that is non-sanctioned internationally traded, and that market is getting tighter. And as we look forward, we -- demand continues to grow, but no supply is being added into that market. And so when we move forward and on top of that, what we continue to see is greater barriers in terms of tariffs and other dislocations that's disrupting supply. .

So what -- where we see things is there is a structural premium there and that as things get tighter, that's going to come under more pressure. And when there's a dislocation like the one we talked about earlier with the Suez Canal, then that actually makes that temporarily expand even greater. So where we are today is we think there's a structural premium that stays and it likely gets stronger as we move forward and that increased dislocations probably stretch that for periods of time as well. I don't know, Karine, if you have anything else to add to that.

I think you have summarized it really well.

Josh Spector with UBS. I wanted to just follow up on the change in the leverage target. And kind of why now? So a year ago, you thought less than 3 was right. You talked about the peers, but I think if you look at that peer list, 60% of them aren't covering their dividend or recently cut their dividend to address free cash flow. So you guys have significantly outperformed, I think, in what's been the bottom of the cycle from cash generation. So why now do you think you need to go lower? Why not consider terming out that 2027 loan to push that into multiple tranches versus, say, today, you need to pay half of that off?

Yes. For us, we certainly -- when we did the OCI deal, we got a lot of feedback on the balance sheet and is at the right level for a company like ours. Taking a look at where we want to be through the cycle, and we really are looking at $300 to $400 range, meaning a low to high cycle as a normal cycle for methanol. We think that, that firmly puts us even at the low end of the range at a 4x debt to EBITDA. I think that, that is value for shareholders, because there's a perception of risk and asymmetric risk to the downside in terms of taking risk on Methanex, which broadens the shareholder group.

At the same time, it makes us more opportunistic, too. So when it comes to share buybacks, when there's a big dislocation, it makes us more opportunistic there as well as being positioned for longer-term growth. I think being a cyclical commodity is tough and getting the right leverage is really important. It's important for the long-term value for shareholders, and we think that, that's the right level for us.

We're not going to go -- we're not going all the way there completely, and we acknowledge that at today's share price, there's value in terms of reinvesting some money back into the business for the remaining shareholders. So we're going to be taking a balanced approach with majority to debt until we get there. But Dean, I don't know if you want to take any more that.

Yes. I'll just comment the 2027 bond is in October. So when we look to just under 2 years away, and we wouldn't want to wait right until the last minute, I think option of building up $700 million cash on the balance sheet and just waiting to repay it is not what we see as an efficient use. So we're setting a long-term target that we think is sustainable company that sets us up for the next phase. And it's a balanced approach is how we're looking at it. So I think that's the same comment.

And just quickly in terms of -- you talked about the 5% of EBITDA from Trinidad, New Zealand. So it's about $50 million of your target. What is that in free cash flow?

Yes. No, you're right with that. I think one of the key differentiators when we were running -- we started up Titan versus Atlas was that Titan had recently had a turnaround done and whereas Atlas needed a large turnaround. So what it means is that it's capital CapEx light. And I would say similarly in New Zealand, we're being very prudent with our capital. The other element that would be in there would be the taxes. And so at these levels, there's not a high level of accounting earnings, so there's -- so I think you can assume it's pretty close to that 50%, maybe slightly lower, but mostly in that same area.

Jeff Zekauskas from JPMorgan. Why is it in Trinidad that there's more methanol exported than there is ammonia? And if some of the ammonia plants don't run -- does that mean there's more gas for the methanol plants? And then secondly, for Dean, when you look at your comparables, why don't you include CF industries.

Okay. I'll take the Trinidad question. So right now, Trinidad has got methanol, ammonia and LNG, pretty much across the board in terms of gas 4 Bcf a day of gas demand and 2.5 Bcf a day of production. So across all end uses there, LNG, methanol and ammonia, there's been everyone's taking a haircut on operations there. We -- there is the recent announcement of Nutrien and backing out of Trinidad, and what happens to gas.

We do believe not certain is that what's going on there? It's obviously not our -- it's not for us to speak to that situation. But we do think, on a short-term basis, some gas may have been rediverted into methanol. But I think everyone has taken a haircut across the whole downstream sector.

And right now, our focus on Trinidad is again operating at cash positive. There are developments that Kevin spoke to that could allow Trinidad both within Trinidad to develop gas in the short term, but also then longer term, it's around geopolitics in Venezuela and to unlock there. So today, our focus would be on the Titan asset that we have. We've got a gas contract coming up in September 2026. Our base case scenario is that we get another two year gas contract there, on similar terms, and we don't have a turnaround on Titan until the end of that -- what would be that term of a contract. So Dean, maybe I'll turn it over to you on the next question.

On the comparable, sure. No, obviously, there's not a lot of direct comparables for Methanex given our industry nature. So we look to a broad set of peers. No specific reason why we've excluded CF. We do look at CF from time to time. I don't have a specific answer for you on that one, Jeff.

Nelson Ng from RBC Capital Markets. So Karine you're giving more color in terms of the realized price globally versus in China. So is it safe to assume that China and probably India absorbs all the sanctioned products. But I just want to ask you, given that you sell about 15% to 20% of your product to China, what's your strategy there? Is that -- that's your lowest -- is that your lowest margin market? And how do you approach selling product into that region?

Go ahead, Karine.

Yes. So you're correct that this is the lost netback region that we serve. That said, it's a very important market. It's a market that's growing, that's very easy to serve in some regions, in some part of the China market as well as some other areas of the demand that's located in very unique location where we actually differentiate as well. So it's not necessarily the lowest of our net backs. There are also some pockets of very specific regional demand that we serve here with additional services.

And my last question is, I guess, you guys talked about moving the Chilean facilities to Louisiana. Can you just -- I know you don't want to look at any large capital projects over the next few years, but is there an opportunity to move 1 of the 10 -- sorry, 1 of the Trinidad facilities or 1 or 2 of the New Zealand facilities to another location?

I think I'll turn that over to you, [indiscernible].

Yes. No, it's something that we look at. What I would say is it sort of depends on the state of the plant and then also the jurisdiction that you might be going to because a lot of it has to do how much of the plant can you move to a different location? And does it actually give you an advantage to do that. And a lot of it has to do with the piping or the pressure envelope that you can move. So we do look at it we've got studies at what I would say are sort of on the shelf and if there's opportunities that emerge, it's -- we'll look at that. But it's not something that we're actively pursuing today.

The main advantage moving is about speed, less about capital savings. And so we don't see the market really demanding us to move with speed because the pricing signals aren't there today. So it's unlikely that exploring that. But like Kevin says, we're always studying to say if that was an option, how and which asset would make sense.

Laurence Alexander with Jefferies. Just a very quick one on the shortfall slide, the 9 million to 11 million tonnes of shortfall. Can you play out the regulatory barriers to addressing that shortfall? How you think about customer shutdown economics and the price elasticity that you think you can observe in the methanol market. So if you get a 2% or 3% tight market for a few quarters where prices go?

Yes. It's a great question because that's why we put a question mark on it. I think the first thing is on building new capacity, building new capacity is isn't easy to do, and it's certainly not easy to do on tight time frame. So even if you really supercharge a project, you're talking about 3 or 4 to do a methanol project.

In terms of restrictions and where we have seen the restrictions, there's quite a bit in China now. There was rapid expansion in the early 2000s in China. But since then, there's a huge amount of government scrutiny around new methanol plants has to be the latest technology, has to be world scale, has to come with downstream derivative with it.

And those are just not being sanctioned nearly as loosely as there was in the past. In fact, they're more on page of shutting down inefficient plants on basis of energy uses and energy efficiency in the country. So it's a big question on what's going to happen, how does that supply demand gap get filled. That's why we're pointing to the consumer, and it likely has to balance where would it balance is we think it balances on your marginal consumer unless something changes, and that's the olefins market, how sticky that is and where that ultimately lands.

Logic would say that the most inefficient plants would have to either shut or significantly reduce down rates. And we are -- we have actually started see that happen. Some of -- there's one older inefficient MTO unit that we think is actually permanently shut in. And you've got new plants starting up. So there's going to be a competition there. logic would say that as the older inefficient plants shut down that the ability to pay becomes greater, because you have more competitiveness of the remaining industry, but we're going to be watching that very closely. So -- on that basis, you don't even -- you don't need the rebalancing to happen within olefins to still get some pricing improvement. But obviously, a big question mark and something we study very closely.

Thanks for arranging these guys. Rich, I thought this was a very tight Analyst Day. So kudos to you guys and the team. Let's start with supply demand. One question on supply, another one on demand. On the supply side first, maybe sort of building on what Laurence asked earlier. You guys laid out 2 million to 4 million tonnes of at-risk production, right? And that's kind of what's baked into your $9 million to $11 million tonne shortfall.

