Morning. My name is Pam, and I will be your conference operator today. At this time, I would like to welcome everyone to the Methanex Corporation 2024 Third Quarter 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. Press the pound key. Thank you. I would now like to turn the conference call over to the Director of Investor Relations at Methanex, Ms. Sarah Herriott. Please go ahead, Ms. Herriott.

Good morning, everyone. Welcome to our third quarter 2024 results conference call. Our 2024 third quarter news release, management discussion, and analysis may 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 2024 MD&A and our 2023 annual report 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 the guidance between quarters. For clarification, any references to revenue, EBITDA, adjusted EBITDA, cash flow, adjusted income, adjusted earnings per share made in today's remarks reflect our 63.1% economic interest in the Atlas facility, our 50% economic interest in the Egypt facility, and our 60% interest in Water Tripping. These exclude the mark-to-market impact on fair value creation and the impact of certain items. If you report our adjusted data, adjusted net income is associated with specific items. These items are non-GAAP measures and ratios not standardized or prescribed by GAAP and therefore are less comparable to similar measures presented by other companies. We report GAAP measures in this way because we believe they better reflect underlying performance, and we encourage analysts covering the company to report their estimates in this manner. I will now turn the call over to Methanex's President and CEO, Mr. Rich Sumner, and then we will have a question and answer period.

Thank you, Sarah, and good morning, everyone. We are beginning today as we discuss our third quarter 2024 results. Our third quarter average price of $356 per ton produced sales of approximately 1.4 million tons generated adjusted EBITDA of $216 million and adjusted net income of $1.21 per share. Adjusted EBITDA was higher than the second quarter of 2024 primarily due to the gas sales, and I am proud of the team for taking a safety and reliability-based approach to ramping up G3 to operate at full rates for the long term. Now turning to the third quarter methanol pricing and market dynamics. Our third quarter global average realized price was $356 per metric ton, $4 higher than the previous quarter. Global methanol demand was stable in the third quarter compared to the second quarter, with relatively flat demand into chemical applications and seasonally higher demand for energy applications such as MTBE and fuel blending. Methanol to Olefins operating rates decreased at the beginning of the quarter due to seasonal maintenance as well as tight supply availability, and operating rates increased throughout the quarter as supply improved. Methanol inventories gradually rebuilt. By the end of the quarter, the MTO industry was operating at around 90% operating rates. On the supply side, third quarter global production was similar to the second quarter production levels, with different trends between basins. In Asia and China, we saw increased supply from the Middle East, including Iran, leading to an inventory build and supply availability leading to increased MTO rates. Methanol prices in China remained fairly stable between $280 and $300 per ton. Supply in the Atlantic basin remained tight and further tightened through the quarter due to various issues including feedstock constraints, seasonal maintenance, and unplanned outages leading to a meaningful inventory drawdown and significant price strengthening in the Atlantic region. That has continued into the fourth quarter. Now turning to our production. Methanol production in the third quarter was lower compared to the second quarter due to the temporary idling of operations in New Zealand and gas constraints in Chile and Egypt. In New Zealand, operations were temporarily idled in August as we entered short-term commercial arrangements to provide contracted natural gas into the New Zealand electricity market until the end of October 2024. As of November 1, we safely restarted one plant and are again producing methanol. The current gas outlook from our gas suppliers for the next few years indicates gas supply will be sufficient to operate only one plant. Therefore, we have made the difficult decision to indefinitely idle one of the two Matsunui plants. We have