Methanex Corp

TSX:MX

Earnings Call Analysis

Earnings Call Transcript 2024-Q3

[Operator]

Good 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. [Operator Instructions] I would now like to turn the conference call over to the Director of Investor Relations at Methanex, Ms. Sarah Harriott. Please go ahead, Ms. Harriott.

[Sarah Herriott]

Good morning, everyone. Welcome to our third quarter 2024 results conference call. Our 2024 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'd 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 2024 MD&A and to our 2023 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 the 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 reflects 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 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 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, executive]

Thank you, Sarah, and good morning, everyone. We appreciate you joining us today as we discuss our third quarter 2024 results. Our third quarter average realized price of $356 per tonne and 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 compared to the second quarter of 2024, primarily due to the gas sales in New Zealand, the recognition of the insurance recovery in Egypt and a higher average realized price.

I'm very pleased that G3 successfully completed its commercial and technical performance tests and has produced approximately 154,000 tons over the past 30 days, which equates to a 1.8 million tonnes per annum production rate.

After producing first methanol in late July, we conducted 2 separate shutdown events during the third quarter to adjust and calibrate equipment, which I can discuss in more detail during the question-and-answer period. I'm 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 of $356 per metric ton was $4 higher than the previous quarter.

Global methanol demand was stable in the third quarter compared to the second quarter with relatively flat demand in 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 through 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 increasing MTO rates. Methanol prices in China remained fairly stable between $280 and $300 per tonne.

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 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. And therefore, we've made the difficult decision to indefinitely idle 1 of the 2 Motunui plants.

We've optimized the operating and capital costs and expect these actions will substantially offset the adjusted EBITDA and free cash flow impact from idling one plant.

We remain committed to working with the government and gas suppliers to support upstream gas development 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 a one plant operation.

In Chile, I'm very happy to share that we've successfully agreed to extend 2 gas contracts that underpin 55% of the gas -- 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 2 plants at full rates for the non-winter months from 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.

This led to various measures 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 industrial plants are expected going forward, particularly during the summer months. The plant is 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 1 million tonnes of methanol from the global market and reduces our equity production by approximately 200,000 tonnes. We continue to work closely with the national gas company at 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're on track to repay the $300 million bond due on December 1, 2024, after which our debt to adjusted EBITDA leverage ratio will be just under 3x at a $350 per tonne realized price.

We recently announced we've secured $650 million in Term Loan A commitments to fund the 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 18 months, assuming a $350 realized methanol price.

Beyond this, we don't see meaningful capital over the next few years and remain committed to maintaining a strong balance sheet with a 2.5x debt to adjusted EBITDA target. With a strong free cash flow profile from our existing assets, which will be enhanced with the OCI 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 EUR 570 per tonne, a EUR 35 per tonne increase from the third quarter. Our November North American posted price was posted at $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 tonne, 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 tonnes, which will be sold through in the fourth quarter of 2024 and the first quarter of 2025 as produced sales normalize to increase 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 onetime Egypt insurance recovery in the third quarter. We would now be happy to answer questions.

[Operator]

[Operator Instructions] Your first question comes from Josh Spector with UBS.

[James Cannon, analyst]

This is James Cannon on for Josh. I just wanted to dig in on the New Zealand guide. I think the 600 kt that you called out in the print reflects 4Q production less than half on that unit. Is that 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?

[Rich Sumner, executive]

We're expecting that as of the end of October here, we're running one plant at full rates. That's something that we're obviously assessing as we go forward. But yes, we've really geared the plant to a plant operation. Of course, we will be looking at our gas profile as we go forward, but that's the level where we expect to be at.

[James Cannon, analyst]

Okay. And then just kind of as I think about what went on over the summer with -- just it doesn't seem like there's much improvement baked into the gas supply forecast for New Zealand. So do 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 sale and gas?

[Rich Sumner, executive]

Well, the shutdown in sale and gas was really due to the domestic -- what was happening on domestic energy balances through that period where there was a draw for gas for power generation.