From the sounds of it, that's primarily Russia, if I heard correctly and Iran. What are you baking in, in terms of anti-evolution? I mean we're beginning to, in a phased manner, here, some rumblings, right? I mean the other day, PetroChina came out, talked about shutting some refineries, some sort of olefins capacity. Nothing much has really come out on the methanol side. So let me start with that on the supply side, and then I have 1 or 2 more.

Yes, we don't -- or at least it hasn't hit our radar that it's going to affect methanol. And they've already been -- they have been restructuring that industry for quite some time, already shutting down the small inefficient plants. And like I said in our kind of yellow bar that I showed you, those are -- there's quite a bit of small plants, 100,000, 200,000, 300,000 tonne plants that were built in the early 2000s that that are permanently mothballed from our perspective and would face significant political and economic hurdles to ever restarting again.

So we do think some -- a lot of that has place in methanol. There aren't big projects today that we would say on the books that they would either slow down or count or cancel because of anti-involution. Again, a lot of that is already on the books. It's coming with downstream integration. So we don't see a big impact there. The one area that we are watching more closely is the olefins market. What does that do in terms of slowing down new projects that might be on the books, what does it do potentially of shutting down older inefficient plants which would certainly be a benefit to us as we're seeing across other regions like Korea and Japan and Europe and the restructurings that are happening there. So China would be a big impact, and that's something we're paying close attention too. Karine I don't know if you want to add anything to it.

Just the only point I wanted to add is the fact that you mentioned about massive rationalization that already took place in China. And just to give you a sense about 1/3 of the Chinese production has actually started in the past 5 years. And so there's been a number of rationalization that took place, a very significant improvement in the quality and the reliability of the plants.

And that's why we have such higher operating rates now in China compared to what we had in the past. But at the same time, you definitely have rationalization of older industries in general, it's true for methanol, but if you put refineries and such, you see a lot of rationalization taking place already.

Perfect. And on the demand side of it really quickly, I mean, it seems you guys are being pretty conservative with your demand estimates, right? The question mark around NPO, but one of the things that seem to be missing from the presentation was the marine opportunity. So I mean, why are you guys not talking about it? Is the opportunity still sort of as spectacular as it seemed to be earlier.

Yes. Thanks, Hassan. And we will -- we are going to hit that off when we talk with the low carbon solutions group. So we will start with a discussion on conventional methanol. There's a big demand potential as we've been saying. And we have always said it's demand potential because, ultimately, conventional methanol used in marine application, it needs to be competitive.

There's an alternative. There are dual fuel engines. And what we've seen thus far is that in the big deep liquid ports where the big container ships, where the biggest part of the demand potential has been is that methanol is traded at a premium to the alternative fuels being low sulfur fuel oil.

We have seen some adoption. So as of today, and I hope I'm not stealing too much of Mark's thunder here, but we say there's probably about 3 million tonnes of demand potential already in the water, but we're seeing less than 10% demand pickup in terms of conventional methanol. So we haven't put any big numbers in. We think where is conservative. Certainly, if methanol is available and you get a dislocation of methanol versus conventional fuels. So a dislocation to energy. There's potentially a floor price there that you break through because you could see a lot of methanol being consumed by ships, but we're not putting in a big level of base demand today.

And then one last one, if I may. Just I appreciated all the slides on natural gas, obviously, a very important variable in the methanol and Methanex story. I mean I just keep debating this that it's there seems to be just binary opportunity out there, right? I mean, as I take a look at AI stocks, the way they're trading, what sort of growth they're implying and compare that to sort of the natural gas market, and you guys did a very good job in showing us that natural gas has averaged $2 to $3 a million BTU over the last 10 years. But I sit there and I take a look at AI data centers, right 60% of the electricity consumption by them is fossil fuel based, right, which, again, depending on the region we're looking at, but the mix seems to be an equal mix between coal globally between coal and natural gas.

Now on the natural gas side of it, I mean, it's been like 12% electricity demand growth for data centers from 2017 onwards. I mean that's a huge number, right? And then when I layer on top of that some of the LNG exports that we are seeing here in North America, I mean, you can go crazy with some of the growth in fossil fuel-based electric -- fossil fuel-based demand, right, natural gas in particular.

So as you sort of sit there and think about the future, I mean in the near term, I heard you guys talking about near-term nat gas hedges going down from being 70% edged down to 50%. But I mean my fear is that you could come up with a cold winter incremental LNG exports. I mean, haven't things gotten a little more volatile or may get a little more volatile at the very least. And longer term, how are you even thinking about what if, what AI stocks are implying may actually be true. Sorry, the very sort of long-winded way of asking you the future of natural gas prices.

Yes. Obviously, it's critically important for us in our business. So I think the main principles that we go back to is what Kevin showed on his slide, right? It's the prolific basin itself that there's 50 years of gas there that are are commercially and technically feasible based on everything that is happening in that market today, and it's based also on the productivity gains and the outlooks for how that industry is able to operate and that there's likely a lot more gain there. Kevin, I don't know if you -- I can turn it over to you to -- I'm sure AI and LNG are 2 things that we're constantly looking at in terms of the demand and how that effectively evolves.

Yes. No, I think one of the things I was trying to highlight in my talk was that natural gas supply historically has been quite elastic. And so it's been quite respond demand. And we think that's going to continue. So we've seen like a doubling of the gas market over a 15-year period. And I think some of the most optimistic projections when you think about increased LNG export and data centers and stuff like that increases the gas market up to 130, maybe 140 Bcf a day.

So that's a 30% increase kind of where we're at today. And when you look at the 50 years of gas that can be technical and commercial produce today. There's also technically recoverable it's over 100 years of gas. And when we think about gas from the dryer gas basins and what it cost to do that, if you look at the, the investor present decks from Expand Energy or EQT or EOG, they all kind of tout unlevered breakeven prices in the low $2 range for that gas, right?

So a lot of low-cost gas that's still available, and that assumes no productivity improvements going on. And you've seen -- when I think about what's going on in the U.S., and I talked to forecasters and experts about this why aren't you baking in more productivity improvements.

So if you look at the pace of what's happening here. We just in Argentina recently, and what they're doing in Argentina as even better than what they've been achieving in the U.S., right? So you're seeing shale drilling technology and get more cost effective. So we've got a view that supply is going to continue to be quite elastic with demand for the first future.

So I think we have time for one more.

We will finish off from -- with a question from the web.

Okay. We should do a question from the webcast for sure.

We've got one here. So would you consider buying out partners out of any joint ventures like not gasoline?

I mean we're pretty early here to be exploring that. But obviously, there's -- anything like that is subject to both parties and what the motivations are of 2 interested parties. And right now, we're focused on really all the things that myself and my colleagues talked about today, which is let's operate these assets, let's do a fantastic -- good job at integration.

Let's deliver performance consistently on a stable basis before we start thinking beyond that. And our focus right now is on delevering the balance sheet and making ourselves a stronger, more resilient company. So we're always open to opportunities, but right now, that's certainly not our focus. So I think that we will wrap up the Q&A. I really appreciate all the questions. And we will have time.

I just want to say that we're going to start the panel discussions. We will be around after the day is done, if there's follow-ups that people want to have. We've got the executive team, we've got Board members, and we also have team -- our senior leaders present as well. So if you have follow-ups, please save them and we'll try to answer those. And of course, as always, our Investor Relations group. So thank you very much.

All right. So we are now going to start our first panel discussion, and this will be on our manufacturing and our center of excellence around manufacturing. We talk about the importance of this as we think about delivering results and integrating our new assets. So with that, I'm going to turn it over to Gustavo.

Thank you, Rich. So I have 2 colleagues here that will walk us through the manufacturing panel. I will talk a little bit about Paul Daoust introduce him as our VP Projects and Turnarounds. He's based in Canada, more than 25 years of experience in different roles in Methanex from corporate development to marketing and logistics and also manufacturing.

And second is Matt Geary. He's our VP of Reliability Asset Integrity, he's from New Zealand. So you need to accommodate my Latin accent to a New Zealand accent. So see how it goes, he has more than 17 years of experience in really understanding the asset quite well and driving excellence in those, and he runs the global experts that certainly will have a little bit of a discussion on how that team works. So I think I'll start with you, Paul, if you can talk a little bit about our capital allocation process, the way that we manage that manufacturing and what is the value that it brings?

Yes, sure, Gustavo. Thank you. When I think about capital management for manufacturing in the organization, I really kind of look at it from 2 perspectives. So one is really around capital allocation, and that's really about what we're going to spend our money on and the technical solutions that we choose. So that really helps us to really focus on maintaining and enhancing our safety and our reliability and our efficiency within our assets.

And then the other part that I'll talk about is more around, more on the how. So the project management and what we do with our capital projects as well as our turnarounds. So I'll start with capital allocation. And so when we look at that, we really drive that from a standardization approach. We drive it from a center approach. And so every one of our manufacturing facilities, we work with them from the center so that we can take a look at how -- what the opportunities are and the risk and allocate the capital appropriately. And that really starts off with a few key things that we've implemented over the past 5 to 10 years.

