Methanex Corporation (NASDAQ:MEOH) Q3 2023 Earnings Call Transcript

Methanex Corporation (NASDAQ:MEOH) Q3 2023 Earnings Call Transcript October 26, 2023

Operator: Good morning. My name is Julie Ann and I’ll be your conference operator today. At this time, I would like to welcome everyone to the Methanex Corporation 2023 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. [Operator Instructions] 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.

Sarah Herriott: Thank you. Good morning, everyone. Welcome to our third quarter 2023 results conference call. Our 2023 third quarter news release, Management’s Discussion and Analysis, and Financial Statements can be accessed from the Reports tab of the Investor Relations page on our website at methanex.com. I would like to remind our listeners that our comments and answers to your questions today may contain forward-looking information. This information, by its nature, is subject to risks and uncertainties that may cause the stated outcome to differ materially from the actual outcome. Certain material, factors, or assumptions were applied in drawing the conclusions, or making the forecast, or projections which are included in the forward-looking information.

Please refer to our third quarter 2023 MD&A and our 2022 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, 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 our share-based compensation and the impact of certain items associated with specific identified events.

These items are non-GAAP measures and ratios that do not have any standardized meaning prescribed by GAAP and therefore, unlikely to be comparable to similar measures presented by other companies. We report these non-GAAP measures in this way, because we believe that 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.

Rich Sumner: Thank you, Sarah, and good morning, everyone. We appreciate you joining us today, as we discuss our third quarter 2023 results. For the third quarter, our average realized price of $303 per tonne and produced sales of approximately 1.5 million tonnes, generated adjusted EBITDA of $105 million and adjusted net income of $0.02 per share. Adjusted EBITDA was lower, compared to the second quarter due to a lower average realized price and lower produced sales. Through the third quarter, we saw improving market conditions with stronger demand from certain sectors, as well as moderation in global operating rates, mainly from various supply outages in North America, Middle East, and Southeast Asia. Methanol demand improvements were primarily driven by stronger demand in China, with increased demand for MTBE and other fuel applications, as well as improved demand for methanol-to-olefins, with a number of MTO plants restarting operations in the third quarter.

An industrial facility with chimneys billowing smoke indicating specialty chemical production.

We are currently seeing very high operating rates across the MTO sector, which we believe is driven by the completion of planned downstream expansions, as well as some improvements in affordability from a higher energy and olefins pricing during the quarter. However, we believe economic pressure remains on this sector under current market conditions. We can continue to carefully monitor the global macroeconomic environment, and during the third quarter, we saw relatively flat demand outside of China for methanol into traditional chemical applications compared with the second quarter. Coal pricing in China increased during the third quarter from around RMB80O per tonne to above RMB1,000 per tonne currently, which we believe was primarily driven by various industry supply disruptions.

We currently estimate the global cost curve to be over $300 per tonne based on current coal pricing in China. Overall, continued high energy pricing and improved supply-demand fundamentals has led to slightly higher pricing throughout the third quarter and into the fourth quarter. Our November posted prices in North America, Asia-Pacific, and China were posted at $549, $370, and $360 per metric tonne respectively. And our fourth quarter European price was posted at €375 per metric tonne. Based on our October and November posted prices, we estimate our global average realized price to be approximately $310 to $320 per metric tonne for these two months. In the third quarter, we had lower production due to scheduled turnarounds in New Zealand and Chile, and seasonal gas restrictions in Chile.

We are encouraged by the pace of gas development in Argentina and the continued supply rates from ENAP in Chile. Increasing gas supply from Argentina allowed us to restart our second Chilean plant in September, earlier than previous years. We expect both plants to run at full rates from the end of September through April 2024, the Southern Hemisphere summer months, and are increasing our Chile production guidance for 2023 from a range of 800,000 tonnes to 900,000 tonnes to a range of 900,000 tonnes to 1 million tonnes based on improved gas availability from Argentina. Earlier in October, we also announced that we signed a two-year natural gas agreement with the National Gas Company of Trinidad and Tobago, to restart our fully owned Titan plant and simultaneously idle the Atlas plant in September 2024.

