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. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star followed by the number one on your telephone keypad. If you would like to withdraw your question, press the pound key. Thank you. I would now like to turn the conference call over to the Vice President of Investor Relations at Methanex Corporation, Mr. Robert Winslow. Please go ahead, Mr. Winslow.

Good morning, everyone. My name is Robert Winslow, and I recently joined Methanex Corporation as Vice President, Investor Relations. Welcome to Methanex Corporation’s fourth quarter 2025 results conference call. Our fourth quarter 2025 news release and 2025 annual report were posted yesterday, and 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 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 Corporation’s President and CEO, 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 would 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 have had the best two years’ 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 have had zero Tier 1 process safety incidents over the past two 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 2,400,000 tonnes generated adjusted EBITDA of $180,000,000 and an adjusted net loss of $11,000,000. Adjusted EBITDA was lower compared to 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 are closely monitoring the current events in the Middle East region, 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. 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 tonne 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 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 customer discounts through recontracting for 2026, our first quarter average realized price is estimated to be $330 to $340 per tonne. Current escalation in the Middle East brings significant risk to the 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 tonne 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 planned 10-day outage to replace a catalyst that is important to environmental compliance. We have 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 three plants operated reasonably well, although we did experience some minor unplanned outages. In Chile, after completing a planned 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 2026. We are 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 has 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. We are 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 non-winter season. Notwithstanding the short-term dynamic, structural gas supply availability in New Zealand continues to be challenging, and we are working with our gas suppliers and the government to optimize our operations in the country. Our expected equity production for 2026 is approximately 9,000,000 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 $75,000,000 of the Term Loan A facility, and end the year in a strong cash position with $425,000,000 on the balance sheet. Since the start of 2026, we have repaid a further $50,000,000, and the balance of the Term Loan A facility is currently $300,000,000. 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 compared to the fourth quarter. We will now open for questions.

At this time, I would like to remind everyone, in order to ask a question, press star then the number one on your telephone keypad. We encourage everyone to limit yourself to one question and one follow-up. You are welcome to requeue for additional questions. Your first question comes from the line of Joel Jackson with BMO Capital Markets. Your line is open.

Thanks, everyone. Welcome aboard, Rob. Nice to hear from you again. Rich, team, can you talk about costs? So if you 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 is going on? Are there any artifacts, some of the things going on with the OCI, taking over the OCI asset? Thanks. And then my second question is, obviously, you all know what is going on in the world. And there is 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 is early, but what do you think is going to happen here in the market? If this continues, can you talk about what we will see in the short term, the medium term, as you see your business potentially changing from what is going on?

Joel, a couple of points I would make on cost is we did see the unabsorbed cost come through. That is really about how the assets ran through December. We saw some outages that resulted 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 a higher percentage of sales coming through in the last few quarters, which is higher than we expect as we move into the new year with our contracted position. We are not yet all the way through the OCI transaction. Right now, we are spending costs as we move through to create the synergies post-deal, and that will happen through 2026 into 2027. We are not all the way there, obviously, and what we need to do is to continue the integration plans, and as we move through, we would expect beginning in 2027 that our fixed cost structure also adjusts down to the new base of the business. For your second question, I think for us, our first priority here is our supply to customers. This is where our reliability of supply and our global supply chain really demonstrates its value. Where we are today, that is our first commitment. Pricing has increased in all regions with anticipation of tightness coming out because the amount of tonnes on the internationally traded market here is quite meaningful that is currently impacted. Our first commitments are to our customers, and as of right now, we will see some benefits because of the tightness on pricing through March, but the real reset will come through into the second quarter. I think we are talking about around 15 to 20 million tonnes of the globally traded methanol market here, so it is a significant impact which will ultimately impact all global markets, and we have seen pricing come up around the world. We are watching things really closely here, obviously, with our customers, trying to ensure 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 we are watching things very closely, and we are really talking to all our customers about how we can keep them supplied through this.