Number one is a common way of looking and defining risks across our assets or vulnerabilities, which is really critical in our decision-making. And then the other part is around value projects. And so what I mean by value projects are projects where we can invest in our assets to increase our efficiency or where we can invest in our assets and make them more reliable, invest in our assets to reduce things like emissions, for example, greenhouse gases.

So we've also introduced a common way across our assets in terms of how we look at capital and how we evaluate it. And so during this process, there's 2 key parts that really pull this together. I would say it's the interaction between our sites and our global experts. So we've got over 350 years of manufacturing plant operating experience within the organization. So we've got a lot of deep experts, whether they sit in Matt's group on the technical expert side or there are people that are in our environment, health and safety or responsible care area or other areas in our plant.

We use them to work with our experts at our sites and our technical knowledge people at the front line to really align on the risks and the opportunities. So we can look at this from a global perspective and prioritize. And the second part of that, what I was talking about, Gustavo was around really that being a center-led process. So we just make sure we consistently do that across the organization. And that really allows us to target our capital and our resources at the highest priorities for the organization.

So that's really about the what and what we're going to allocate that capital on. I'd say the second part that we really work on and spend a lot of time improving over time is more of the how, the project management. So when we do capital projects or turnarounds, we've really gone through the organization and find some very common processes and discipline around how we develop and how we plan and how we execute those capital projects as well as those turnarounds.

And that's really allowed us to enhance our performance over time. We have a common approach across all of our assets, and we continuously learn in terms of how we do that within the organization. And so that's really allowed us to improve our performance in both the what we're going to do and how we're going to do it. And I think actually some of the slides you showed earlier, Gustavo, around our performance in terms of our safety performance as an organization, our reliability performance as an organization, it's really underpinned by how we manage our capital and execute our capital.

Thank you, Paul. No, certainly, really, really good job in working with the team there and aligning our process. So you talk about turnarounds, probably it's really an important thing that we do every 4 to 5 years. So probably it would be good to understand what those turnaround mean and what do we do and how we improve our practices and we try to become better and better in those turnarounds.

Yes. Turnarounds are really important for us. So as you mentioned, Gustavo, there are events that happen at each one of our plant sites every 4 to 5 years. They're very major planned events for us. So just to give some perspective, we will have a turnaround that we'll be shutting down the plant to do a number of work, and we'll have the plant shut down for approximately 5 weeks or it could be longer depending on the scope. So it's a fairly large event.

To give you a sense of the people on site, we work with our people and contractors, our Methanex employees and contractors. We could be reaching 600, 700 people as a peak on our sites. So as you can imagine, these are pretty major events, and we want to make sure that we plan, develop and execute them really, really well.

Some of the things that happen, just to give you a perspective of what goes on in the turnaround, we'll do a few major things. One of them is we'll change the catalyst in our plants. And so we have catalysts in various reactors. And over time, this catalyst degrades. So you have to replace it on a certain frequency. We could be replacing several hundred tonnes of catalyst in multiple vessels during the turnaround. So pretty significant work. We'll test our safety critical and environmental critical equipment.

We'll do regulatory and critical inspections, testing, repair of our equipment, any kind of overhauls we have to do. And then also when we're doing some of these capital projects I talked about, that happens within a turnaround window as well when we can only do these when the plant comes down. So pretty big events.

And so we've had a very disciplined approach to looking at our practices around the organization over the past 5 to 10 years and embedding common ways of doing these, common processes and following stage-gate processes to make sure we have the discipline in how we define and develop these turnarounds as well as how we plan them and how we execute them.

And that's really underpinned by a few key things to make that successful. I would say one of the ones is we have dedicated teams on our sites. Number two, because of all of our operating experience across all the sites, we have a center that works within my team to look at how we do these turnarounds and make sure we're really supporting the sites in terms of that and development process as well as execution.

We have steering committees, a common approach around how we do our steering committees with people from the center and leadership from the sites working together to make sure we're applying really good practices and discipline across the sites. And then I would say one of the last things is that when we -- and you mentioned this earlier, Gustavo, when we actually do a turnaround at one of our sites, we like to space our turnarounds out between the sites. And that allows us to leverage global resources, and it allows us to leverage resources from other sites to come to a site and help with such a major event so we can execute them successfully.

Thank you, Paul. An add is, that every turnaround that we finish, we go through a close-out process, and we get all the learnings that we apply in the next opportunity. So you mentioned about 4, 5-year cycle. So can you talk a little bit about what are we trying to do in that space to optimize performance in turnarounds?

Yes. I think you touched on one of them there, Gustavo, and that's that lessons learned processes and bending it back and sharing it amongst the teams globally so we can get better and better as we go forward. The other thing I'll talk about, I mentioned catalysts and it degrades over time, and there's a requirement to change it.

Over time, Catalyst has been -- there's been developments in catalysts and the technology has improved. And that's really allowing us to look more and more at not having to change catalysts out after 4 years but the opportunity really to make it last 5 years. And so we've been looking at that across our asset bases, and we're going asset by asset to look at the potential to go from a 4- to 5-year turnaround cycle.

Now that requires you to look at other things associated with turnrounds, requires you to think about asset integrity, it requires you to think about your inspection protocols, your testing of your equipment that I talked about and potentially some things around vulnerability at the site. So you have to look at it from a catalyst perspective, which is quite positive but all these other elements too, to make sure if you're going to move from 4 to 5 years that you're doing that and not compromising something else like the safety performance we have at the plants or the reliability.

And so we have experts in the turnaround side and a lot of team members in Matt's team that are technical experts, helping each one of our sites go through and evaluate what's the potential to do that. And so far with a couple of the sites that we've looked at, it's looking positive.

Thank you, Paul. Last question for you. You talk a lot about OCI. The way I think about OCI is not OCI anymore, it's Methanex, but that's me. So how are we embedding all the things that you talk about, the governance, the processes and the kind of center of excellence into these new high quality assets?

Yes. When we -- well, first of all, I think when we did the due diligence, we had a fairly -- we got a fairly good sense of the assets and the teams, and that helped us with integration planning. And so as we went forward with the integration planning as an organization, manufacturing looked at how we're going to take -- undertake that as well.

And I would say we really have kind of hit the ground running on that. Some of the key things that we did are very quick interaction between our teams at the center and the site teams. And this is very common in the way that we work with any site within our organization, working close with the site teams and the center teams underneath yourself. So we've done things like risk management assessments at the sites or sort of responsible care audits at the sites and assessments.

Matt and his team are doing asset integrity assessments. And that will help us to understand the vulnerabilities or potential vulnerabilities of risk that they're identifying as well as any kind of value opportunities. And very quickly, in parallel to people that are technical experts working with site people, we also, as a leadership team, went in and worked with their leadership team looking at the risk that they're identifying, what kind of capital they needed to focus on the projects they need to focus on.

And we've been having very good dialogue back and forth between the teams to really kind of align on what I talked about before when I talked about capital allocation. What's the relative vulnerability and risk? What's the priority and what's the opportunity? And so that process has gone quite well. There's been a lot of interaction, really good interaction between the teams to help us align on those priorities.

Thanks, Paul. Turning now to you, Matt. In the screen, we are showing our reliability framework. We talk a lot about that. Probably it's a good opportunity for you to explain what that really means and what is the value that we bring using this framework.

Certainly, Gustavo. So I'll talk about 3 areas. One is about the culture around reliability, the framework itself and then the value that we see it deliver. In Methanex, we don't leave reliability to chance. And so that's why we have a large focus on it. Just in terms of the culture and the mindset, that's the place that we've started over the last 15, 20 years in building that.

And we've defined reliability within Methanex to be constantly and consistently meeting expectations of our stakeholders. What that practically means within our operating plants is that we do what we say we're going to do. And that really translates into asset performance. So in terms of the framework, on the screen there, you'll see the 5 areas.

It starts with the leadership and culture, which I just mentioned. Reliability management is really taking a data-driven approach to everything we do. And we do that with specific reliability engineers that are trained in terms of looking at that data and analysis to drive the right decisions around our capital allocation.

Asset condition management is really focused on how we can assess the assets and then work execution management is really focused on not introducing any defects when we're doing turnarounds, so we have this -- reliability is about driving a failure-free operation. And when we're doing work on our assets, we don't want to introduce anything that could cause risk.

And the last area really is around human factors and what that translates to is, making it easy to do the right thing and hard to do the wrong thing. So when we're designing new bits of equipment or undertaking work, we're really designing the process of the system easy to do the right thing.

Thank you, Matt. So I spoke before about our global expert, Paul Thachett. So this group reports to you. So probably it would be an opportunity here to explain what is the value that this group brings and how they integrate with our global manufacturing.

Certainly. So we have a team of technical experts. There's about 12 experts working across 6 disciplines. Those disciplines are static equipment, which would be pressure vessels, piping, exchanges, rotating equipment, our compressors, turbines. We've got electrical instrumentation and control, our infrastructure around that space, water treatment and corrosion and operations and then process engineering.