I want to thank our team for their hard work; to ensure that we maintained operations in Trinidad, which is a strategic part of our global portfolio. The gas situation in Trinidad in the near-term is challenging, which is reflected in the short-term of the new gas contract. We remain committed to working with the NGC and the government to secure long-term economic gas supply. We entered the third quarter in a strong financial position with approximately $500 million of cash and $300 million of undrawn backup liquidity. Our capital priorities are to complete the Geismar 3 project, and allocate any excess cash to repay rather than refinance the $300 million bond due at the end of 2024. Construction of our G3 project is progressing safely to plan.

Construction is nearly complete and the team is in the final handover, testing and commissioning phases. We expect to achieve commercial production around the end of the year and within our budget range of $1.25 billion to $1.3 billion. The remaining $140 million to $190 million of cash expenditures, including approximately $50 million in accounts payable, is fully funded with cash on hand. Looking ahead to the fourth quarter of 2023, we are expecting higher adjusted EBITDA with a higher realized methanol price and higher produced sales. We remain focused on delivering strong operational results from our existing assets and completing the G3 project. We are well positioned during this period of economic uncertainty with growing cash flow generation capability from G3, and a portfolio of assets that can generate cash flow across a wide range of methanol prices.

We would now be happy to answer questions.

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Q&A Session

Operator: Thank you. [Operator Instructions] Our next — our first question comes from Ben Isaacson from Scotiabank. Please go ahead, your line is open.

Ben Isaacson: Thank you, very much, and good morning, everyone. Rich, a question on Trinidad. You said that the gas situation has been challenging, which was the reason for the short-term deal. Does that mean that you don’t have confidence that it’ll get better? Is that why — I mean, if it’s challenging, presumably it’s challenging in the short-term. And as part of that same question, what was the rationale to idle a plant that was running and then bring on CapEx to restart Titan? Is that because there was going to be a major turnaround for Atlas that you wanted to avoid? Just trying to understand the whole Trinidad story. And then, just maybe as my follow-up. Can you talk about any risk at E-Methanex due to the shutdown of the Tamara platform off of Israel? Thank you.

Rich Sumner: Okay. Thanks, Ben. On Trinidad, I’ll talk about the kind of the near-term and the reason we call it challenging is, I think, we talked about previously that the gas market is tight in Trinidad. And then in the near-term what we see today, there’s about — when you look across L&G, ammonia and methanol, that’s about 4.5 Bcf of demand per day. Current production is in the range of 2.5 to 3 Bcf. And the government — no, we haven’t given up on the one. On the fact that, that situation is going to get better, because there’s a lot of things happening in Trinidad. And we believe there’s a lot of incentives today to restart capacity that is there across the estate and these are long assets that have run really reliably over time in Trinidad.

So certainly, not — we are working to understand all of the initiatives that are being taken. And we remain really committed to working with NGC as they – and the government of Trinidad, as they work with the upstream on improving that situation. The reason we started up — the decision around Titan versus Atlas is because of the near-term situation. They were offering a fairly short-term contract. And when you look at the economics under that contract in the short-term, it made sense to run Titan. And as you said, we don’t have a turnaround in front of us like we do in Atlas. That plant had gone through major maintenance just before we’d idled it. I think that was back in 2019. So, it made sense from an economic perspective and also, I would call it an organization perspective.

We want to keep our team in place. Our global manufacturing team is part of our — huge part of our organization. And we’re really pleased that we’ve got — we’ll have the Titan asset running at the end of next year, and we will shift and create a Titan restart team now that will be focused on getting that plant up, and running safely and reliably. You asked about Egypt?

Ben Isaacson: Yes.

