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. 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 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 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 are 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 focusing 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 the 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.

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 arrangements, and we are not in a similar situation there. Regarding gas availability, we are experiencing similar conditions in Trinidad, where gas markets are tight. Most of the downstream contracts are expiring at the end of this year, while ours lasts until September 2026. We are currently in discussions with the NGC about gas supply. In the near term, we believe the tightness in gas supply will persist. There are developments in Trinidad that may lead to a slight increase in supply over the next few years, but we don't anticipate any significant changes in our current situation, which involves operating one plant fully supplied with gas. Even if additional gas were available today, we wouldn't expect a restart of Atlas to be feasible since there isn't enough gas for all downstream operations. Our focus will remain on the upcoming discussions regarding our current gas supply, and we do not have any turnaround planned for Titan for a while, so that's our main priority as we engage with the NGC.

And if I can just do a quick follow-up. Rich, you talked about 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 two questions, but I'll do them one at a time. Can you provide us with an estimate of how the Q4 accounting reflected in Q3 would have impacted the EBITDA? Specifically, what is the effect on earnings due to the accounting treatment during the first month-and-a-half of Beaumont?

Thank you, Joel. The key point to consider is that we achieved 1.9 million tonnes of equity production through sales. Looking at our production for the third quarter and into the fourth quarter, we now have an asset base, including newly acquired assets, that aligns with our expected run rate due to our strengthened portfolio. We believe this will consistently showcase our performance. Our estimated run rate number, which we discussed during the introduction of the OCI transaction, is around $9.5 million annually in equity tonnes, including ammonia. Therefore, we anticipate output to be around 2.4 million to 2.5 million tonnes, reflecting an increase of 500,000 to 600,000 tonnes compared to Q3. This change represents a significant rise in EBITDA, and we expect fourth-quarter sales of produced products to closely match our equity run rate. That's why we are anticipating a substantial uplift as we enter the fourth quarter. While we are not yet at $350 per tonne, we are approaching it, setting us up for 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 issues you have. Can you speak about that? And then I imagine Beaumont, Natgas, G3 wouldn't have to have turnarounds anytime soon.

Yes. Regarding the Natgas issue, there may have been some misinterpretation from gas monitoring related to our operations in Natgasoline. We don’t typically comment on daily gas reports where this concern seems to have arisen. It’s important to note that there are no significant problems at Natgasoline as indicated by that information. On the topic of turnarounds, we have provided guidance of about $150 million in capital expenditures annually, which covers 2 to 3 turnarounds each year. I believe that guidance is sound. We are always seeking ways to optimize maintenance while maintaining safety and reliability, which our team continuously focuses on. Within the $150 million, we have allocated a substantial amount for new assets that we are examining more closely. However, we will maintain our average guidance of around $150 million and continue to explore further optimization opportunities.

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. When we introduced the OCI acquisition, we indicated that a significant portion of the contracted business would be in North America and Europe, which is primarily where we are selling the product. The assets are performing very well. There are some small uncontracted tonnes, which will enhance the flexibility of our existing assets and customer base, while also allowing us to place some of those tonnes on a short-term basis. Our commercial global team is currently focused on recontracting for 2026. We provide guidance on what our regional allocations will be on a percentage basis, and those will give an overview of our global portfolio for next year. In terms of applications, we have a diverse set of customers, which means our sales portfolio reflects the breakdown of global methanol markets. This diversity will continue into next year, maintaining a well-diversified sales portfolio across different derivatives that aligns with our guidance in the 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?

These tonnes were already present before we acquired them, so we're not eliminating any tonnes. There is a slight increase in production compared to our previous models, approximately 200,000 tonnes in a 100 million tonne market, which is not significant. Therefore, we are not concerned about placing those tonnes. Year over year, methanol markets are growing about 2% to 3%, driven mainly by China and Asia, which account for 70% to 80% of global methanol demand. This growth is supported by strong export manufacturing and energy derivatives, particularly in China. Overall, the market is not expanding rapidly, while the Atlantic and other markets are mostly flat. However, we do not believe the market is declining, and supply remains constrained. We have a tightened methanol market, with gas either sourced from mature basins or redirected for LNG. Existing supply is still tight, so we are not worried about maintaining higher operating rates. In fact, the situation is the opposite. Our assets are located in low-cost basins, making production in our system highly profitable.

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

First question relates to capital allocation. Rich, you mentioned gradually paying down the Term Loan A. From your perspective, would the balance sheet be in the right place after fully repaying the Term Loan A and having a reasonable cash buffer? Would you consider the deleveraging process complete at that point?

