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. All lines have been placed on mute to prevent any background noise. After the speaker's 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 over to the Director of Corporate Development and Investor Relations at Methanex, Ms. Jessica Wood-Rupp. Please go ahead. Good morning everyone. Welcome to our third quarter 2025 results conference call. Our 2025 third quarter news release, Management's Discussion and Analysis, and financial statements can be accessed from the Financial Reports tab of the Investor Relations page on our website at methanex.com. I would like to remind our listeners that our comments and answers to your questions today may contain forward-looking information. This information by its nature is subject to risks and uncertainties that may cause the stated outcome to differ materially from the actual outcome. Certain material factors or assumptions were applied in drawing the conclusions or making the forecasts 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 net 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 are 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 ton and produced methanol sales of approximately 1.9 million tons generated adjusted EBITDA of $191 million. An 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 product, offset by a 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 plant as well as the 50% owned Natgasoline plant operated at high rates, produced a combined 482,000 tons of methanol and 92,000 tons 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, an increase 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- $280 per ton. 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 of EUR 535 per ton, 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 ton respectively. We estimate that based on these posted prices, our October and November average realized price range is between $335 and $345 per ton. 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 plant 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 equity production guidance for 2025 is approximately 8 million tons, which is made up of 7.8 million equity tons of methanol and 0.2 million tons 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 ton. 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 question. This time, I would like to remind everyone, in order to ask a question, press star, then the number one on your telephone keypad. Our first question comes from the line of Ben Isaacson with Scotiabank. Thank you. Please go ahead. Thank you very much and good morning everyone. Rich, can we talk about Trinidad? You saw Nutrien's closure and I'm not asking you to comment on their issue, but I believe you're next door. My questions are, what's your relationship with the NGC? Are they asking you for retroactive port fees or is that a risk? If Nutrien is down, which it is, does that mean more gas allocated to you? Thank you. Thanks, Ben. We have a contract with the NGC for port fees. Port arrangements, that's not, you know, 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 this year. Ours runs until September 2026. 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 over the next few years that 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. Right now we're operating one plant at full gas supply. 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. 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. That's our main focus and we're in discussions with the NGC. 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? Thank you. Yeah, I think one thing to note is we did increase our sales. You would have seen from Q2 to Q3 we increased sales by about 350,000 tons, which is about 1.4 million tonnes on an annualized basis. When the assets are running extremely well and 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 contract, 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 re-contract for next year. Great, thanks so much. Our next question comes from the line of Joel Jackson with BMO Capital Markets. Please go ahead. Good morning. Thanks for taking my questions. I'm going to ask two. I'll do one by one. Can you maybe give us an idea? Could you quantify like if on the accounting you're able to, if you were able to use Q4 accounting in Q3, what would have been the EBITDA like boost in Q3? Like basically how much was earnings hit by the accounting treatment the first month and a half of Beaumont and Natgasoline, I think. Thanks Joel. I think the way to think about it is that we had 1.9 million tons 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. When we think what is that run rate number we gave when we introduced the OCI transaction, it is about 9.5 million, a little bit more than that per annum of equity tons including ammonia. What should be coming through is about 2.4 million- 2.5 million tons. That's a delta of 500,000- 600,000 tons versus Q3. That's where the main earnings difference is coming from, which is a meaningful, you know, 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. That's why we're kind of guiding to a meaningful uplift as we move into the fourth quarter. We're not at, we're not at $350 per ton but we're close. It should be setting up to be a strong quarter. Thanks for that. Second question, just first there were some news this week that maybe Natgas 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 processes you have. Can you speak about that? I imagine, you know, Beaumont, Natgas, G3 wouldn't have to have turnarounds anytime soon. At least Beaumont Natgasoline probably wouldn't. Yes. First on the Natgas, I think there may be some interpretation from gas monitoring around the operations in Natgasoline. We don't really comment on, you know, kind of daily gas reports where I think where this has been picked up. Nothing should be read into that there's any significant issues happening at Natgasoline based on any of that information. I'll probably end there on that one. On turnarounds, we've guided to about $150 million in CapEx per year and that's two to three 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 is a good, you know, there's a meaningful amount of capital for the new assets. That's something we're looking at closer, but we would stick with the guidance of around $150 million on average and that's something we're always looking to further optimize. Our next question comes from the line of Jeff Zekauskas with JP Morgan. Please go ahead. Thanks very much. You know you ran Beaumont and Natgasoline at high rates. You expect to run them at high rates. Where's the methanol going? Are these going to North American customers or offshore customers? If they're going to offshore customers, what kinds of customers are they, what products are they making? Yeah, 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. That's largely where we're selling the product. Obviously the assets are running really well and there's some small uncontracted tons which then we will increase the flexibility in our existing asset or existing customer base as well as having to place some of those tons. That's a short-term basis. What our global commercial team is working on now is looking at 2026 recontracting and I think 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 have a diversified set of customers. You can think of our sales portfolio as almost a representation of the break of global methanol markets. That's pretty much what it'll 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 really growing very much if it's growing at all and you've got extra production. Whose tons are you squeezing out? These tons existed before we had them so we're not squeezing out any tons. There is some incremental production over what we might have modeled. We're talking about 200,000 tons in a 100 million ton market which isn't meaningful. We're not worried about placing those tons and methanol markets year over year we would say are growing, it's growing about 2%- 3%. 