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

Thank you very much, and good morning. 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. 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? 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. We are a term contract supplier, so our first priority is our commitment to our customers, and we reset price monthly. Right now, we are 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. Our first priority today is the security of supply to our customers globally. Of course, there are certain mechanisms in our contracts which may adjust slightly, and that is built into our forecast, so you could see that there could be a little bit of a push-up in our guidance on where pricing is for the first quarter, but generally, it will reset into April. Our first commitment is about how we ensure the industry operates for our customers and help them take care of their business. On your follow-up, no, we are not aware of any damage to any methanol facilities. We are monitoring the situation really closely. As far as it relates to the gas supply from Israel into Egypt, our understanding is that gas is not flowing, as they have all but shut down the gas imports from Israel today. We are 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 more supply through LNG imports. So far, we have sustainable operations there, but we are watching things and monitoring them really closely.

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

Hi. Good morning. 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? And with respect to 2026, the 9,000,000 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 the most fluid.

I think Q1 is the reset, Hamir. When we think about where our realized pricing is for Q1, if you go region by region, China is going to be up because we saw the supply built in China through Q4. 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 are relatively flat on an realized basis. So that should be a resetting. The discount for Q1 should be a good guide for the rest of the year, and then on an average realized basis, we are expecting to be up a little bit. This is all pre the current developments. Prior to the current situation, we were going to be slightly up mainly because of China and factoring in those other considerations. On your production question, you can think of it in terms of a little over 6,000,000 tonnes in North America, about 1,300,000 to 1,400,000 tonnes for Chile, which is consistent with where we were last year, around 0.5 to 0.6 million tonnes for Egypt, which is obviously less than around an 80% operating rate, and then Trinidad would be one plant, really the Titan plant, around 800,000 tonnes. For New Zealand, our guide is less than half a million tonnes, and that is because of the situation we face with gas supply. Those are rough numbers to help you break that out by plant.

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

Good morning, and thanks for the time. I want to go back to the discount issue, or perhaps even 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 average. Has there been a material shift in the sales mix here in the last two quarters relative to prior? It does seem that the formulas we used in the past are becoming outdated. 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 that cadence, is it running as planned, and you think you suggested even full rate? Is there anything else in the tempo that we should expect to change over the balance of the year, whether it be turnarounds or other major pickups?

I think what we do is give guidance in terms of percentages in regional allocations, Steve, so you can use those as a good guide. The proportion of China was higher as we moved through Q4 for sure, and that is partly because, when we acquired the assets, we did inherit a fairly large uncontracted position from the OCI business. We contracted into Q1 now, and I think if you work the percentages and the pricing, you would get close to our ARP, but we can help you with that offline if, for some reason, it is not adding up. On Geismar, we are pleased with the operation. We have gotten through the ATR challenges that we had, and we feel really good about the way the asset is running. In a lot of ways, it is about just continuing to ensure safe, reliable operations in Geismar, and the team is doing a fantastic job there. We have put those issues behind us, and right now, we have really good stable production coming out of Geismar.

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

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 in January, was that something that you felt, or were you hedged against it? And in Trinidad, do you expect your operating rates to rise relative to the fourth quarter or fall in the first quarter?

Thanks, Jeff. Our hedging today, what we are guiding towards, is about 50% hedged for our North American assets, and that is across the whole portfolio. We did see gas pricing, as we always do, come up through the winter period, and then we did hit the gas spike. We will talk more about our operations when we get to our first quarter results, but we would normally expect gas prices to come up, and we have different ways to manage that. We would have had some open exposure, but we would have been managing that. We will talk more about that in our first quarter. We do expect the gas pricing, and that is part of the guide—really, when we look at slightly higher earnings, part of the reason that it is 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 will give more information on when we disclose that in the coming weeks. In Trinidad, we are running the one plant, the smaller Titan plant, based on our gas contract for the plant. We expect that operation to be very consistent, and we will 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 the September timeframe, and we would expect to have good operations from that plant up until that time. We are already looking at the contract renewal. Most producers are already in discussions for their feedstock recontracting in Trinidad, and we are making sure we are in discussions as ours comes up later in the year. I would anticipate that we are running that plant at similar rates to last year until that time.