optimized the operating and capital cost and free cash flow impact from idling one plant and expect these actions will substantially offset the adjusted EBITDA. We remain committed to working with the government and gas suppliers to support gas developments, and future production will be dependent on gas availability and any on-selling of gas into the electricity market to support New Zealand's energy needs. I would like to personally thank our team in New Zealand for all their hard work and dedication as we transition to one plant operation. In Chile, I am very happy to share that we have successfully agreed to extend two gas contracts that underpin 55% of the site needs until 2030 and 2027 on similar economic terms. In addition, we secured agreements to purchase gas from Argentina to allow us to operate two plants at full rates for the non-winter months from the beginning of October this year through the end of April 2025. Combined, these contracts will allow us to continue to underpin and progressively increase our production from Chile over the coming years. In Egypt, industrial plants were impacted by gas curtailments due to increased seasonal demand for power generation. Due to elevated temperatures coupled with lower domestic supply, various measures were taken by the government to manage gas balances, including curtailments to industrial plants. There has been stabilization of gas balances in the country as temperatures have moderated, but some continued limitations on supply to the plant are currently operating at full rates. I would also like to recognize and thank our team in Trinidad who safely idled the Atlas plant and restarted the Titan plant, which had been in preservation mode since March 2020, with no disruption to production. This changeover removes one million tons of methanol from the global market and reduces our equity production by approximately 200,000 tons. We continue to work closely with the National Gas Company of Trinidad to secure longer-term gas to ensure sustainable operations in Trinidad beyond the current gas contract that expires in September 2026. Now turning to our current financial position and outlook. We ended the third quarter with approximately $490 million of cash and continued access to our $500 million undrawn revolving credit facility. We are on track to repay the $300 million bond due on December 1, 2024, after which our debt to adjusted EBITDA ratio will be just under three times at a $350 per ton realized price. We recently announced we have secured $650 million in term loan commitments to fund a portion of the OCI transaction. Once the OCI transaction has closed, our top priorities will be completing a safe and effective integration, realizing synergies from the transaction and across our business, and deleveraging. We plan to return to our pre-OCI deal leverage level by repaying $550 million to $600 million over the next eighteen months, assuming a $350 realized methanol price. Beyond this, we do not see meaningful capital over the next few years and remain committed to maintaining a strong balance sheet with a 2.5 times debt to adjusted EBITDA target. With a strong free cash flow profile from our existing assets, which will be enhanced with the OCI transaction acquisition, we believe we are well-positioned to take a balanced approach including deleveraging and shareholder distributions depending on future market conditions and methanol prices. Turning to the fourth quarter. Our European quarterly price was posted at €570 per ton, a €35 per ton increase from the third quarter. Our November North American posted price was $785 per metric ton, a $47 per ton increase from October. In Asia Pacific and China, November prices were rolled at $400 and $380 per ton respectively. We estimate that based on these posted prices, our October and November average realized price range is between approximately $365 and $375 per metric ton. Our expected equity production guidance for Q4 2024 is approximately 1.9 million tons. This will be sold through the fourth quarter of 2024 and the first quarter of 2025 as produced sales normalize to increased production. In the fourth quarter, we expect similar adjusted EBITDA compared to the third quarter, with higher produced sales and a higher average realized price offsetting lower New Zealand gas sales and the one-time Egypt insurance recovery in the third quarter. We would now be happy to answer questions.