2%- 3% is really being driven by China and Asia where it represents 70%- 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. The market's not growing at strong rates. The Atlantic and other markets generally flat. We don't think that the market's in retreat, and supply continues to be constrained. We have a constrained methanol market. When we look at plants, gas being either immature gas basins or gas being redirected into LNG, existing supply continues to be tight. 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. Great, thank you so much. The next question comes from the line of Nelson Ng with RBC Capital Markets. Please go ahead. Great, thanks. First question just relates to capital allocation, I think. Rich, you talked about paying down the Term Loan A gradually. 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 in place in your balance sheet, 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. Our main focus in the near term is paying down the initial tranche like you said. 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. Our primary focus is 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, our debt targets get us back to our three times debt to EBITDA. Our target has always been two and a half to three times. We've got a debt tranche coming due, a bond coming due in 2027, which we wouldn't want to fully refinance. Having said that, we believe we've got a really strong asset base with a more competitive asset base, and 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 significant growth capital, and there could be some room there as well for shareholder returns. First, we want to get there, and the focus on that is the $350 million that's in front of us, and that's the primary focus today. Okay, got it. 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 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? Yeah. The $30 million is primarily IT-related, insurance-related, logistics, which means terminals and other optimization around logistics. Those are relatively hard synergies, and we plan to be realizing those on an 18 months, it's more like almost a year period now, but 18 months, 12 month- 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 that we're really focused on is getting above deal value results. 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. I think today we're achieving above those results. Our goal is to replicate that. 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 being able to deliver and replicate this going forward. That's the primary focus. Great. Thanks for the color. I'll leave it there. Thank you. Your next question comes from the line of Josh Spector with UBS. Please go ahead. Hey guys, this is James Cannon on for Josh. Thanks for taking my question. I wanted to ask on New Zealand because I think last quarter you guided to about 400,000 tons 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? Yeah, I mean I guess I'll kind of caution around New Zealand. Right now we've got the asset running at 60%- 70% rates through the third quarter on the one Motunui plant. That gas balance is, we're really tight on gas. The country's tight on gas and our gas allocation is allowing us to operate at minimum operating rates today. It's still something we're really focused on. The 400,000 tons sort of assumes that for part of the year we would be shut in. At the end of the day we're really focused on how we maintain that 400,000 tons based on gas supply today. 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 a lot of the, that's usually where the demands on the grid are the highest. Today Egypt's probably above. We've got two plants operating in Chile, so that run rate assumes the average for the year. We're a bit above there. The other assets were pretty close. Things are going well right now. I think when you think about that backdrop against how our newly acquired assets are running, it sets up really well for us to demonstrate the strong free cash flow generation that we expect from the investments we've made having G3 fully operating and really I would say the strength of the portfolio enhancement we've made with these assets. That's our focus right now is continue to replicate that and focus on free cash flow conversion for shareholders. Great, thank you. If you would like to ask a question, simply press star one on your telephone keypad. Your next question comes from the line of Laurence Alexander with Jefferies. Please go ahead. 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? 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. From industry operating rates, the Q2 and Q3 period tend to be the highest and I would say across the industry we've operated high. What do I mean by that? If you look, these are round numbers, but the Atlantic's operating at 80% operating rates, the Pacific ex China is operating at 75% rates, and China's 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. We would say that we're at very high operating rates and there's not a lot of latent capacity, especially when Iran was operating at 70% rates, which is seasonally high there. Notwithstanding that, we did see some build during the quarter in coastal markets in China. As that built up, we've now seen MTO operating rates moving up above 90% and that's meant that inventories are now moderating in the coastal markets in China. I think everything there tells us that even when everything is working, the market actually is relatively imbalanced. 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 a, we would say this is a constructive market. From that perspective, when you asked about MTO and DME demand, DME demand is relatively flat. It does go up or down a bit between 3.5 million and 4 million tons 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. 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. Hopefully that answers the first question on the IMO. First, on the marine side, that is the big upside for methanol on a new application. Obviously, 400 ships should be in the water between dual fuel vessels between now and the end of the decade, which 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. The deferral has been deferred by one year. It came up against meaningful political opposition. We think that one year deferral allows the IMO to line out their guidelines and spell those out more, which was a big pushback during the meeting. 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. That's 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. Thank you. Our final question comes from the line of Jeff Zekauskas with JPMorgan. Please go ahead. Thanks very much. How have you fared in buying gas forward for your new assets that you've acquired? In that gas prices have been pretty low from the time you bought it, but they've moved up. Are you hedged yet or 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 2026 and 2027, the number gets closer to 50%- 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. We did some contracts below $3.50 on a nominal basis out beyond 2030 recently. Not big contracts, but we're always looking to seek competitively priced gas for us that's really favorable for our North American exposure. 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'll 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. Much of the gas market trades off of how inventories are trading. We'll wait and see and obviously we've got a team that's reviewing these things daily and managing our exposure for us. Okay, thank you very much. Thank you. With no further questions in queue, I will now turn the call over to Mr. Rich Sumner. 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. This concludes today's conference call. You may now disconnect.