So we onsold our gas during that period and really for wet producing methanol. Coming out of that, we had to assess where we were -- we were already operating -- we had initially guided to about a 1 million 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 future -- the forecast looks like enough gas to run a plant operation, and it didn't make sense to be gearing to a 2-plant operation with the operating structure and capital programs required to run a 2 plant on a sustainable basis.

So we've geared everything to a plant for indefinitely at this point. And we're working on having gas supply to be able to run that plant efficiently over the near to medium term right now.

[Operator]

Your next question comes from Joel Jackson with BMO Capital Markets.

[Joel Jackson, analyst]

Just want to get an update on what you've done on the OCI deal, things left to be done. We know that -- and also have your team -- has your team had a chance to go inspect nat 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 going forward?

[Rich Sumner, executive]

Thanks, Joel. On OCI, there's really 2 things happening right now for us is we're going through the regulatory approval process. As we said when we announced the deal that we would be filing in both the U.S. and Europe, and those things are progressing as planned.

And we expect that, that will close sometime in the first half of 2025. As it relates to nat gasoline, we don't own the assets today. So certainly, that's something that we're also aware of, but it's not something where we're actively managing in any way that plant. That's a competitor plant today.

And so we're going to be listening closely on the updates on that and trying to understand the impact of their outage and sort of what's behind that. But as of today, no, there's been no active involvement at all in the Natgasoline situation.

[Joel Jackson, analyst]

Okay. And then just following up on New Zealand, can you remind us if you go to the plant operation, just remind us what we should expect to get full run rates one plant in New Zealand, not new what it would look like in '25 for volume.

[Rich Sumner, executive]

800,000 to 850,000 tonne capacity for our plant operation. So we are -- that's what we're geared towards at full rates. That's what you would have, and we'll be -- we'll give guidance on the run rate for the plant operation in January when we come out with our new guidance for 2025.

[Joel Jackson, analyst]

Rich, are there some dis-synergies from like only running one plant like some fixed cost absorption?

[Rich Sumner, executive]

No, 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 had 70 people that were restructured during the quarter.

So we took that difficult decision. And those are talented and dedicated people that we lost during the quarter. And we've also optimized the capital programs down to one plant.

And so when we look at the impact of the operating cost base as well as the capital flows, you're -- from an earnings and cash flow perspective, it's not a huge impact because we were already so low running a 2-plant operation with gas to only support about 1 million to 1 million -- 1.1 million tonnes.

[Operator]

Your next question comes from Steve Hansen with Raymond James.

[Steven Hansen, analyst]

Just curious, Rich, about some of the gas procurement activity you've 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's come to fruition this quarter after a long period of effort? And maybe just give us some backdrop in terms of why now? And anything around the cost structure would be helpful.

[Rich Sumner, executive]

Yes. Thanks, Steve. Look, right now, we are hedged on our full gas position in Geismar with G3 at 70% in a kind of 1- to call it, 3-year period.

Current spot pricing is at the $2.75 level. So we're 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.

And 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 when -- on the day 1 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're at on the 70% level hedged, and then we're participating in that spot market on the 30%.

It does bode well for us, maybe looking at lengthening out our position in Geismar beyond the 3 years that we have, and we will look to see if we layer in more hedges in that kind of plus 3-year time frame as well. So -- but we haven't done anything yet, but it's obviously come down recently and getting more attractive, which is which is good for us. We locked in our gas to run at full rates for the non-winter months. It's about a 7-month period here.

So we're really happy with that. There's 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 5-year period at the same pricing terms. And we also signed a 20 -- sorry, 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're going to work with them on getting full gas all year round under that contract, but that's something that we're -- is a really good indication of what's happening in Argentina as they continue to debottleneck the Vaca Muerta field and the domestic supply balances continue to improve in that country.