If you would like to ask a question, please press star followed by the number one on your telephone keypad. Your first question comes from Josh Spector with UBS. Your line is open.

Hey, guys. This is James Cannon on for Josh. Thanks for taking my question. I just wanted to dig in on the New Zealand guide. I think the 600 KT that you called out in the print reflects Q4 production less than half on that one unit. Is there a matter of just ramping the unit back up, or are there ongoing constraints? And if there are, what level do you expect to be able to run the plant kind of on a run rate?

We are expecting that as of the end of October here, we are running one plant at full rates. You know, that is something that we are obviously assessing as we go forward. But, yeah, we have really geared the plant to one plant operation. Of course, we will be looking at our gas profiles as we go forward, but that is the level where we expect to be at.

Okay. And then just kind of as I think about what went on over the summer, it does not seem like there is much improvement baked into the gas supply forecast for New Zealand. So did you anticipate this kind of imbalance to persist going forward, or was there anything one-off that contributed to the level of imbalance this year that led to the shutdown in the sale of gas?

Well, the shutdown in the sale of gas was really due to what was happening on domestic energy balances through that period where there was a drop for gas for power generation. So we onsold our gas during that period and really forwent producing methanol. Coming out of that, we had to assess where we were. We were already operating, you know, we had initially guided to about a 1 to 1.1 million production rate for the year, and we were receiving gas lower than that. So coming out of the gas sales, we had to assess in the near to medium term, what does the gas outlook look like? And really, the forecast looks like enough gas to run a one plant operation, and it did not make sense to be gearing to a two plant operation with the operating structure and capital programs required to run a two plant on a sustainable basis. So we have geared everything to a one plant indefinitely at this point. And, you know, we are working on having gas supply to be able to run that plant efficiently over the near to medium term right now.

Okay. Thank you.

Hi. Good morning. Just want to get an update on what you have done on the OCI deal, things left to be done. We know that and also have your team had a chance to go inspect that gasoline. There was a fire there. The plant was down for about a month. And how does that incident affect your view of the deal and going forward?

Thanks, Joel. On OCI, there are really two things happening right now. For us, it is going through the regulatory approval process. As we said when we announced the deal, we would be filing in both the US and Europe, and those things are progressing as planned. We expect that it will close sometime in the first half of 2025. As it relates to nat gasoline, you know, we do not own the assets today. So, certainly, that is something that we are also aware of, but it is not something where we are actively managing in any way that plant. That is a competitor plant today, and so we are going to be listening closely on the updates on that and trying to understand the impact of their outage and what is behind that. But as of today, no, there has been no active involvement at all in the nat gasoline situation.

Okay. And then just following up on you doing, can you remind us if you go to the one plant operation, just remind us what we should expect to get full run rates one plant in New Zealand, what it would look like in 2025 per volume.

Yeah. So it is around about 800 to 850 thousand ton capacity for a one plant operation. So we are, you know, that is what we are geared towards at full rates. That is what you would have, and we will give guidance on the run rate for the one plant operation in January when we come out with our new guidance for 2025.

Richard, there are some dissynergies from only running one plant, like some fixed cost absorption. No? Okay. Thanks.

No. We, Joel, we took the difficult decision here to revise or optimize our operating structure, which included the size of the employee base there. So we have seventy people that were restructured during the quarter, so we took that difficult decision, and you know, those are talented and dedicated people that we lost during the quarter. We have also optimized the capital programs down to one plant, and so when we look at the impact of the cost base operating cost base as well as the capital flows, you know, from an earnings and cash flow perspective, it is not a huge impact because we were already so low running a two plant operation with gas to only support about one million to 1.1 million tons.

Thank you.

Good morning, guys. Thanks for the time. Just curious, Rich, about some of the gas procurement activity you have undertaken here recently. Has there been a shift in the market dynamics there that made you want to go after additional gas? Is it just something that has come to fruition this quarter after a long period of effort? Maybe just give us some backdrop in terms of why now and anything around the cost structure would be helpful. Thanks.

Thanks, Steve. Right now, we are hedged on our full gas position in Geismar with G3 at 70% in a kind of one to three-year period. Current spot pricing is at the $2.75 level, so we are benefiting from that on our spot gas purchases on 30% of our purchases in Geismar right now. The forward curve, like you said, has come down. One of the things that we do have to evaluate is the OCI transaction. That is going to come to us without any fixed hedges or gas procurement associated with it on day one of the transaction. So we are looking at that as we move closer to the close date there. But on our current base, we like where we are at on the 70% level hedged, and then we are participating in that spot market on the 30%. It does bode well for us. Maybe looking at lengthening out our positioning in Geismar beyond the three years that we have, and we will look to see if we layer in more hedges in that kind of plus three-year time frame as well. But we have not done anything yet, but it has obviously come down recently and is getting more attractive, which is good for us.

In Latin America, Rich, in the Southern hemisphere, it sounds like you got some additional gas out of Chile and Argentina.

Yep. We locked in our gas to run at full rates for the non-winter months. It is about a seven-month period here, so we are really happy with that. There is a lot of gas being made available in those non-winter months, and we did sign we extended our deal with ENAP until 2030. That underpins around 30 to 35% of the total site needs for that five-year period at the same pricing terms. We also signed a deal with YPF until 2027, which is about 20 to 25% of our total site needs as well, and that is on a year-round basis as well. That will still be subject to the imbalances that Argentina experiences in the winter months, and so we are going to work with them on getting full gas all year round under that contract. But that is something that is a really good indication of what is happening in Argentina as they continue to debottleneck the Vaca Muerta field, and the domestic supply balances continue to improve in that country.