So collectively, those 12 people have anywhere between 20 and 45 years of technical experience. It's over 400 years of experience and probably about 60% within Methanex itself. They kind of act as the backbone of our technical expertise, and they're really the glue within Methanex. So their role is to cascade knowledge from outside the industry to inside Methanex and then cascade it across the sites as well.

And they do that through global teams. Each of them have a disciplined team that integrates the sites to collectively work on any issues or problems and get ahead -- be proactive in terms of getting ahead of those problems as well.

Thank you, Matt. And certainly, all our knowledge is captured in our Methanex project standards that we use when we build and we operate plants, so thank you for that. So last question to you, Matt, is that, we talk a lot about tools, a gentlemen talked about AI.

Can you elaborate a little bit what are we focusing on how we can improve performance by using these tools? What are we -- are the things that we believe are going to bring value to our manufacturing and operations?

Yes, certainly. So we believe that AI lets us see a little bit further ahead in terms of our manufacturing assets but in saying that, our reliability framework is a foundation, and we remain disciplined in terms of doing those foundational activities because that has shown over time how we get to a 96% reliability, and we don't take that for granted. A couple of areas that we see value in terms of AI today where it's helping us.

So one example I'd give is advanced process control, which is about running our process a little bit tighter to generate efficiency value. AI is sitting on -- and that technology has been around for a long time, but AI is starting to sit on top of that where it can give you some predictive direction on where that process control is occurring and provide operator response to that.

So if we can utilize that response, we can kind of keep our operations in control before they get to a point where it's -- we're having to recover from a situation. The other area, which is quite interesting, so we have 2 or 3 large compressors in each of our facilities. So we're operating 20 to 25 compressors. They are single -- they're not redundant.

So if they do have a failure, they do have a big impact. AI is allowing us to kind of build a plant model for each compressor. So we would take -- and in doing that, you generate an operating signature for that compressor and then you can sit that alongside the operation of the compressor. And as it deviates, you can get an indication as to whether you potentially have an issue. What that translates to us is that we're able to utilize that to develop a plan.

And if we're planned, then we're not in a situation where we have an unplanned outage and we're having to react. The differentiator for Methanex in terms of this area that we've got from feedback from the vendors is the 350 years of operating data that we have. So we have a lot of operating data that we've utilized to build those models.

And we've also had some failures. So when we're developing these models, we use some of those failures to blind test the models, and that allows us to get confidence that when we're applying these models that they are giving us actually the correct indications.

Thank you, Matt. I know I said the last one, but another one occurred to me. So we have been talking about asset integrity and all the things that we are doing in Beaumont and soon in Natgasoline. So can you talk a little bit about that process and how that translates into improvement?

Sure. So if you think about the reliability framework is defining the activities that we need to do, and we do them in the right way, then our asset assurance program is really assessing the equipment at a corporate level to assure that the integrity of the equipment is actually adequate. And we gauge it to be -- is it at or above industry level, and we use that in terms of our capital allocation around resetting some direction for the next period.

So just a couple of -- we've been on this journey within Beaumont and Natgasoline at the moment and a couple of examples of where we're seeing value in that. I think you mentioned earlier that the front end of the Beaumont plant is similar to our Medicine Hat and actually one of our New Zealand plants. So both of those plants have over 30 years of operating history, and we've been able to take some of those procedures and then provide them and sit them alongside the reformer at least and then just rebalance the reformer and how that's operating.

So that's a tangible example of where we've made a difference early on. In the Natgasoline reviews, we're working through that at the moment with the team there. And we've got a list of learnings from our Atlas plant and some specific learnings around piping and the flue gas duct and coils where we've had issues. And we've made some relatively cost-effective solutions. So we're looking to take those direct into the Natgasoline really to drive an improved performance there.

Thank you, Matt. So that will conclude our panel. So I hope you got a better appreciation how we work together, how we run our manufacturing strategy, how do we care about the assets, how we manage our turnarounds, our capital allocation process, how we operate as one team, how we leverage on our capabilities that we have globally and how we really sustain performance. So it's a moment for 1 or 2 questions if somebody wants to kick it off. No then, so thank you very much for the opportunity, and thank you for the explanations today, and thank you.

Thanks, Gustavo. Paul and Matt, thank you very much. So we'll start the second panel. This will be on discussion on low-carbon methanol. And Mark is going to start off with that conventional methanol discussion we were having as well. So with that, I'll turn it over to you. Mark, you have a microphone?

All right. Good afternoon, everyone. Pleasure to be here today. Now I'd just like to highlight that I think my colleagues have done an excellent job of highlighting the positive outlook that we have for the conventional business. And now we're going to turn to the opportunity in low-carbon methanol. Importantly, there are some synergies between the 2 opportunities. And so let me just highlight 2 synergies that we think are really important.

So first of all, we can leverage our global supply chain to be able to cost effectively move low-carbon methanol around the world at times when it's still a relatively small market. And that's really important because logistics costs are an important element of the overall cost of getting low-carbon methanol to market. So for example, you can co-mingle 5,000 tonnes of low-carbon methanol in a 45,000-tonne vessel, just to put it into perspective.

The other area of synergy is really leveraging our existing asset base. And so one of the things that we do today is we put renewable feedstocks into our existing asset base which effectively allows us to produce green methanol from a conventional methanol facility. So those are just 2 examples of synergies that we think are really important in the low-carbon space.

Having said that, let me turn to introducing the panel here. So you know me, Rich introduced me, so I have oversight responsibility for our low-carbon activities, and I have the pleasure of being joined by 2 of my colleagues here. First of all, to my direct right, Roger Strevens, who comes with a deep history and knowledge in the marine space, having worked for over 15 years in regulatory and decarbonization. So he's going to talk about some of the regulatory aspects of the business.

And then Renato Monteiro, who has a great deal of experience in strategy and business development before he joined Methanex, but has also been with Methanex for a number of years and he's really responsible for driving a portfolio of cost-effective low-carbon methanol supply opportunities that are critical to meet the needs of our customer base.

To get us started, maybe I could turn to you, Roger, and maybe you could highlight what existing regulations are in place that are designed to drive the adoption of low carbon fuels in general and low-carbon methanol specifically and then maybe some other developing regulations that might impact things in the future.

Thank you, Mark, and good afternoon, everybody. So one of the primary functions of regulation is to address the higher cost of lower carbon fuels versus the fossil incumbents. And it's for that reason that regulation is a primary driver of the market opportunity that we have for our low-carbon methanol in 2 of the 3 markets that Mark is going to discuss a little bit just a moment.

When we look at the low-carbon regulatory landscape, we can divide it into really 2 parts. There's the regulation on a national and regional level, that's in the U.K. and the EU, that's already in effect. This is a market that exists and where we're competing today. And then there is the global regulation which is still under development. That has the potential to represent a much larger opportunity again. There are a few general points that I'd like to make about regulation.

First, we're moving nearly entirely towards a life cycle basis for regulation and a greenhouse gas basis. And what do I mean by that? It's not just the emissions from combustion that are considered by regulation but also the emissions from production and transport. In addition, we're not just looking at CO2 anymore. We're also looking at 2 other climate gases, that's methane and nitrous oxide. And why is this important?

Well, it means that we're actually addressing the issue for one thing. But second, this is good for the competitiveness of methanol, contra, other types of fuels. Second point, the actual -- the specific requirements of different fuels -- of different regulations vis-a-vis what's accepted vary. And you'll see that this fact is reflected in the supply strategy that Renato is going to discuss in just a moment.

The third point I'd like to make is that all of the regulation that's on the books today, it escalates over time. It has -- it's driving more demand. So as time goes by and in different ways, the size of the cake, the size of the opportunity is growing. And there, I'm talking about regulation that's already settled. It's already on the books.

So I'd like to turn next to a specific regulation under the EU. It's fuel EU maritime. This is the primary driver of the energy transition on -- for maritime. And it escalates over time as well. But it's something else that I think is important and interesting is that it's coming up for review. And there are 2 points I'd like to make about that. The first is that it is significantly less ambitious as a regulation today than what IMO, that's the International Maritime Organization, is contemplating.

The second point, it was the European Union member states who pushed the level of ambition for the IMO. And so I think the question you can ask yourself is this review of Fuel EU Maritime, are the Europeans going to adopt, make a change to it that's more similar in level of ambition to what they've been pushing for at a global level at IMO. So I don't know the answer to that, but I do know there will be advocacy.

The next point I'd like to move across to -- is to IMO. And first, just a little bit of context here. IMO is a UN agency, over 170 member states who decide on regulations for security, safety and environmental aspects of shipping. They're a global regulator. They've been doing this for decades. In 2023, they set out their greenhouse gas revised strategy. It includes a series of targets. That defines the what, what are we trying to achieve? And those targets are quite ambitious. And even if I think they're not achieved exactly as intended, they represent a huge opportunity.