[Steven Hansen, analyst]

Okay. That's 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've 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, I'll call it, the ramp period here? Like 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 that we should be thinking about in our model?

[Rich Sumner, executive]

Yes. Thanks, Steve. No, we're really happy with G3 and where we're at with where the plant is running. And you should think of this as now in our manufacturing and production base fully, and we're really happy with the way it's running for what we think will be really high efficiency rates for the long term here.

So yes, 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.

And when I say that we've completed our performance and reliability test, so there's kind of 2 tests. One is a 72-hour performance test where you run -- have to run at 100% rates for 72 hours.

The other one is a 90-day -- or sorry, a 30-day reliability test where you need to run at a sustained plus 90% rate. And we've -- we've passed both of those now, and we feel really good of where the plant is operating at. And it's that 154,000 tons over 30 days is above the nameplate.

It's running really, really well and efficiently, and we're 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's in the production base, and we're managing it within our portfolio now as we would all of our plants.

[Operator]

Your next question comes from Hassan Ahmed with Alembic Global.

[Hassan Ahmed, analyst]

A question around pricing. Obviously, you guys have seen nice upticks in pricing, both in the U.S. and Europe. And not surprisingly, with the sort of Asia macro the way it is, we haven't seen sort of that upward mobility in pricing in Asia. So my question is how sustainable are these disconnects in sort of geographical or regional pricing? I mean it seems that the disconnect between Western and Asian sort of methanol pricing seems to get wider and wider.

[Rich Sumner, executive]

Yes. Thanks, Hassan. Right now, we're seeing that disconnect and it's grown quite a bit. And I'll kind of explain what's happened in the Atlantic Basin that's widened that during the quarter. But right now, to really -- in terms of maybe balancing it between basins, you would probably look first to Middle East flows.

We don't see a lot of Middle East product moving to Europe. It's further restrained because there's 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 isn't a lot of Middle East product that's not contracted that can move and be able to arb that gap. Traders will look to others to access molecules via other spot markets. And so China will be looked at as, can I buy it in China and reload it to Europe.

That's a really big shipping cost, and there's a lot of risk in terms of the time lag and the price risk you take to try to move that. And 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. We went from 60% operating rate up to 90% operating rate.

That's 5 million tons of demand built in a 3-month period. So we think things are going to get tighter in China because of that and as we're heading into the winter months. What's happened in the Atlantic Basin is that it's we've had stable demand, but a continued pressure on supply. And it's not just the unplanned outages in the market.

There are things happening there that are temporary, but there's also things that look more structural. We've seen Equinor out of the market since April. We're not sure when the Norwegian plant comes back in.

There's about 800,000 tons to 1 million tons in Europe, refinery-based methanol and a lot of that was shut during the quarter. We're not sure if that's temporary or structural. -- less product out of Equatorial Guinea, less gas in Trinidad this year than there has been in the past.

So we've seen a tightness in the Atlantic markets that's part temporary, part structural. -- demand continues to stay balanced and stable there.

And then now there's more pull in the Pacific Basin. So things look good. They look tight, and it doesn't feel like there's 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 down.

[Hassan Ahmed, analyst]

Very detailed and helpful. And as a follow-up, I mean, since we are discussing the different regions, I mean, obviously, last couple of months, extreme heightened sort of geopolitical tensions, particularly in Iran, even skummishes out there.

I mean, if anyone is a guessing guy, one would like to think that with the new regime in place in the U.S., even further heightened sort of sanctions and the like.

So how has production and export levels been? How have they been over the last couple of months out of Iran? And where do you see those things going now that we have some sort of political certainty, I guess, here in the U.S.

[Rich Sumner, executive]

Yes. So far, we haven't seen a big impact on Iranian methanol supply production. We watch it. We don't know exactly what's happening in the country, but we do watch flows out of Iran, and we haven't seen an impact.

We are watching very closely as the war continues to escalate. And -- but thus far, Iran has been producing. They are heading into their winter months right now. So we think that they're going to -- we do expect that there's going to be restrictions on gas use.