Okay. That is helpful. And just one follow-up on your G3 references. I mean, it sounds like the facility is running well now. It sounds like you have got plans to run it here at effectively full rates for the balance of the quarter. But is there anything else we should think about in terms of the ramp period here? Are we effectively through it now, and we can think about it as a regular course run? Or is there other downtime that still is planned in the short term we should be thinking about in our model? Thanks.

Yeah. No. Thanks, Steve. We are really happy with G3 and where we are at with where the plant is running. You should think of this as now in our manufacturing and production base fully, and we are really happy with the way it is running for what we think will be really high efficiency rates for the long term here. So, yeah, there were a couple of shutdowns that we took during the period, but those were done mainly around an abundance of caution for safety and reliability to ensure we get to this place. When I say that, we have completed our performance and reliability test, so there are two tests. One is a 72-hour performance test where you have to run at 100% rates for 72 hours. The other one is a 30-day reliability test where you need to run at a sustained plus 90% rate, and we have passed both of those now, and we feel really good at where the plant is operating at. It is at 154,000 tons over 30 days, which is above the nameplate. It is running really, really well and efficiently, and we are happy with the great job the team has done, really safely and reliably bringing us to where we are. So you should think of it as it is in the production base, and we are managing it within our portfolio now as we put all of our plants.

Great. Appreciate it, Rich. Thanks, guys.

Morning, Rich. A question around pricing. Obviously, you guys have seen nice upticks in pricing both in the US and Europe. Not surprisingly, with the sort of Asia macro the way it is, we have not seen that mobility in pricing in Asia. So my question is how sustainable are these disconnects in geographical or regional pricing? It seems that the disconnect between Western and Asian methanol pricing seems to get wider and wider.

Yeah. Well, thanks, Hassan. Right now, we are seeing that disconnect, and it is growing quite a bit. I will explain what has happened in the Atlantic basin that has widened that during the quarter. But right now, to really balance it between basins, you would probably look first to Middle East flows. We do not see a lot of Middle East product moving to Europe. It is further restrained because there is not a lot of product that wants to move through the Red Sea right now. There may be traders willing to move that product, but there is not a lot of Middle East product that is not contracted that can move and be able to carve that gap. Traders will look to others to access molecules via other spot markets. China will be looked at as, can I buy it in China and reload it to Europe? That is a really big shipping cost, and there is a lot of risk in terms of the time lag and the price risk you take to try to move that. Things have been also quite tight in China. When inventory is built during the quarter, but now MTO is operating at 90% operating rates, and that has a huge impact on demand. It went from 60% operating rate up to 90% operating rate. That is five million tons of demand built in a three-month period. We think things are going to get tighter in China because of that, and we are heading into the winter months. What has happened in the Atlantic basin is that we have had stable demand, but continued pressure on supply. It is not just the unplanned outages in the market. There are things happening there that are temporary, but there are also things that look more structural. We have seen Equinor out of the market since April. We are not sure when that Norwegian plant comes back in. There is about 800,000 tons to a million tons in Europe refinery-based methanol, and a lot of that was shut during the quarter. We are not sure if that is temporary or structural, less product out of Equatorial Guinea, less gas in Trinidad this year than there has been in the past. So we have seen a tightness in the Atlantic markets that is part temporary, part structural. Demand continues to stay balanced and stable there. Now there is more pull in the Pacific Basin. Things look tight, and it does not feel like there is going to be a lot of flows from the Pacific solving that issue, and it really needs to be more production out of the Atlantic basin to bring that back.

Very detailed and helpful. Thank you so much, Richard. As a follow-up, since we are discussing the different regions, obviously, the last couple of months have seen extreme heightened geopolitical tensions, particularly in Iran, even skirmishes out there. If anyone is a guessing person, one would like to think that with the new regime in place in the US, even further heightened sanctions and the like. How have production and export levels been over the last couple of months out of Iran? Where do you see those things going now that we have some sort of political certainty, I guess, here in the US?