IMO is -- regulates about 8x as much emissions as the European Union. So it's big. Just to put it in terms of energy equivalent, the shipping industry goes through the equivalent of over 500 million tonnes of methanol per year. Now of course, that entire amount is not going to be what the shipping industry is using. I'm not saying that, but it shows that even a small proportion represents a big opportunity.

So the strategy was the what. The next part is the how, and that was where the net zero framework comes in. This was a package of regulation that IMO has been developing and which it considered for adoption. That's a critical step before it becomes -- comes into effect last month at IMO headquarters in London. The outcome of that meeting was adjournment for a year. There was a lot of pressure from the U.S. and other member states. This has been widely documented.

And I think there is -- this is a deferral for sure. The IMO agenda has been slowed down by this. We need to be realistic about that. There is uncertainty on how we go forward. I don't think anybody can say, not even the IMO themselves, what the exact agenda is going to look like from here, when something would be adopted and what version of the net zero framework that might be. I think the key issue was the economic aspect of the net zero framework. There's a technical piece, very similar to Fuel EU Maritime.

And then there's an economic piece, which has been viewed by many stakeholders as a tax. And that has been, I think, a key sticking part. It is possible, and I don't know, I don't think anybody can say this for certainty, that the focus may pivot towards really narrowing in on a technical measure. And that's the kind of thing IMO has been doing for a long time and successfully and recently. The last big example has been the 2020 global sulfur cap change. So the work on this is continuing very vigorously at IMO but there is a lot of uncertainty. And I think we need to be realistic about that.

One thing that is clear and has been encouraging is the shipping industry have been in general and across all of the major shipping representative organizations, they have been supportive of the work at IMO. Why? Because they want global regulation for a global industry which is much better than fragmentation as an approach. And so for us, for our part, we are trying to work with member states, industry partners, the Methanol Institute to develop solutions and try and help us towards reaching an agreement. And so with that, I'd like to hand the word to you, Mark.

Thanks very much, Roger. Roger happened to be at the IMO meeting in London. So it was quite interesting. I was getting an hour-by-hour blow about everything that was going on. So it's quite a fascinating experience to have experienced that at least remotely. Now I'd like to speak on behalf of one of my colleagues who couldn't be here today, and her name is Denise Abdin, and she's responsible for our customer relationships and driving demand for our low-carbon methanol.

So today, we already have a small but profitable low-carbon methanol business. So we're selling today about 70,000 to 80,000 tonnes of low-carbon methanol, and that goes into the 3 segments that are shown on the screen here. Importantly, the reason why that's a profitable business today because the costs are higher than the cost for conventional methanol. And what drives profitability is that the sales price for that low-carbon methanol is roughly 3x the sales price of conventional methanol.

So now turning to the 3 different segments here. The first one, and I'll start from the smallest and go to the biggest. The first one is in the chemical space, and that's a voluntary application. So there's no regulatory driver there. And so you might ask the question, well, why are some of the chemical customers voluntarily agreeing to pay close to 3x the price of conventional methanol? Well, what really drives that is some of our customers' customers have retail-facing products that they're looking to sell in the marketplace.

And so there are some green marketing credentials, whether it's renewable feedstocks or green credentials that helps them to pass those costs along to their customers. We don't expect this is going to be a very material market. It's going to be in the tens of thousands of tonnes, but it's something that's really important for us to make sure that we help support the needs of our existing customers. The road transportation market today is the largest market that we sell into.

And that's really driven by renewable fuel obligations in both the U.K. and Europe. And so what -- where methanol finds its way in there is as a 3% blend in gasoline. So that's part of meeting the renewable fuel obligations in the U.K. and Europe. And that market is our largest today, and we believe that it has the potential to grow into several hundreds of thousands of tonnes over the next few years.

Importantly, we have got a large amount of capability in that space through the OCI acquisition because OCI was actively promoting that market development for the previous 10 years. So we're really well placed to capitalize on some of the growth opportunities that are there. But the most important, by far, potential opportunity for us in terms of volume is in the marine space.

And so let me first start off by just addressing the question that came earlier and what's the opportunity for conventional methanol in that space. And Rich correctly outlined that conventional methanol and the main trade routes with the container ships generally is not competitive with conventional bunker fuels. So for that reason, we haven't allowed a lot of incremental demand there. But it's important to note that we're very early days in the development of this marketplace, and there are some locations where methanol is quite competitive with conventional fuels. So I'll give you an example.

The further up the Yangtze River you go, the more expensive conventional bunker fuels get and the cheaper methanol gets. So there is a point up river where conventional methanol will be competitive. There's also some other potential markets where it can be competitive. But it's not a major focus for us. The major focus and the biggest opportunity is for low-carbon methanol in this space.

Now what's going to drive demand for low-carbon methanol, it's really going to be regulations, and it's going to be its competitiveness with other low-carbon fuels. And so what are we doing in that space? We're really focused on making sure that we help shape the regulation so that methanol gets a fair treatment, including in blue methanol that Renato will talk about in a minute. And then lastly, we have to make sure that our product has all the environmental attributes that the customers are looking for and has those attributes in a cost-effective way.

And so typically, what we look at is we look at being competitive on dollars of incremental fuel cost per tonne of CO2 reduced basis. And that's the benchmark within which we measure our various low-carbon methanol supply opportunities. I'll now turn it over to Renato, who can highlight a bit of the activities that are underway in developing this supply portfolio. Renato?

Thank you, Mark. Good afternoon, everyone. Pleasure to be here sharing with you. So just to start, as my colleagues alluded, low carbon methanol is the same methanol molecule. Therefore, we can leverage our supply chain commingling physically with the conventional methanol but it has different environmental attributes, and that's a critical aspect to define our supply strategy. This implies essentially 2 elements.

The first one is, as Mark said, the carbon intensity, which is emissions per megajoule generated by the methanol molecule. And second one, the certifications that are necessary to be accredited by the regulatory frameworks that Roger has described. So in that capacity, we are aiming to develop a sustainably competitive advantage through the supply of all of our customer needs as a one-stop shop for all their needs. As an example, in the maritime industry, as they develop new vessels, they utilize conventional methanol to test the engines. But thereafter, they would have to use low carbon methanol to attain the regulatory frameworks.

So Methanex is uniquely positioned to offer all those ranges of products. And how do we want to achieve the competitive -- sustainable competitive advantage? Through 3 steps. The first one is, as Mark alluded, being in the left-hand side of the cost curve in a dollar per tonne of CO2 reduced. That's the benchmark, that's how the regulatory frameworks alludes to the parameters of penalties in the event they don't meet the targets. We are developing this with a diversified portfolio of supply, both in terms of geographies as well as production pathways. And that aims to minimize geopolitical and regulatory risks as we have seen already in the short life, we have many changes along the way on the regulatory side can curtail our production depending on those measures.

Second step is really taking a stepped approach to avoid putting our balance sheet at risk as Dean and Rich has mentioned before. So as the market matures, we believe that we -- starting small, creating the knowledge, the connections in the market will enable us to leverage in the right moments to significantly increase our production and market presence. And the third one, we recognize that in some of these production pathways, we are not the experts. In some of those locations, we are not quite familiar, and we will need to build alliances with complementary skills to help us build that sustainable operations, okay?

How we translate this into our product strategy? And as I mentioned, in this market, it's more similar to specialty chemicals than really a chemical commodity. So we have 2 strategies, one for green products and another one for blue products. Green products are essentially produced through renewable feedstocks such as renewable natural gas going through our existing plants, as Mark has alluded.

Another example is producing green hydrogen through electrolyzers utilizing renewable power and combining this with captured CO2. A third one, it's biomass gasification. So you can see that methanol being the simplest alcohol has multiple options that can leverage the local benefits and the local intrinsic values for different geographies. And then in the blue methanol side, those are essentially fossil fuel-based or conventional feedstocks, utilizing carbon capture utilization and storage in one way or the other. That may include putting carbon capture in our own facilities or buying blue hydrogen to combine with captured CO2 as an example. So regarding our green strategy initially, first, as Roger mentioned about the frameworks, that's the only allowed product into the European Union that is the existing framework.

Therefore, has been our focus in this initial phase of development. We have been producing renewable -- biomethanol through renewable natural gas in our U.S. Gulf Coast assets, Beaumont and Geismar since 2018. Therefore, we have a strong connection with the supply market, and we keep a really good track of how much affordability those feedstocks can generate for our end customers. The competitiveness of these pathways are typically in places where you find competitive feedstocks, especially China and in emerging markets. China has an additional benefit of low capital intensity in their production which creates a really strong market for biofuels in general.

We are starting this approach small and with low risk through offtake agreements in a way that we can establish the contacts with the different developers and understand the different pathways around the world to, in the right moment, transform these offtake agreements into a stronger presence either through equity positions or through joint ventures.

We have just signed 2 nonbinding term sheets, and we are now in the process of negotiating definitive agreements that will allow us to continue the supply of the markets that Mark has described, right?