And last year, we saw that a more extended period of gas restrictions. So we're going to watch that closely.

Thus far, we haven't seen the escalation really impacting production there, but it's something we're going to continue to watch. And then geopolitically, and the new administration will be watching really closely on foreign policy, and it doesn't -- we don't foresee in this environment likely a lifting of sanctions.

It's not going to be easy to get to any place like that. So we do continue to think Iran will be restricted on sanctions and will therefore be -- it will be harder for them to increase capacity and they'll be restricted on their trade flows like they are today, mainly going into China with some into India. So...

[Operator]

Your next question comes from Matthew Blair with TPH.

[Matthew Blair, analyst]

Circling back to the question and the positive developments in Chile from the new gas supply contracts. If you can run 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?

[Rich Sumner, executive]

We're going to -- we will update the guidance in January. But if you -- yes, if you do sort of the math on it, the range is kind of in that 1.3 million to 1.4 million depending on how -- if you get that extra increment of gas during the winter. So yes, no, it is about 100,000 to 150,000 tons of incremental supply that we get with that uplift.

[Matthew Blair, analyst]

Sounds good. And then, Rich, could you talk about how you're 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?

[Rich Sumner, executive]

Yes. The big thing that we are focused on is the pre-OCI deal leverage. And where we are with -- prior to the deal, we'll get at the end of this year after we pay our $300 million, we'll be just below 3x debt to adjusted EBITDA.

That's going to be as of -- if the deal were to be done on January 1, and we were to take all the debt in, it would be about $550 million to $600 million that we would need to take off the balance sheet, and that's going to be the big focus for capital allocation. as we move into this period. We don't 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 -- we're in a really good spot.

So we're going to continue to build cash, and that will be the primary focus until we move past that level.

And we'll be in a really good position to look at capital allocation thereafter and maintaining a strong balance sheet and shareholder distributions will be things we'll be looking at, obviously, dependent on where we are in the market.

But the laser focus for us right now is the $550 million to $600 million for capital allocation.

[Operator]

And your last question comes from Roger Spitz with Bank of America.

[Roger Spitz, analyst]

So your realized price increased 17% in Q3 year-over-year and the posted price moved up 31%. Can you talk more about the -- what was driving the difference? I mean, was it that you're having to send more Atlantic Basin methanol to Pacific Basin, which, as you mentioned on the call, is a lower price? Or is that part of it? Or is there something else going on?

[Rich Sumner, executive]

I think it's probably because we have a widening in our discount range. I would think that, that's -- if you're looking at reference prices to average realized prices, our reference prices would be going up higher than the average realized price.

And really, that is a function of what's happening in the Atlantic markets. We've seen increased competition by marketers, mainly through discount competition, and we've seen discounts from reference to realized increasing.

And 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.

And what we would see this year is that our realized price has the difference between our realized price and the cost curve price has grown because of that tightening in the Atlantic markets as well.

So I think you've had a bit of a double impact there where we've seen not only the Atlantic Basin driving more of the price, but also that's the regions that carry the higher reference. So that's led to a higher discount levels.

[Roger Spitz, analyst]

Got it. And the other question is, so nat gasoline's $565 million Term Loan B goes current, I guess, next week, November 14.

This is probably awkward, but since you'll be taking over OCINB's 50% ownership in the first half of 2025, I mean, will you have a representative participating in a likely refinancing of that facility or have any input into how nat gasoline should be capitalized in general, even though obviously, you're not there yet?

[Rich Sumner, executive]

Yes. We're not active and nor can we be in decision-making for that asset prior to close. So that's something that we would expect that they're 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 yes, we're not involved. and -- but we'll be watching closely in terms of ensuring that, that happens.

[Operator]

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

[Rich Sumner, executive]

All right. Well, thank you for your questions and interest in the company. We hope you'll join us in January when we update you on our fourth quarter results.

[Operator]

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