Rich Sumner: I’ll answer that. I think, as of right now, what we’ve seen is there has been a shutdown of the — so, Israel is an exporter of gas to both Jordan and Egypt. Israel has shut in the Tamara field, which has impacted the flow of gas into Egypt. That is not affecting the available of gas to the industrial producers there. We do understand there may be impact to L&G producers. So, as of right now, that’s not impacting our operations or other industrial producers in Egypt.

Ben Isaacson: Appreciated, Rich. Thanks so much.

Rich Sumner:

Operator: Our next question comes from Joel Jackson from BMO Capital Markets. Please go ahead, your line is open.

Joel Jackson: Well, good morning. A couple of questions, short-term and then I’ll do a long-term. I’ll do short-term first. Just looking at some of your guidance for Q4, can you say, if you expect Q4 EBITDA to be higher? You said, everything will be higher. Will it be higher than Q4 of ’22. And when you gave your price guidance of $310 to $320, it looks like you’re using a higher discount rate than Q3. And then would you be having some inventory bills in Q4, like you normally do?

Rich Sumner: Okay. So, the Q4, I haven’t done that comparison. Our reference was in comparison to Q3, Joel, for higher pricing and higher produced sales. As it relates to the discount rate, we don’t expect a big difference in the discount rate. So maybe, we can take that one offline. And then inventory bill, yes, we do — we have seen a number of quarters here with inventory bills on our produced sales. So, we probably — accounting’s accounting, but we would expect that at some point, we’ll also be seeing a benefit of pulling through produced sales as well. So hopefully, that answers a bit of context to the quarter for you.

Joel Jackson: Okay. And then my longer-term question —

Rich Sumner: Does that help?

Joel Jackson: Yes. That’s why I asked ’24. That’s a clearly longer-term now.

Rich Sumner: Yes, yes.

Joel Jackson: If you look at the production for ’24, can you give about like off a base of little more than 6.5? Can we talk about what you expect for 2024? So, I would imagine you expect G3 could ramp across Q1. You have almost near production there next year. I would imagine you switch over from Atlas to Titan, but there might be a hiccup there. Would you lose some tonnes — would you be running both plants overlapping for a month, or would you lose some tonnes on a ramp-down and a ramp-up? Any other changes in New Zealand or anywhere else with better gas in Chile? Like, should we expect 2 million tonnes more in production next year, 1.5 million tonnes? Can you just give us some ideas?

Rich Sumner: Yes. We will update our guidance formally towards the end of this year, but I’ll — maybe, I’ll give you some kind of preliminary thoughts there. We are — we will, for Chile, like I said, we’ll be operating two plants at full rates at least until April of next year. So already, we’ve got those gas contracts in place today, and we’ll be working on the similar contracts for next year. This is the first time in a very long time that we’ve operated two plants at full rates. So, we’re really excited about that. And we’ll be working on replicating that out in the — for the summer month period for next year. So, I would expect, when we were at 800 to 900 this year that number will be higher for Chile. For Trinidad, we will — we are going to be working — the gas contracts are working simultaneously.

So, we will be trying to — I don’t expect a lot of overlap there, but we will try — it will be kind of an idling and then a start-up of Titan. So, you can do the numbers on how that change happens. And then I think the big one will be also G3. Intention here is obviously to start up around the end of the year, but it will take time before our G3 actually works through our inventory flow. So, you probably got a 45-day to 70-day inventory bill before G3 starts kind of coming through the earnings. Egypt, we would expect similar results — we’ve been operating at high rates and New Zealand, we’ll update our guidance today. It’s at 1.3 million tonnes to 1.4 million tonnes, and we’ll be — that’s probably a similar level we would be at. But we’ll update it more formally, and we also have to factor and schedule turnarounds as well.

So, more to come there.

Joel Jackson: Thank you.

Operator: Our next question comes from Steve Hansen from Raymond James. Please go ahead, your line is open.