No, we won't be done deleveraging. However, we believe the focus doesn't need to be solely on deleveraging. Our main priority in the near term is to pay down the initial tranche, as you've mentioned. If you look at the balance of our Term Loan A facility, we also have excess cash on hand. We estimate that there's about $350 million left to address, which is our primary focus. Furthermore, we are continuing to deliver on what we have been doing through the third quarter and concentrating on converting this into cash for our shareholders. Beyond the $350 million, our debt target aims to bring us back to a 3x debt to EBITDA ratio. We have always aimed for a target of 2.5x to 3x, and we have a bond maturing in 2027 that we would prefer not to fully refinance. Nonetheless, we are confident in our strong asset base, which is more competitive now, and the robustness of our free cash flows enables us to continue deleveraging and focusing on our balance sheet. We don't have significant growth capital needs, which may also allow for some shareholder returns. However, our immediate goal is to address the $350 million in front of us, and that remains our primary focus today.

My next question is regarding the 18-month integration strategy you mentioned. Although it's still in the early stages, can you provide more details about the approximately $30 million in anticipated synergies and where most of those benefits will originate?

Yes. The $30 million is mainly related to IT, insurance, and logistics, which involves terminals and other logistics optimization. These synergies are somewhat challenging to achieve, and we expect to realize them over a period of 12 to 18 months. Some benefits will be easier to realize in the near term than others, with IT taking a bit more time. Additionally, we are focused on delivering results that exceed the deal's expected value. We evaluate the assets based on specific operating rates and annual capital and maintenance costs. Currently, we are achieving results above those expectations, and our aim is to continue replicating that success. We are still in the early stages and are concentrated on collaborating with our teams, understanding the assets, ensuring they operate safely and reliably, and achieving consistent results moving forward. This is our main focus.

Our 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 want to caution regarding New Zealand. Currently, we're operating the Motunui plant at 60% to 70% capacity through the third quarter. We are experiencing a tight gas situation in the country, and our gas allocation is only sufficient for minimum operating rates at this time. We remain focused on maintaining the 400,000-tonne target, although it does assume some shutdowns during the year due to gas supply constraints. We are actively collaborating with gas suppliers. For the rest of our portfolio, performance is generally in line with guidance. In Egypt, we are currently running at full rates after an 80% rate over the summer, which was a strong result given the high demand on the grid during that time. We have two plants operating in Chile, and our annual run rate is slightly higher than expected there as well. Overall, most of our other assets are performing well, and it's important to consider how our newly acquired assets are contributing. We are well-positioned to showcase the robust free cash flow generation we anticipate from our investments, as we have the P3 fully operational now. Our main focus is to continue replicating this success and prioritize free cash flow conversion for our shareholders.

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, during the second and third quarters, industry operating rates are typically at their peak. We’ve observed that across the industry, we’re operating at high levels. For example, the Atlantic is running at about 80% capacity, the Pacific excluding China is at 75%, and China itself is at 70%. While these numbers might not appear high, when considering factors like permanently idled capacity, redirected gas feedstock, and geopolitical issues that limit supply, the effective utilization is noticeably greater. We would argue that our operating rates are quite elevated, with limited excess capacity, especially since Iran is achieving a 70% operating rate, which is particularly high for them seasonally. Despite this, we did notice an inventory build during the quarter in China's coastal markets. As this inventory increased, MTO operating rates surged above 90%, leading to a moderation of stocks in those coastal regions. All of this indicates a relatively balanced market, even when everything is functioning optimally. Moving into the fourth quarter and the following period, supply is expected to tighten, and the current supply is insufficient to meet demand, signaling a more constructive market environment. Regarding MTO and DME demand, the demand for DME has been relatively stable, fluctuating between 3.5 million and 4 million tonnes depending on operating rates but not experiencing significant changes from the demand side. MTO demand shifts based on market availability and price. Currently, MTO is maintaining high operating rates as we head into the fourth quarter, though there could be some pressure on it as Iran faces restrictions and import supplies decrease. Concerning the IMO and the marine sector, there's significant potential for methanol as a new application, especially given that around 400 dual fuel vessels are expected to be launched by the end of the decade, representing substantial demand. We're closely monitoring the IMO's actions on the net zero framework adoption. If adopted, this would have improved the competitiveness of low-carbon methanol as a compliant fuel. However, it has been deferred by a year due to considerable political opposition. We believe this one-year delay will provide the IMO with the opportunity to clarify their guidelines, which faced considerable pushback. The marine industry remains committed to the net zero initiative, with significant investments being made by shipping companies in dual fuel ships to comply with future low-carbon regulations. We will continue to track these developments, and our Low Carbon Solutions team will be collaborating closely with the marine sector moving 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. When we acquired the assets, the OCI assets were mostly unhedged. We already had our North American exposure, and in the near term, we were hedged at about 70% on our existing assets. Currently, we are nearing that 70% level for the end of the year across our total North American exposure. Looking ahead to 2026 and 2027, our hedged level is expected to be around 50% to 60%. We enter the market opportunistically when we find attractive pricing. At present, we are not looking to hedge given today's prices, but if prices fall below $3.50, we will consider increasing our hedges. For now, we are comfortable with our open exposure and will take advantage of market opportunities when favorable pricing arises. Interestingly, the short-term prices are not aligned, but the longer-term prices are lower, and we have secured some contracts below $3.50 for time periods beyond 2030, though they are not large contracts. We consistently seek competitively priced gas that benefits 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.