And we keep looking for many pathways. We are totally technology agnostic but very thorough in terms of having that project or production in the left hand of the cost curve. And this is an ongoing discussion, okay? Regarding our blue methanol strategy, this is still not viable or recognized at the moment through the regulatory frameworks in Europe. The IMO, as Roger has indicated, has already signaled that this will be accepted. And we are in further advocacy in detailing how those products can be utilized in the maritime space. This is possibly the most competitive pathway, and it's a fantastic position that we have in North America, as Kevin has described, give us access to storage, incentives and the network economics of pipelines for CO2, hydrogen and other elements that makes our position in the Gulf Coast and in Alberta extremely positive and strong.

You may have heard that last year, we issued a press release that we were starting pre-FEED studies for a carbon capture plant in our Medicine Hat facility in Alberta. This is in partnership with Entropy who will build and own that facility with the large majority of all the investments. We will only cover the tie-ins. But this will provide us sufficient CO2, carbon dioxide so that we can reinject in our production and produce about 50,000 tonnes of low-carbon methanol in Medicine Hat. So I think that's only the first step in this. The economics of this project is -- it does not rely on blue premiums and just in the capacity expansion, but it's certainly a small step and can show you how we are addressing those challenges of starting small and growing as the market comes to fruition. Mark, back to you.

Thanks very much, Renato. And I hope this has given you a good overview of our business in the low-carbon space. I'd just like to take you through a few key takeaways. I think, first of all, is we've got a profitable business today. Yes, it's very small. It's just in the first innings of development for this low-carbon space.

We're approaching this through a diversified set of customers in different market segments. Regulations are going to be a key to driving adoption of low-carbon methanol because of the higher price. We need to work to reduce the price of low-carbon methanol, and Renato is working hard on developing a slate of different low-carbon methanol supply opportunities that we think will meet the needs of our customer base.

Overall, the demand potential here is very large, and we're really optimistic about what the future will hold. But as I said, it's still very early, and we'd be happy to answer any questions that you might have.

I was looking at your last Investor Day deck, so about 2.5 years ago. And there were about 65 vessels that were built at the time, and now we're over 100, which is what your slide says. If you think back to what your projections were 2.5 years ago, are we tracking behind? Ahead from that? And why? And as part of that question, can you talk about ammonia and the competitiveness of ammonia for dual-fuel ships as well?

No, thanks for the question. And certainly, these vessels take a number of years to be built. And so we're pretty much on track with what we would have projected back at that time. I think the more important part of the question, though, is how are the new methanol dual fuel vessel orders coming into play.

And right now, what we're seeing is we're seeing a slight decrease in the number of dual fuel methanol vessels that are being ordered today, but we're still seeing new ones come on the water. So we still have an optimistic view about the outlook for low-carbon methanol vessels. You're right to point out that there are a number of competing fuels and LNG is probably the biggest one today.

So the 400-plus vessels that methanol will have on the water, for LNG, it's -- the numbers are over 1,000. The ammonia comment that you made, that's an interesting one because a lot of people are looking at ammonia vessels. There's not really -- they still have more development to do on the engines but ammonia does have the attractive feature that it doesn't have a carbon atom on board, which means there's no CO2 emissions on board. So that is an attractive feature.

But one of the key challenges for ammonia is the potential for N2O emissions through the combustion of ammonia, which is a very bad actor from a greenhouse gas perspective, a factor of 260 or thereabouts. And then the other aspect of ammonia is the safety considerations for onboarding a vessel. I'm not saying that those issues can't be solved, and ammonia does have some very attractive features. And now that we are an ammonia player, it's also an opportunity for us to potentially get involved in that space.

Matthew Blair from TPH. So you mentioned that you're co-processing these RNG feedstocks. Could you talk about whether these are landfill RNG feeds or dairy RNG feeds? What is your preference and why? Second, it seems like some of your competitors have been a little bit more aggressive on the green methanol front. Is that because they're building projects on a more speculative basis? Or have they just been better about securing contracts?

And then finally, what is Methanex's thoughts today on building a green methanol plant? Is that on the radar at all or something you're not really considering?

Yes. Maybe I'll start off with the green methanol question, and then I'll turn it over to Renato for the RNG question. So we think that it's important that the demand signals are strong enough before we're ready to make a big capital investment. And you're right to point out that some of our competitors have gone a little bit ahead of time.

What I would say is that I'm aware of at least 2 projects where they have stopped the projects in midstream and then they've had to write off hundreds of millions of dollars. So we think it's prudent to take the time and assess the various different green methanol production options before making any big investments in that space.

And the -- regarding the renewable natural gas, we are mostly utilizing so far landfill gas which is a cheaper renewable natural gas. The manure based or dairy, as you mentioned, has also additional streams of revenue from the California low carbon fuel standards which makes the price disproportionately high.

So this product is still more valuable on a per tonne of CO2 reduced, but many of those users are not recognizing yet that feature because they are really in the initial stages of the decarbonization targets. And therefore, we see the manure side being developing much stronger in the future when people will need those CO2 reductions to meet the targets.

Well, if there are no other questions, we'd like to thank you very much for your attention. And I'll now call Dean Richardson up to the podium.

Okay. Thanks, Mark. Yes. Thank you. Yes, just 30 seconds here for the most exciting slide of the day. I just wanted to communicate around our Q4 report. We've historically issued a Q4 report in addition to our annual report. We've done the Q4 report earlier and then our annual about a month later. Like most companies, we're actually going to be consolidating that going forward and just have a single issuance.

We will still be issuing the Q4 information to make sure you can split it out. But from a timing perspective, we're going to do that once. So what you can see here on the left is our timing for 2025, which is coming up in Q1, so just a couple of months from now. And it means a delay in the issuance of our earnings to coincide with our annual report.

For the next year, we'll be resetting our Board and audit dates to be a bit earlier and to be about 2 weeks after that. So I just want to clearly communicate that to anyone. If anyone has any questions, please feel free to follow up with me directly. Thank you.

All right. So that's a wrap on our 2025 Methanex Investor Day. I want to remind people in the room, we will stay around for another 30 minutes to an hour. There's management and Board here available to answer any other questions. And I really want to say thank you very much for participating here and allowing us to communicate how we're trying to drive long-term value for shareholders. So very much appreciate it. Thank you very much, and we'll talk soon.

Good morning. My name is Tina, and I will be your conference operator today. At this time, I would like to welcome everyone to the Methanex Corporation Third Quarter 2025 Results Conference Call. [Operator Instructions]

I would now like to turn the conference over to the Director of Corporate Development and Investor Relations at Methanex, Ms. Jessica Wood-Rupp. Please go ahead, Ms. Wood-Rupp.

Good morning, everyone. Welcome to our third quarter 2025 results conference call. Our 2025 third quarter earnings 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 third 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, our 50% interest in the Natgasoline 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.

Good morning, everyone. We appreciate you joining us today to discuss our third quarter 2025 results. Our third quarter average realized price of $345 per tonne and produced methanol sales of approximately 1.9 million tonnes generated adjusted EBITDA of $191 million and adjusted net income of $0.06 per share. Adjusted EBITDA was higher compared to the second quarter of 2025, primarily due to higher sales of produced products, offset by our lower average realized price.

I'll start by providing an update on our newly acquired assets and integration activities. During the third quarter, both the fully owned Beaumont plants as well as the 50% owned Natgasoline plant operated at high rates, produced a combined 482,000 tonnes of methanol and 92,000 tonnes of ammonia. We have a structured 18-month integration plan across all functions of the business to ensure we fully realize the expected benefits of this highly strategic transaction. We've begun executing on our integration plan and working with our new team members at these manufacturing sites on asset and safety reviews. On the supply chain side, we've integrated the new logistics operations into our business to ensure we meet customer needs while focused on planned synergies. Given normal inventory flows, the high rates of third quarter production from these new assets will not fully flow through earnings until the fourth quarter of 2025.

Now turning to methanol market conditions. Global methanol demand was relatively flat in the third quarter compared to the second quarter across all downstream derivatives. Demand for methanol-to-olefins in China operated at high rates, consistent with the second quarter and increased to approximately 90% by the end of the quarter, supported by an increasing amount of import supply availability from Iran, which we estimate operated at close to 70% rates through the quarter. This increased supply from Iran, along with relatively high operating rates across the industry, led to an inventory build, particularly in coastal markets in China.

Looking ahead to the third quarter, we estimate the methanol affordability into MTO and the marginal cost of production in China to be approximately $260 to $280 per tonne. We continue to see spot and realized methanol prices in all other major regions at premiums to these pricing levels. We posted our fourth quarter European quarterly price at EUR 535 per tonne, representing a EUR 5 increase from the third quarter. Our North America, Asia Pacific, and China prices for November were posted at $802, $360, and $340 per tonne, respectively. We estimate that based on these posted prices, our October and November average realized price range is between $335 and $345 per tonne.

Now turning to our operations. Methanex production in the third quarter was higher compared to the second quarter with the full contribution from the new assets and higher production from Geismar, Medicine Hat, and New Zealand, which all experienced planned or unplanned outages in the second quarter. In Geismar, production was higher in the third quarter after the site experienced unplanned outages late in the second quarter. All plants returned to production in early July.