Steve Hansen: Yes. Thanks, guys. Rich, can you go back to the Chilean gas situation just in a little bit more detail? It sounds like on the back of some recent success, there’s an opportunity to secure some more gas going forward. Just trying to understand what that means for the pressure in profile next year, I guess, through the summer months in particular down there? And now we should think about maybe even the medium, longer-term profile for the pressure in the complex?

Rich Sumner: Yes. Thanks, Steve. So, a bit of a background on what’s happening in Chile. A lot of this is what’s happening in Argentina. Argentina is developing the Vaca Muerta field in the Neuquen Basin, and this is quite a prolific field. What they’re trying to do is, they’re investing in pipeline infrastructure. So, gas development is – a lot of success around gas development. And what they have done is, they are working on connecting that field into the major grid in Argentina. Argentina consumes about 120 million cubic meters a day in gas. What they did is they commissioned a pipeline that is now delivering, in the third quarter, that’s now delivering 10 million cubic meters into the grid. They’re working on adding compression to that pipeline, which would add another 10 million cubic meters per day into the grid as well.

So — and that will happen sometime in the first half of 2024. And then what they are also working on is another pipeline connection, which would double that capacity that would come on in the 2025 timeframe. In addition to that, there’s a development that’s happening in the Austral Basin by Total and Wintershall in a consortium there called the El Phoenix project, and that’s located really close to our plants. So, all of these developments are significantly improving the domestic gas balances in Argentina. And as well, that supports export markets, which we are very well positioned there with our assets. So, we’re really pleased to say that we’re going to be operating two plants at full rates during this sort of eight-month period. And like I said, it’s the first time in a very long time, we’ve been doing that.

And we’re going to work on longer-term gas. We think that focusing on the non-winter months is the right thing now and over time, we’ll also be hoping to improve our gas position during the winter months. But these are things we’ll continue to update on as we progress through.

Steve Hansen: Very good. Thank you. And just one follow-up on the G3 in terms of the commissioning and the inventory bill that you described. I know it’s early, but can you give us a sense for whether the 45 to 60, or 70 when do you describe will all take place in Q1 from your standpoint today, or will that start to build through the later part of Q4?

Rich Sumner: Yes. I think right now, the way to do it is starting in Q1. That would be probably the right way to think of it, around — starting in around the beginning of the first quarter.

Steve Hansen: Okay. Very helpful. Thank you.

Operator: Our next question comes from Hassan Ahmed from Alembic Global. Please go ahead, your line is open.

Hassan Ahmed: Good morning, Rich.

Rich Sumner: Good morning.

Hassan Ahmed: You guys saw a nice uptake across all your regions, obviously Europe — pricing-wise, Europe’s obviously for the quarter, no reflection there as yet. I’m just trying to understand the delta between sort of North American pricing and China/Asian pricing. I mean, even if I were to discount North American pricing, there is still, call it, as much as $70, $80 tonne delta between those pricing levels in the regions. So, just trying to get a better sense of why that exists? I mean it seems to me above and beyond shipping.

Rich Sumner: Yes, Hassan. Thanks for the question. I think, hopefully, I’ll answer your question the right way here for you to make sense of it. I think, if you were to look at discount levels across the regions rather than our global discount, because you can’t really apply the average discount to all the prices. It’s really that each region does have its own kind of market discount levels, which do vary quite widely depending on which region you’re looking at. So, our ARPs, if you were to look at our ARPs by region, that would probably make more sense and probably more reflective of kind of reasonable pricing differentials between those. So, it’s hard to look at the global discount and apply that, and try to make sense of those prices relative to say, spots or other markers.

Hassan Ahmed: Understood. And just coming back to sort of broader question. I know it’s all recent occurrences and the like in the Middle East. But I mean, are you guys seeing any meaningful shifts as a result of that in trade flows? I mean, I guess more specifically, what are you guys hearing in terms of Iranian product?