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

Hi. Good morning. It is Chris Perilla on for Josh. As you had lower production out of the OCI, the acquired assets sequentially, can you give us an update on the integration there and what the cost puts and takes over the course of 2026 are, or what you are budgeting for the spend to get the synergies? 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 update if the gas supply situation in Trinidad, absent contracts, has improved since the events in Venezuela?

The first thing I would say about the assets is we are pleased with the way the operations are going there. When we modeled the acquisition, we used operating rates of around 85% to 90%, and we have definitely achieved over and above that since we have owned the assets. We are really impressed with the teams that we are working with, and we are working collaboratively together to bring our global expertise and work with the expertise at both sites to create value from the asset. We did have some downtime in Natgasoline, and that was partly getting ahead of environmental compliance and taking a proactive outage, and then we did have some minor downtime at the Beaumont plant as well. On the other parts of the integration, we said about $30,000,000 in synergies that we were targeting to realize by the end of 2026. We have realized some of those, but you also have to take on higher costs when you are integrating systems and integrating teams during that phase. We are in the middle of that right now, and we would expect to complete that as we move through 2026 and then have realized the $30,000,000 in synergies as we move into 2027. To your spend question, no, when we did the modeling around the deal, we set assumptions around operating rates and an assumption around CapEx spend on average per year. The plants have been operating above our assumptions on the deal, and both of the assets have come off turnarounds in 2024 and 2025, so the CapEx spend relative to where we had deal assumptions, which would have been an average, is much lower in the early phase of the asset, which is good for us because we are in a deleveraging period. On your question regarding Venezuela, there are announcements about fields being developed there for import into Trinidad. That is a longer term. When we look at the Dragon field that has recently been announced, the things I would say are: the size of these fields relative to the demand-supply gap suggests more than just the Dragon field needs to be developed; there are other fields also being developed, but that is going to take time and a lot of progress; and ultimately, we will also need to ensure that the commercial agreements and pricing for that gas allow that to make sense long term for methanol. There is a lot to be done there. Our focus is really on the short term right now—how we are operating our plants in Trinidad with a contract renewal 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. Your line is open.

Great, thanks, and good morning. Quick question on the supply-demand dynamics. Rich, you talked about potential demand destruction. I think you talked about in the past how MTO facilities’ economics are somewhat challenged. Do you expect a large reduction in MTO demand, and from your customer perspective, do you have a sense of how price sensitive they are? And then in terms of your production in New Zealand, it is staying relatively low in 2026. I presume that facility is marginally profitable. What are some of the key factors you look at in terms of making a decision to potentially mothball that last plant?

Thanks, Nelson. There are a lot of dynamics going on right now. Just in terms of MTO and MTO affordability, to your point, the price in methanol is rising, but so is the price downstream in the olefins market, and that is because it is not just methanol that is constrained, but so is naphtha, and so are all the oil derivatives that come out of the Middle East, which means that pricing has gone up. Olefins pricing has gone up, which makes methanol more affordable. So there are a lot of dynamics at play right now. That is what is uplifting the China price, but their pricing in the downstream has gone up too, so the affordability dynamics are changing as well. What is going to happen here, depending on the restriction on supply, is how that supply gets directed into which markets, and then what that does to price. We are watching things really closely. Right now, all energy and energy derivatives are lifting up because the demand-supply gap continues to grow every day that there is disruption in that region and not a lot of product flowing out. We are going to monitor this very closely. Our commitments are to work with our customers on security of supply, and we certainly see that there will be pressure until some relief comes into the market. On New Zealand, it really comes down to gas development and production out of the fields. These are very mature fields, and outside of the existing fields, there is not a lot of new exploration going on. Our concern would be that we have seen the forecast continue to decline. In that industry, you have to see capital going in and development consistently happening for operations to be sustained. Today, we have a profitable operation, but even when there is peak gas available, we are operating one plant at less than full rates, which is not ideal. We are watching things really closely and working with gas suppliers as well as the government to sustain operations, but it is a tough outlook right now.