As previously noted, both the Beaumont and the Natgasoline facilities operated at high rates during the third quarter. In Chile, we operated the Chile I plant at full capacity throughout the quarter, marking the first time we've had one plant operating at full capacity throughout the Southern Hemisphere winter months for more than 10 years. During the quarter, the Chile IV plant successfully completed a planned turnaround and restarted at the beginning of October. We expect both plants to operate at full rates through to April 2026.

In New Zealand, we had higher production in the third quarter as the plant restarted in early July after a temporary idling of the operations to redirect contracted natural gas to the New Zealand electricity market. Gas supply availability in New Zealand continues to be challenged, and we're working with our gas suppliers and the government to sustain our operations in the country.

In Egypt, we operated at approximately 80% of capacity during the third quarter as gas availability during peak summer demand remains constrained. There has been stabilization of gas balances in the country, but some continued limitations on supply to industrial plants are expected going forward, particularly during the summer months.

The plant is currently operating at full rates. Our expected production -- equity production guidance for 2025 is approximately 8 million tonnes, which is made up of 7.8 million equity tonnes of methanol and 0.2 million tonnes of ammonia. Actual production may vary by quarter based on timing of turnarounds, gas availability, unplanned outages, and unanticipated events.

Now turning to our current financial position and outlook. In late June, we closed the OCI acquisition, consistent with our financing strategy, using proceeds from the bond issued in 2024 and borrowing $550 million under the Term Loan A facility. During the third quarter, we repaid $125 million of the Term Loan A facility with our cash flow from operations and ended the third quarter in a strong cash position with $413 million on the balance sheet. Our priorities for the rest of 2025 are to safely and reliably operate our business and continue to execute on our integration plan. Our capital allocation priority is to direct all free cash flow to deleveraging in the near term through the repayment of the Term Loan A facility. We do not anticipate significant growth capital over the next few years and remain focused on maintaining a strong balance sheet and ensuring we have financial flexibility.

Based on our fourth quarter European posted price, along with our October and November posted prices in North America, China, and Asia Pacific, our October and November average realized price is forecasted to be between $335 and $345 per tonne. Based on a slightly lower forecasted average realized price coupled with produced sales levels much closer to our run rate equity production, including the newly acquired assets, we expect meaningfully higher adjusted EBITDA in the fourth quarter of 2025 compared to the third quarter.

We'd now be happy to answer your questions.

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

Rich, can we talk about Trinidad? You saw Nutrien closure, and I'm not asking you to comment on their issue, but I believe you're next door. And so my questions are, what's your relationship with the NEC? Are they asking you for retroactive port fees or is that a risk? And then if Nutrien is down, which it is, does that mean more gas allocated to you?

Thanks, Ben. Yes, we have a contract with the NEC for port fees or port arrangements, that's not -- we're not in a similar situation there. As it relates to gas and gas availability, we're in a similar situation as we've been talking about in Trinidad, which is gas markets are tight. A lot of the downstream contracts come up at the end of -- most of them come up at the end of this year. Ours runs until September 2026. So we're in discussions with the NGC about gas. When we look at the gas outlook, we think that in the near term anyways that tightness remains. There are activities happening in Trinidad that over the next few years could mean some slight uptick on supply there. But we don't see a meaningful change to the situation we're in, which is a one plant operation.

And right now, we're operating one plant at full gas supply. So even if there were more gas available today, certainly, we wouldn't expect that a restart of Atlas or anything like that would make sense. There just isn't enough gas to go around today for all the downstream. So our situation will be focused on the next round of discussions for the current gas supply. We don't have a turnaround for Titan for some time. So that's our main focus and we're in discussions with the NGC.

And if I can just do a quick follow-up. Rich, you talked about kind of recontracting some of the OCI book. Can you just talk about that? What was the existing OCI book like and why does there need to be some recontracting now?

Yes. I think one thing to note is we did increase our sales. So you would have seen from Q2 to Q3, we increased sales by about 350,000 tonnes, which is about 1.4 million tonnes on an annualized basis. The assets are running extremely well. And so when you've got the production there, there could be some recontracting that we need to do for next year, certainly, we're in those discussions. In the near term, we'll take that into our supply chain. We'll actually flex as much as we can within our existing sales contracts. So we have flexibility to increase sales there. And then we'll be working if we had to do short-term contracts to the end of the year, we don't see that being significant. What you should expect though is in the fourth quarter, we will have higher sales than we did in the third quarter. And you should expect next year, the quarterly average sales to be higher than they were in the third quarter as well as we recontract for next year.

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

I'm going to ask 2, but I'll do one by one. Can you maybe give us an idea, could you quantify like if -- I mean, accounting you're able to -- if you do the Q4 accounting in Q3, what would have been the EBITDA like boost in Q3? Basically, how much is earnings hit by the accounting treatment the first month-and-a-half of Beaumont?

I think -- thanks, Joel. I think the way to think about it is that we had 1.9 million tonnes of equity production coming through sales. When we look at our production in the third quarter as well as into the fourth quarter, we now are at a point where we've got the asset base with the newly acquired assets closer to what we would say is our run rate with our new strengthened asset portfolio, which we think is really something that is going to -- we're working on is consistently demonstrating this performance. So when we think what is that run rate number, if we gave, when we introduced the OCI transaction, is about $9.5 million, a little bit more than that per annum of equity tonnes, including ammonia. So what should be coming through is about 2.4 million to 2.5 million tonnes. That's a delta of 500,000 to 600,000 tonnes versus Q3. So that's where the main earnings difference is coming from, which is a meaningful -- that's a meaningful increase in EBITDA.

And that's what we're expecting when we get into the fourth quarter is that sales of produced product is going to look more like our equity run rate. So that's why we're kind of guiding to a meaningful uplift as we move into the fourth quarter. We're not at $350 per tonne, but we're close. So it should be setting up to be a strong quarter.

Second question, just first, there were some news this week that maybe Natgas, the plant lost some gas or it was down. Tackle that for a second. And then I know you talked about before about turnarounds, maybe being able to do turnarounds maybe a year later than usual, looking at some of the [indiscernible] you have. Can you speak about that? And then I imagine Beaumont, Natgas, G3 wouldn't have to have turnarounds anytime soon. Also [indiscernible] Beaumont and Natgas probably wouldn't?

Yes. First on the Natgas point. I think there may be some interpretation from gas monitoring around the operations in Natgasoline. We don't really comment on kind of daily gas reports where I think where this has been picked up. Nothing should be read into that, that there's any significant issues happening at Natgasoline based on any of that information. So probably I'll end it there on that one.

But on the turnarounds, we have guided to about $150 million in CapEx per year, and that's 2 to 3 turnarounds a year. I think that's good guidance. We're always looking at ways that we can optimize around maintenance without sacrificing safety and reliability. And that's something that our team is consistently looking at. Within the $150 million, there's a good -- there's a meaningful amount of capital for the new assets, that's something we're looking at closer. But we're going to -- we would stick with the guidance of around $150 million on average and something we're always looking to further optimize.

Our next question comes from the line of Jeff Zekauskas with JPMorgan.

You ran Beaumont and Natgasoline at high rates, you expect to run them at high rates. Where is the methanol going? Are these going to North American customers or offshore customers? And if they're going to offshore customers, what kinds of customers are they? What products are they making?

Yes. I mean when we -- so when we introduced the OCI acquisition, what we had said was a large percentage of the contracted business we would expect would be in North America and Europe, and that's largely where we're selling the product. Obviously, the assets are running really well. And so there's some small uncontracted tonnes, which then we will increase the flexibility in our existing assets, our existing customer base as well as having to place some of those tonnes. That's a short-term basis. What our commercial -- global commercial team is working on now is looking at 2026 recontracting. And I think you can -- we give guidance about what our regional allocations look like on a percentage basis, and we would say those are the regional allocations to think about our global portfolio for next year.

In terms of which applications we sell into, we sell into -- we have diversified set of customers. So you can think of our sales portfolio as almost a representation of the breakdown of global methanol markets. And that's pretty much what it will look like next year, a well-diversified sales portfolio into different derivatives with a similar global allocation that we guide to in our investor deck.

Just maybe if I could try it one more time. Global methanol demand isn't really growing very much, if it's growing at all, and you've got extra production. So whose tonnes are you squeezing out?

Well, these tonnes were existent before we had them. So we're not squeezing out any tonnes. There is some incremental production over what we might have modeled. So we're talking about 200,000 tonnes in a 100 million tonne market, which isn't meaningful. So we're not worried about placing those tonnes. And methanol markets year-over-year, we would say, are growing -- it's growing about 2% to 3%. 2% to 3% is really being driven by China and Asia, where it represents 70% to 80% of global methanol demand. That's on the back of export manufacturing and strength in those markets as well as energy derivatives mainly in China. So the market is not growing at strong rates. The Atlantic and other markets generally flat. But we don't think that the market is in retreat and supply continues to be constrained, right? So we have a constrained methanol market with -- when we look at gas being either in mature gas basins or gas being redirected into LNG. Existing supply continues to be tight. So we're not concerned about having higher operating rates. Quite frankly, it's the opposite. We've got our assets in low-cost basins and it's highly profitable to have this production in our system.