Rich Sumner: Yes. So, as of right now, we’re not hearing any disruptions as of today. We are monitoring the situation very closely, and really hoping for a peaceful and sustainable resolution here for everyone, but we haven’t seen any disruption. Israel doesn’t have any meaningful really methanol demand, nor is there any supply. And in the area, there, there’s no methanol trade routes that are impacted. Now, if this were to escalate in the region, a lot of things could be impacted, including methanol. So — but we haven’t seen any of those disruptions yet, but that could impact crude, it could impact L&G trade flows, methanol trade flows. And so those could have really meaningful impacts on the industry and — but we haven’t seen any of that yet. But we’re closely monitoring to see obviously what’s going to — how this is going to unfold.

Hassan Ahmed: Very helpful, Rich. Thanks so much.

Operator: Our next question comes from Matthew Blair from Tudor, Pickering, Holt. Please go ahead, your line is open.

Matthew Blair: Hey. Good afternoon or good morning, sorry. Could you talk about any opportunities you’re looking at for your underutilized assets? Is there a chance that you could take apart Atlas, move it to the U.S., like you did with some of your Chile plants a long time ago? Or is there an opportunity for converting those assets into an E-methanol plant?

Rich Sumner: Yes. So, we — in terms of relocation in Trinidad, at this point, we remain committed to Trinidad. And we are — we think there’s a lot of incentives today to get assets, underutilized assets operating in place, where they are today, and that assets operated really well for us in Trinidad. So, we are focused there. Now, we do have experience relocating plants. We moved Chile 2 and 3 to Geismar. Our experience on plant relocation is that the capital cost savings are really not that meaningful. It’s really about speed. The construction timeframe can probably be — we could probably save a year on in terms of the construction timeframes versus building news. So, it has advantages there. We’re not considering that today for Atlas, as we want to work on getting longer-term sustainable gas in Trinidad.

But that is something that we’ve done before, we have a lot of experience with, and there is that speed advantage in the event that you wanted to move quickly on a project.

Matthew Blair: Sounds good. And then could you talk a little bit about the moving parts on cash flows in 2024. Should we think of your CapEx moving down to the, I don’t know, $150 million to $200 million range? I think you mentioned the debt pay down of about $300 million next year. There’s also the dividend of $50 million plus potentially a working capital build as you ramp up G3. Would the remainder, any remaining cash flow go to buybacks in that scenario?

Rich Sumner: So, I think the right number to use on the CapEx is the lower of your range, they’re around $150 million. And I think, you’ve got all the numbers in terms of the other cash outlays. So yes, we’re focused on the $300 million bond. And I think as of today, today’s pricing more probably, that’s the main focus. We generate a little over $200 million in free cash flow with G3 at $300 methanol price. Above that then, you’re probably getting above the bond, if you get closer to $350 million. We still see the market environment today is supportive of what we need to repay the bond, but we’re really focused on that. If we were to have a really stronger methanol market, then you start looking at free cash flow beyond the debt repayment.

We don’t have any major capital ahead of us. And so we would be looking at returning excess cash and likely some balanced approach between looking at the balance sheet further on deleverage. But we’re really focused on the $300 million bond today.

Matthew Blair: Great. Thank you.

Operator: Our next question comes from Josh Spector from UBS. Please go ahead, your line is open.

Josh Spector: Yes. Hi. Thanks for taking my question. I guess, first, I just wanted to ask a follow-up on the cash flow side. So, when you think about the working capital build next year with the G3 startup, I mean, you’re already purchasing and reselling some tonnes. So, is there a way to size kind of the net impact that you would expect that to be in terms of cash use to build that inventory?

Rich Sumner: Yes. I — we’re not really concerned with the working capital build up here. I don’t think that there’s any strategies we’re having in terms of managing that down. We’re — you will see, we are buying a lot of product today, which we will significantly reduce with G3 coming online, because we’re not going to be growing our sales by 1.8 million tonnes next year. We’ve already grown our sales. So, you’ll see a lot of purchased product being displaced by produced product, which would be supportive of lower inventory values anyways.