So far, we have not seen a big impact on Iranian methanol supply or production. We watch it. We just do not know exactly what is happening in the country, but we do watch flows out of Iran, and we have not seen an impact. We are watching very closely as the war continues to escalate, but thus far, Iran has been producing. They are heading into their winter months right now, so we do expect that there are going to be restrictions on gas use, and last year, we saw a more extended period of gas restrictions. We are going to watch that closely. Thus far, we have not seen the escalation really impacting production there, but it is something we are going to continue to watch. Geopolitically, with the new administration, we will be watching closely on foreign policy. We do not foresee in this environment likely a lifting of sanctions. It is not going to be easy to get to any place like that. We do continue to think Iran will be restricted on sanctions, and it will be harder for them to increase capacity, and they will be restricted on their trade flows like they are today, mainly going into China with some into India.

Very helpful, Rich. Thank you so much.

Thanks, and good morning. Circling back to the question and the positive developments in Chile from the new gas supply contracts. If you can run that at 55% in the winter months down there, does that mean that the full-year production could be above 1.3 million tons in 2025?

We will update the guidance in January. But if you do the math on it, the range is kind of in that 1.3 to 1.4 million tons, depending on if you get that extra increment of gas during the winter. So, yeah, it is about 100 to 150 thousand tons of incremental supply that we get with that uplift.

Sounds good. Rich, could you talk about how you are thinking about capital returns to shareholders here? It seems that for the next couple of years, as you pay down debt from the OCI deal, the share buybacks are probably going to be pretty limited. Is there any thought to pushing up the dividend a little bit more while we wait for the buyback to resume?

The big thing that we are focused on is the pre-OCI deal leverage. Prior to the deal, we will get to the end of this year after we pay our $300 million, and we will be just below three times debt to adjusted EBITDA. If the deal were to be done on January 1, and we were to take all the debt in, it would be about $550 to $600 million that we would need to take off the balance sheet, and that is going to be a big focus for capital allocation as we move into this period. We do not expect things to close on January 1, and so we will be in a really good position with today's methanol price to continue to generate cash with pricing today and production where we are with the assets we have running, which is a really good spot. We are going to continue to build cash, and that will be the primary focus until we move past that level. We will be in a really good position to look at capital allocation thereafter, maintaining a strong balance sheet, and shareholder distributions will be things we will be looking at, obviously, depending on where we are in the market. But the laser focus for us right now is the $550 million to $600 million for cash out capital allocation.

Great. Thank you.

Hello. Thanks very much. Good morning. So you realized price increased 70% in Q3 year over year, and the posted price moved up 31%. Can you talk more about what was driving the difference? I mean, was it that you are having to send more Atlantic Basin methanol to the Pacific Basin, which, as you mentioned on the call, is a lower price? Is that part of it, or is there something else going on?

I think it is probably because we have a widening in our discount range. If you are looking at reference prices to average realized prices, our reference prices would be going up higher than the average realized price. That is a function of what is happening in the Atlantic markets. We have seen increased competition by marketers mainly through discount competition, and we have seen discounts from reference to realized increasing. That is probably the main reason. What we do look at is we tend to look at what is our realized price versus the marginal cost of production or the cost curve price in the industry. What we would see this year is that our realized price has the difference between our realized price and the cost curve price is growing because of that tightening in the Atlantic market as well. So I think you have had a bit of a double impact there where we have seen not only the Atlantic basin driving more of the price, but also that is the region that carries the higher reference. So that has led to higher discount levels. Yeah. We are not active, nor can we be, in decision-making for that asset prior to close. That is something that we would expect they are doing and progressing and ensuring that they get those refinancing in place the same way you would if you were owning those assets for the long term. So, yeah, we are not involved, but we will be watching closely in terms of ensuring that that happens. Alright. Well, thank you for your questions and interest in the company. I hope you will join us in January when we update you on our fourth quarter results.

Ladies and gentlemen, that concludes today's call. Thank you all for joining. You may now disconnect.