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

First question just relates to capital allocation. I think, Rich, you talked about paying down the Term Loan A gradually. So from your perspective, would the balance sheet be in the right place after you fully repay the Term Loan A and obviously have a reasonable cash buffer on -- in place in your balance sheet? Would that be -- would you be done deleveraging at that point?

No, we won't be done deleveraging. But we do think the focus doesn't need to be entirely to deleveraging. We are -- our main focus in the near term is paying down the initial tranche, like you said. And if you look at the Term Loan A facility balance that we have, also consider that we've got excess cash on hand. We think we've got about $350 million left to go there, which is our primary focus. And really, our primary focus is we continuing to deliver what we're doing right now and what we've done through the third quarter and really focusing on conversion to cash for shareholders. Beyond the $350 million, we -- our debt target gets us back to our 3x debt to EBITDA. Our target has always been 2.5x to 3x, and we've got a debt tranche coming due -- a bond coming due in '27, which we wouldn't want to fully refinance.

Having said that, we believe we've got a really strong asset base with competitively -- stronger, more competitive asset base. And so the strength of the free cash flows is there that we can continue to deleverage and focus on the balance sheet. We don't have a significant growth capital, and there could be some room there as well for shareholder returns. But that's what we want to -- first, we want to get there and the focus on that is the $350 million that's in front of us. And it's really -- that's the primary focus today.

My next question is just in terms of, you talked about how you've started on the 18-month integration strategy. And obviously, it's still early days. But do you -- in terms of the -- I think it's roughly $30 million of anticipated synergies that you expect to realize. Can you give a bit more color in terms of where most of those benefits will come from?

Yes. So the $30 million is primarily IT-related, insurance related, logistics, which means terminals and other optimization around logistics. So it's -- those are relatively hard synergies, and we plan to be realizing those on an 18 -- it's more like almost a year period now, but 18 month -- 12- to 18-month period. Some of those are easier to get at in the near term than others. IT will take a little longer. The other elements of the deal, I think, is that we're really focused on is getting above deal value results. And when we look at that, we focus on the assets. We model these assets at a certain operating rate as well as annual capital and maintenance capital. And I think today, we're achieving above those results.

So our goal is to replicate that. And obviously, we're still early, and we're really focused on working with the teams, understanding the assets, how they operate the safe and reliable assets and be able to deliver and replicate this going forward. So that's the primary focus.

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

This is James Cannon on for Josh. I wanted to ask on New Zealand because I think last quarter, you guided to about 400 kt out of that unit this year. It seems you're tracking decently above that, but you held the overall guide relatively stable. Is there anywhere else in the portfolio you're seeing maybe weaker-than-expected results?

Yes. I mean, I guess I'll kind of caution around New Zealand. Right now, we've got the asset running at 60% to 70% rates through the third quarter on the one Motunui plant. That gas balance is, we're really tight on gas. The country is tight on gas and our gas allocation is allowing us to operate at minimum operating rates today. So it's still something we're really focused on. The 400,000 tonne sort of assumes that for part of the year, we would be shut in. But at the end of the day, we're really focused on how we maintain that 400,000 tonne based on gas supply today. So we're working closely with gas suppliers. When you look at the other assets in the portfolio, everything is pretty much on the guidance.

Egypt today, we're at full rates. We've come off the summer where we were at 80%, which is actually a very good result relative to the -- a lot of the -- that's usually where the demands on the grid are the highest. So today, Egypt is probably above. We've got 2 plants operating in Chile. So that run rate assumes the average for the year. So we're a bit above there. And then the other assets, we're pretty close. So things are going well right now. I think we need to think about that backdrop against how our newly acquired assets are running. And it sets up really well for us to demonstrate the strong free cash flow generation that we expect from the investments we've made, have P3 fully operating and really, I would say, the strength of the portfolio enhancement we've made with these assets. So that's our focus right now is continue to replicate that and focus on free cash flow conversion for shareholders.

[Operator Instructions] And your next question comes from the line of Laurence Alexander with Jefferies.

So can you give a sense for what's going on in terms of the global industry utilization rate and what you're seeing in terms of demand, in particular in Asia for DME and MTO applications? And then secondly, can you speak to how the IMO decision to defer the flex fuel mandate might affect the cadence of demand for methanol over the next couple of years?

Thanks, Laurence. Yes, from industry operating rates, Q2 and Q3 period tend to be the highest. And I would say across the industry, we've operated high. And what do I mean by that is if you look -- these are round numbers, but the Atlantic is operating at 80% operating rates. The Pacific, ex-China, is operating at 75% rates, and China is operating at 70% rates. Those may not seem high. But if you back out capacity that's permanently idled or gas feedstock that has been redirected or issues around, geopolitical issues that's constraining supply, the effective utilization is much higher than that.

So we would say that we're at very high operating rates and there's not a lot of latent capacity, especially when Iran is operating at 70% rates, which is seasonally high there. So notwithstanding that, we did see some build during the quarter in coastal markets in China. But as that built up, we've now seen MTO operating rates moving up above 90% and that meant that inventories are now moderating in the coastal markets in China.

So I think everything there tells us that even when everything is working, the market actually is relatively in balance. And then when we move into the Q4, Q1 period, supply gets restricted. And there actually isn't enough supply to meet all demand today, which is -- we would say this is a constructive market from that perspective. When you ask about MTO and DME demand, DME has been -- that demand is relatively flat. There's no -- it does go up or down a bit between 3.5 million and 4 million tonnes based on operating rates, but it's not really a move around the demand side. MTO moves up or down based on availability in the market as well as affordability there. And we've seen MTO continuing to operate now at high rates as we move into the fourth quarter. We would expect that might come under pressure as Iran gets restricted and there's less import supply availability. So hopefully, that answers the first question.

On the IMO, we -- first, on the marine side, that is the big upside for methanol and a new application. Obviously, 400 ships should be in the water between -- dual fuel vessels between now and the end of the decade, represents a big demand potential. The IMO, obviously, we were watching closely what the IMO would do around the adoption of the net zero framework. Really what that would have done if it were adopted and some of the guidelines that they were proposing were adopted, it would have enhanced the competitiveness of low-carbon methanol as a fuel to meet those regulations. So the deferral by -- it has been deferred by 1 year. It came up against meaningful political opposition. We think that 1 year deferral allows the IMO to line out their guidelines and spell those out more, which was a big pushback during the meeting, but the opposition is a big hurdle. So that's something we're going to closely watch.

The marine industry continues to support the net zero framework. There's been a lot of invested capital by shipping companies on investing incremental capital on dual fuel ships to meet low carbon regulations in the future. So something we're going to continue to watch. Our Low Carbon Solutions team will be working really closely with the marine sector on how that goes forward.

Our final question comes from the line of Jeff Zekauskas with JPMorgan.

How have you fared in buying gas forward for your new assets that you've acquired? And that gas prices have been pretty low from the time you bought it, but they've moved up. Are you hedged yet or do you have more to go? Or where do you stand?

Thanks for the question. The gas situation, when we acquired the assets, the OCI assets came to us largely unhedged. We already had our North American exposure. At least in the near term, we were hedged at around a 70% level on our existing book of assets. Where that puts us today is, I'll start, in the near term, we have hedged a little bit up. So we're closer to the 70% level to the end of the year across our total North American exposure. Into '26 and '27, the number gets closer to 50% to 60% hedged. We opportunistically enter the market if there's attractive pricing. Today, we wouldn't be looking to hedge at today's price. We will be seeking if the pricing drops below $3.50 as an example, we'll look to put in more. Today, we're comfortable with that open exposure and we'll opportunistically enter the market to layer more in when the pricing allows for that.

Interestingly, the near end of the curve isn't priced that way, but the longer end of the curve actually is priced lower, and we did some contracts below $3.50 on a nominal basis out beyond 2030 recently, not big contracts, but -- so we're always looking to seek competitively priced gas for us that's really favorable for our North American exposure.

So in terms of hedging near term, it might be that you wait until the spring before you really try to lift your purchases again. Is that a base case?

I mean it will be market determined. Of course, if we see the forward curve drop off for any reason and it's attractive, then we'll enter the market. I understand what you mean. Typically, we'll see some softening when inventories start to build so much as the gas market trades off of how inventories are trading. But we'll wait and see. And obviously, we've got a team that's reviewing these things daily and managing our exposure for us.

And with no further questions in the queue, I will now turn the call over to Mr. Rich Sumner.

Okay. Thanks again for joining the call this morning and for your questions and interest in our company. We hope you'll join us on November 13th for our Investor Day presentations and Q&A.

Thank you for your questions. And this concludes today's conference call. You may now disconnect.