Josh Spector: Yes. So, I appreciate that. I guess, that’s where I was kind of going. So, it do kind of net offset each other, so it’s not really a major cash use. Is that kind of what you’re saying or should we be thinking about it as somewhat of a cash use?

Rich Sumner: Yes.

Josh Spector: Okay. And then the other question I have is, just more on cost curve and just methanol price support. If I heard your comment correctly, you talked about $300 a tonne methanol price support. Your posted pricing in China is higher. I guess, what do you view as the pricing driver here? Is it the fuel value? is it coal? And then how does that evolve into next year in your view?

Rich Sumner: Our posted price is higher, but after discount, we’re probably in a — we’re kind of closer to those levels. What’s driving the price today is really, it’s going to be the marginal producer cost, which is a co-producer cost in China. And then the other factor that we look very closely at is the affordability of methanol into – primarily into the olefins industry. And I think right now, we would say that both of those factors are kind of pointing to the levels, where we are today in China, at around $200 spot pricings and around $280 to $300. We have seen some improvement in the olefins market. And I would say that, that sector relative to oil pricing today is pricing well under where it would be on a kind of mid-cycle basis.

So, we’ve seen tonnes of pressure on that sector that we would in a normal, in a kind of mid-cycle energy pricing at $90 oil, we would expect much, much higher pricing. And especially, when MTO is operating at the highest rates, I think we’ve ever seen today. As an example, that sector is operating at 90% operating rates over a very high base, because we’ve added MTO plants last year. So, if we had a better market there, I would expect that would be driving methanol prices higher than where we are today.

Josh Spector: Okay. Thank you very much.

Operator: [Operator Instructions] Our next question comes from Laurence Alexander from Jefferies. Please go ahead, your line is open.

Kevin Estok: Hi. Good morning. This is actually Kevin Estok on for Laurence Alexander. So, it looks like most of my questions have been asked, but I guess, I was wondering if you could give me any updates since the last calls around your strategy on green and blue methanol? And I guess, maybe how current interest rates might impact future investments? I guess, you’re going to get a sense of your rate sensitivity too, as it relates to your strategy. Thank you.

Rich Sumner: Yes. Thanks. Maybe, when you think about the low-carbon space, the strategy is really looking at both sides, both the demand and the supply side. I didn’t mention it in the opening comments, but there continues to be a lot of momentum in marine fuels. Right now, over 200 ships plan to be in the water in the ‘27-‘28 timeframe. That represents around 7 million tonnes of demand if those ships were to run on a methanol 100% of the time. So, we are working with major international shipping companies. This is a container shipping segments leading the way, but there’s interest in dry bulk, tankers and cruise ships. So, we’re working with that issue. We’ve got a number of MOUs signed, working closely with the shipping industry on their desire for green, blue, conventional methanol.

Say green, it looks like; for green methanol, it’s mainly being driven by the European market in shipping, and that a lot is on the back of what’s happening on the emissions trading scheme, as well as EU Maritime regulations around carbon emissions. We’re having a lot of other discussions around blue and conventional methanol as well. So — and then on the supply side, we’re working on a number of projects. I would say, first and foremost, we’ve been certified to be able to purchase our renewable natural gas in North America and produce green methanol, and our Geismar plants. And our marketing regions are certified to be able to sell that product through the customers — certified products through the customers. And then we’re looking at the feasibility of projects at our sites and would be using renewable hydrogen and CO2 to sort of green the assets.

We’re looking at multiple feasibility within our existing sites. We’re also in discussions with other projects that are out there that would like to work with us on off takes. And so we’re trying to understand how we can open up as many economically-efficient supply alternatives for the marine industry around green methanol. There’s a lot of discussions happening, and we’ll hope to be able to report more as we progress in this area.

Kevin Estok: Great. Thank you very much.

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

Rich Sumner: All right. Well, thank you for your questions and interest in our company. We hope you will join us in February, when we update you on our fourth quarter results.

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