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

Great, thanks for taking the question. Could you talk about whether you are truly realizing the benefits of the OCI acquisition that closed in mid-2025? I am just looking at the total company EBITDA in Q3 and Q4, which is roughly flat to Q2, even though global spot methanol prices are also about flat, and I think the OCI acquisition should have provided at least $150,000,000 to $200,000,000 in EBITDA. Is this just a function of Q3 having some accounting headwinds, and Q4 sounds like some unplanned outages, but are you getting the benefits of that OCI deal rolling through? And 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 a contract basis?

I think maybe the way to answer this is to look at the numbers that we had on the deal. At a $350 methanol price, we said it was slightly over $1 billion in EBITDA. Methanol prices today are not at $350 per tonne. That is $20 lower across an asset base that is 9,000,000 tonnes. So the big thing is price. We are also pre-synergies on the deal, so we have not realized the synergies, and there are some other things on cost structure that are slightly above what our assumptions would have been on the deal. 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. In today’s environment, we would be looking, at least in the short term, at going above $350. On your exports question, we run our global supply chain. Our assets feed our global supply chain. We give our regional sales percentages, and then you can see where our assets are located. Our product is not assigned to any particular region. It is a flexible supply chain where our main priority is to keep our customers supplied in the most cost-effective manner. We do 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. Your line is open.

Good morning. First, can you help parse what the current situation means for the market in terms of the near term? How much of the near-term disruption is shipping being rerouted, and 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 me parse the near-term supply chain adjustment versus how you are thinking about the demand adjustment? And secondly, on your shipping fleet, given that you can reroute tankers more quickly than somebody who is using shipments that might be contracted to ship other products rather than being committed to methanol, will you be seeing a benefit in Q2 or Q3 from that, and can you help size it?

Thanks, Laurence. When we look at what supply is impacted today, Iran puts into the market around 9 to 10 million tonnes a year, and when you combine Saudi Arabia, Oman, Qatar, Bahrain, and other countries that are going to be impacted, it is probably another 9 to 10 million tonnes. Of a 100 million tonne market, but really a globally traded market of 55 million tonnes, this is a pretty big impact. Of course, Iranian supply goes only into China, so that is a direct impact on the China market, and then the other product services mainly the Asia Pacific region, as well as some into Europe. Those trade flows today have stopped. How long this lasts, how quickly you are going to first work off inventories, and how long people have inventory will ultimately determine how long people can operate. Our first commitment here is to our contract customers and the security of supply that we provide through our contracts, and that is our number one commitment. We will continue to monitor this as it evolves because it is certainly hitting methanol and a lot of other downstream oil and energy products as this develops. On shipping, our time charters certainly give us that security within our supply chain, and we have very little spot exposure in our fleet. We have seen shipping rates double on a lot of the lanes that we run. It is more about what it does to our competitors compared to what it does to us. To the extent that pricing has to go up to help our competitors cover costs to meet security of supply, that is going to be baked into the pricing, which we can benefit from. It is not an immediate, instant hit to our cost structure because ours are fixed in, but we do think that is partially compensated through increasing price that is required to get other products into the market. Again, that is another factor that we will be watching, and this 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. Your line is open.

Thanks. 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 excess cash flow coming in the door? Is it just going to accelerate the paydown of Term Loan A? You have been at that a fairly rapid pace thus far anyways, but is that how we should think about that excess flow that comes in the door?

Our first commitment is to our balance sheet right now. We have, as I said in the remarks, $300,000,000 left on the Term Loan A, and that is our first priority for cash. Of course, we are 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 change. But our first priority and commitment is to the balance sheet post-deal, and right now, this pricing environment is very supportive of that.

Appreciate your time. Thanks.

Thanks, Steve.

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

Thank you for your questions and interest in our company. We hope you will join us in April when we update you on our first quarter results.

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